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16th June 2011 Company Announcements Platform Australian Stock Exchange Level 4 20 Bridge Street SYDNEY NSW 2000

By e-Lodgement

�COMPANY PRESENTATION MATERIAL Please find attached a copy of the presentation that will be used by Aurora Oil & Gas Limited at investor presentations being conducted this week in Sydney and Melbourne, Australia. For Aurora Oil & Gas Limited Julie Foster Company Secretary (Data referencing activities in adjacent acreage has been sourced from publically available information) Technical information contained in this report in relation to the Sugarloaf project and Sugarkane field was compiled by Aurora from information provided by the project operator and reviewed by I L Lusted, BSc (Hons), SPE, a Director of Aurora who has had more than 15 years experience in the practice of petroleum engineering. Mr Lusted consents to the inclusion in this report of the information in the form and context in which it appears.

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Aurora Oil and Gas Limited

UpdateAugust 2011

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Disclaimer

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This document has been prepared by Aurora Oil & Gas Limited (“Aurora”) in connection with providing an overview to interestedanalysts / investors and is being provided for the sole purpose of providing preliminary background financial and other information toenable recipients to review the business activities of Aurora. This presentation is thus by its nature limited in scope and is notintended to provide all available information regarding Aurora.

This presentation is not intended as and shall not constitute an offer, invitation, solicitation, or recommendation with respect to thepurchase or sale of any securities in any jurisdiction and should not be relied upon as a representation of any matter that a potentialinvestor should consider in evaluating Aurora.

Aurora and its affiliates, subsidiaries, directors, agents, officers, advisers or employees do not make any representation or warranty,express or implied, as to or endorsement of, the accuracy or completeness of any information, statements, representations orforecasts contained in this presentation, and they do not accept any liability or responsibility for any statement made in, or omittedfrom, this presentation. Aurora accepts no obligation to correct or update anything in this presentation. No responsibility or liability isaccepted and any and all responsibility and liability is expressly disclaimed by Aurora and its affiliates, subsidiaries, directors, agents,officers, advisers and employees for any errors, misstatements, misrepresentations in or omissions from this presentation.

Prospective investors should make their own independent evaluation of an investment in Aurora.

Nothing in this presentation should be construed as financial product advice, whether personal or general, for the purposes of section766B of the Corporations Act 2001 (C’th). This presentation consists purely of factual information and does not involve or imply arecommendation or a statement of opinion in respect of whether to buy, sell or hold a financial product. This presentation does nottake into account the objectives, financial situation or needs of any person, and independent personal advice should be obtained.This presentation and its contents have been made available in confidence and may not be reproduced or disclosed to third parties ormade public in any way without the express written permission of Aurora.F

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Forward‐looking Information

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Statements in this presentation which reflect management's expectations relating to, among other things, target dates, Aurora'sexpected drilling program and the ability to fund development are forward-looking statements, and can generally be identified bywords such as "will", "expects", "intends", "believes", "estimates", "anticipates” or similar expressions. In addition, any statements thatrefer 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 oncertain estimates and assumptions, that some or all of the reserves described can be profitably produced in the future. Thesestatements are not historical facts but instead represent management's expectations, estimates and projections regarding futureevents.

Although management believes the expectations reflected in such forward-looking statements are reasonable, forward-lookingstatements are based on the opinions, assumptions and estimates of management at the date the statements are made, and aresubject to a variety of risks and uncertainties and other factors that could cause actual events or results to differ materially fromthose 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; reserveestimates 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 oflicences 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 madeby management prove to be incorrect, actual results and developments are likely to differ, and may differ materially, from thoseexpressed 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, readers are cautioned not to place unduereliance on such statements.

All of the forward-looking information in this presentation is expressly qualified by these cautionary statements. Forward-lookinginformation contained herein is made as of the date of this document and Aurora 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.

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Regarding Disclosure of Reserves

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The reserves shown in this presentation are estimates only and should not be construed as exact quantities. Proved reserves are thosereserves which can be estimated with a high degree of certainty to be recoverable; probable reserves are those additional reserves whichare less certain to be recovered than proved reserves. Possible reserves are those additional reserves which are less certain to be recoveredthan probable reserves. There is a 10 percent probability that the quantities actually recovered will equal or exceed the sum of proved plusprobable plus possible reserves. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or lessthan the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received forthe reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this presentation. Estimatesof reserves may increase or decrease as a result of future operations, market conditions, or changes in regulations.

Unless otherwise indicated, all estimates of reserves in this presentation have been prepared or evaluated in accordance with the COGEHandbook effective as of 31 December 2010, and are derived from the reserves report of Netherland Sewell & Associates, Inc (“NSAI”)dated March 8, 2011 (“NSAI Report”). NSAI is a qualified independent reserves evaluator under the Canadian Securities AdministratorsNational Instrument 51-101 – standards of Disclosure for Oil and Gas Activities (“N1 51-101”).

Defined Reserves and Resource Terms• “2P reserves” means proved plus probable reserves.• “3P reserves” means proved plus probable plus possible reserves.• “bbl” means barrel.• “boe” means barrels of oil equivalent, determined using a ratio of 6 Mcf of raw natural gas to 1 bbl of condensate or crude oil, unless

otherwise stated. There are now allowances for NGLs within quoted boe figures in this presentation.• “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.

Boe may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mscf: 1bbl is based on an energy equivalency conversionmethod primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Management uses certainindustry benchmarks such as operating netback to analyse financial and operating performance.

Operating netback, as presented, represents revenue from production less royalties, state taxes, transportation and field operatingexpenses calculated on a boe basis. Management considers operating netback an important measure to evaluate its operationalperformance as it demonstrates its field level profitability relative to current commodity prices.

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Corporate Overview• High growth oil and gas producer with significant onshore acreage in the core of 

the Eagle Ford Shale, the world’s premier shale region

• Aurora (ASX:AUT) is part of the S&P/ASX200 Index and listed in Canada (TSX: AEF)

• Strong balance sheet with cash reserves and no debt

• 89% of current production and over 90% of forecast revenue is from high value liquids

• Fully funded drilling program for 2011– 50 wells drilled, 45 on production, a further 5 drilling and 25 additional new wells 

planned by year end– Conversion of majority 3P to 2P reserves within the current year– Current net production approx 2,820 boe per day after royalties1– Production rates set to increase to over 5,000 boe per day net by year end

• Sugarkane field offers scalable, low risk, profitable growth– Reserves and production growth within existing acreage– Potential for acquisitions of additional acreage within the Eagle Ford shale

51 as at 10 August 2011

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Corporate Summary

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Key FactsFully Paid Ordinary Shares 409,865,343

Options on issue (varied prices) 6,000,000

Executive Performance Shares 3,690,000

Fully diluted Capital 419,555,343

Cash at 30 June 2011 US$50m

Debt Nil

Board of Directors ShareholdingJon Stewart Chairman & CEO Australian 17.7 m

Graham Dowland Finance Director Australian 2.2 m

Ian Lusted Technical Director Australian 1.0 m

Fiona Harris Non Executive Australian 0.1 m

Gren Schoch Non Executive Canadian 5.2 m

William Molson Non Executive Canadian 1.3 m

Alan Watson Non Executive British 1.0 m

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History

• Successful 2009 farm‐out to Hilcorp Energy delivered a portfolio of producing wells with outstanding results

• Exciting exploration/appraisal project was transitioned to a large low risk development project during 2010

• Installation of larger efficient operator reduced project execution risk

• Current net production approx 2,820 boe per day after royalties• 2011 Hilcorp EF sale to Marathon Oil to accelerate development

• 48% increase in December 2010 3P reserves following acquisition of additional Sugarkane working interest

• Active 2011 development drilling program converting majority of 3P reserves to 2P category by year end 2011

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Successful farm‐out

Reserves expanded

Production ramping up

Exploration Discovery

• Partnered local company with regional approach to exploration• 2006 Sugarkane Eagle Ford discovery followed by initial 2 year 

land acquisition program

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Majors scrambling for Eagle Ford acreage • The Texas Eagle Ford shale is currently the most active oil and gas A&D market 

in the USA

• $13+ billion of deals since June 2010, including:– BHP acquisition of Petrohawk Energy– Marathon Oil $3.5 billion acquisition of Hilcorp Eagle Ford acreage– Royal Dutch Shell– Talisman and Statoil– CNOCC– Reliance Industries– KNOCFurther consolidation expected

• Approx. 200 rigs now operating across the trend with continued significant ramp‐up of development activities planned for the 2012

• Aurora established an early foothold and is the “pure play” mid‐cap producer in the “sweet spot” providing significant leverage to the upside potential that many are now recognising

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Eagle Ford ‐ the world’s premier shale region

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• Uniform, continuous and predictable shale across the play (200km x 80km)• Majority of Eagle Ford trend is economic but some is very economic• Major US shale players continuing to refocus their portfolios towards liquid rich shales

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Sugarkane Gas and Condensate Field Holdings

10Source: Aurora

AMI WI Gross Acres

Net Acres

Sugarloaf 15.7% 23,550 3,700

Longhorn 31.9% 28,280 9,020

Ipanema 36.4% 4,600 1,670

Excelsior 9.1% 20,180 1,840

Total 76,600 16,230

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Prime acreage position within Eagle Ford core area

• Sugarkane is entirely within the ‘sweet spot’ of the Eagle Ford Shale determined by economic well performance 

• Sugarkane is within the gas‐condensate and “volatile” (gas rich) oil windows• Very high liquids content and significantly over pressured resulting in high 

productivity and strong economics11

Eagle Ford Shale Hydrocarbon Map (20:1)

Core area of Eagle Ford

* Source Texas Railroad Commission

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High growth and valuation upside potential

• Fully funded drilling program underway (80 wells by year end).

• Huge uplift in 2P reserves being delivered via 2011 drilling program

• Optimising drilling, completion and production processes 

• Significant upside potential from tighter well spacing 

• Marathon Oil announced plan to ramp up core area development which will drive production and cash flow generation

• Leverage to oil price12

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1%

12%

14%

73%

PDP

PUD

PRB

POS

Transformational uplift in 2P reserves under way

• Confident that the majority of 31 December 2010 3P reserves of 83 mmboe will be converted to 2P category (31 December 2010 ‐ 22 mmboe) by 2011 year end.

• An uplift in 2P reserves should unlock significant further shareholder value.

Dec 2010 Reserves Dec 2011 Reserves*60 new wells

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10%

35%50%

5%

* Estimated reserve position end 2011

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Significant upside potential for reserves 

• June quarter commissioning of wet gas line has enabled the addition of NGL’s to 31 December 2010 numbers

• 10‐15% of Aurora’s current acreage is not included in the NSAI reserve calculations

• IP rates are strong and the continued outperformance of NSAI type curves should deliver higher well EUR’s and reserves growth in due course

• The current reserve report and drilling inventory is based on 80 acre spacing. Competitors in the area are now looking at development on 60 acre spacing. In other more developed shale plays 40 acre spaces are being used or tested. Commenced testing of closer well spacing.

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Operations Update

• 5 rigs drilling full time in acreage• 2 full time frac crews• 45 wells now on production, 50 in total drilled and 5 wells underway• Plan to drill 60 wells this year, taking total to 80 wells• Current net production approx 2,820 boe per day (after royalties)• Several operators in the Eagle Ford sweet spot achieving consistently good 

results – “code has been cracked”• Operators continue to refine well design, stimulation and flow control to 

further optimise results eg “HiWay Fracs” • Centralised processing facilities being installed – 3 completed, 6 by year 

end across field and 9 planned in total.

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• Highly contiguous acreage position excellent for development 

• Drilling locations currently dictated by lease expiry schedule which runs through 2014

Well locations

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• On existing drilling schedule anticipate land ‘held by production’ by mid 2012 – well ahead of requirements 

• Commenced testing tighter spacing whilst maintaining drill to hold plan

• Suggested rig count increase from 5 to 12‐14 by end 2012 

Sugarkane Well Status  ‐ July 2011

Longhorn

Sugarloaf

Ipanema

Urrutia #1H

Patino #1H

Kowalik#1RTurnbull #3H

Turnbull #2H

Turnbull#1H

Rancho #1H

Easley #1H

Weston #1H

Kenedy #1H

May #1H

Luna #1HDirect 

Assets #1H

Morgan#1H

Franke#1H

Sienkiewicz #1H

Gilley#1H

Turnbull #4H

Yosko #1H

Foster #1H

Jordan#1H

Hollman#1H

Barboza #1H

Excelsior

Chapman Pfiel #1H

Carter #1HBuehring#1H

PMT #1H

Carter Salge #1H

Davenport #1H

Best Fenner #1H

Chapman Rothe #1H

Henke A #1HHenke B #1H

HeirholzerSeewald #1H

Best Huth #1H

Kellner Jonas #1H

HeirholzerRetzloff #1H

Esse Smith A #1H

Turnbull #6H

Yosko Borgfield #1H

BryschJonas#1H

Turnbull #5H

Pfiefer #1H

RippsteinMikkelson #1H

Chapman Thompson #1H

Kellner McMahon #1H

Hullub #1H

Esse Smith B #1H

Chapman Schroeder #1H

DeAtleyMay  B #1HDeAtleyMay  A #1H

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Production mid August 2011

Production data at 10 August 2011 Boepd1 Average mmscfpd2

Average bopd2

Gross Production from acreage in which Aurora participates 23,000 29.98 18,010

Notional gross Aurora production without farmin cost recovery  4,210 5.81 3.242

Gross Aurora production (after farmin cost recovery & pre Royalties) 3,814 5.04 2,975

AUT net production (after royalty and cost recovery) 2,822 3.73 2,202

Estimated Y/E Aurora net production (post royalties) 5,000

NSAI estimated Aurora peak net production 2019 (pre royalties) 29,000

1. BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 mscf:1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead

2. These figures have been estimated from the raw gas and oil produced. A 20% shrinkage is assumed for the gas and a yield of 80 bbls/mmscf for the NGLs. The gas volumes provided are post shrinkage and the bopd values are including NGLs.

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• Drilling schedule shifting to higher WI % wells having focussed in Excelsior during last 4 months (9.1% WI)

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Sales infrastructure

• Existing– Pipeline has capacity for 20,000 bpd of oil and condensate, present Flint 

Hills offtake contract is for 6,000 bopd, balance trucked to two destinations. 

– 50,000 mscfpd wet gas take away capacity contracted or underway enabling stripping of NGLs

• Immediate future– Additional 30,000 mscfpd wet gas contract – Q4 2011– New oil pipeline through Excelsior and Longhorn, additional 20,000 bopd

capacity – Q1 2012• Future regional development plans

Expected by mid 2012– Liquids – over 600 mbopd additional capacity– Gas – over 500 mmscfpd additional capacity

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Drilling program on schedule

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0

10

20

30

40

50

60

70

80

90

2010 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

No.

of W

ells

Well Status (Plan vs Actuals)

Drilling (Actual) Awaiting Fracture (Actual) Producing (Actual) 2011 Planned Drilling

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Production growth ahead of target

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20,0

75

21,2

10 26,0

85

37,4

64

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61,1

64

75,1

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10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

Cum

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Mon

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oe)

2011

Aurora Monthly Net Production (BOE)

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Production increases generating profit growth

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Financial

3 months ended

30 June 2011

US$‘000 

3 months ended

31 March 2011

US$’000 Increase %

Production revenue 17,416 6,721 159%

Funds from operations 10,006 3,569 180%

Net earnings after tax 12,518  3,683 240%

Net earnings ($/boe) 55.05 38.90 42%

Net Capex 26,005 11,454 127%

Operating

Production – pre royalties boe/d 2,499 1,052 138%

Prod. Rev (Ave product prices) $/boe 76.57 70.99 8%

Royalties                                         $/boe 20.98 18.81 12%

Operating expenses                     $/boe 5.59 4.70 19%

Operating netback                        $/boe 50.00 47.48 5%

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Accelerated drilling to have significant impact

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Operating

2011

Estimated

2012

Base Case

2012

Accelerated

Variation

2011 ‐2012*

Number of wells to be drilled 60 99 115 92%

Y/E Production – pre royalties boe/d 6,700 12,800 15,100 125%

Annual production                        boe 800,000 2,700,000 3,100,000 288%

Net Capex $110 $170m $210m 91%

Financial

Production revenue – post royalties $40m $180m $205m 412%

Run rate revenue y/e – post royalties $90m $240m $285m 217%

Minimum debt facility drawdown Nil $100m $125m N/A

• Base case development plan generates a minimum 2012 debt facility requirement of approx. $100m. An accelerated program increases this to approx. $125m. Management intends to put in place a larger facility to cover further acceleration or other sensitivity variations.

• The acceleration of development defers cashflow breakeven to 2013 but has a material impact on go forward revenue and earnings.

* 2011 estimated to Accelerated

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Key data

Gross participating acres 76,600

Net Acres 16,230

2P / 3P Reserves (mmboe) 22 / 831,5

Enterprise Value (US$mm) $1,1603

EV/boe Dec 2010 3P (US$mm)4 $12.34

Issued Capital – fully diluted 419 million

Note 1: NSAI Report as at 31 December 2010Note 2: Aurora calculation based on estimated drilling schedule for 2010‐2011, $8.0m well cost through that period and $90 oil and $4 gas prices. Cash flow  post royalty, opex, G & A, production & state taxes. Note 3:Calculated based on the closing price for ordinary shares on the ASX on 6 June 2011 Note 4:“EV/boe 3P” means enterprise value per barrel of oil equivalent of proven plus probable plus possible reservesNote 5:Possible Reserves are those reserves that are less certain to be recovered than probable reserves.  There is a 10% probability that the quantities actually recovered will equal or exceed the sum of the proved plus probable plus possible reserves.

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2011 Sources & Uses of Cash  US$‘000 

Opening cash  85,760

Cash at 30June 2010 50,000

Est. cash from operations (excl. Capex) 

40,2002

Capital program  111,770 

Est. year end balance 14,190 

Debt Facility to fully fund 2012development program to be in place before year end *

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Key profit drivers trending favourably

Estimated internal rate of return (IRR) per gas condensate well is 150%1 

Estimated internal rate of return (IRR) per volatile oil well is 80%1

High global oil price

Liquid rich production in over pressured environment 

Efficient develop‐ment

Excellent margins and robust cash flow generation

1 Based on current sales price and cost metrics 24

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A pure investment in the core area of the Eagle Ford

• Prime acreage position• High profits from liquids rich production• Active drilling program underway – 80 wells by year end• Accelerated development program from 2012• Ideal macro environment for US onshore oil development• Significant upside potential from:

– Reserves transition ‐ 3P reserves reclassification to 2P category– Production optimisation– Tighter well spacing

• Sharp ramp up in development accelerating production and cashflow generation

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Additional Slides

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NSAI Reserve Report Post Royalties – 31.12.10

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The estimated future net revenue values below do not necessarily represent fair market value of Aurora’s reserves

NPV figures provided are post royalties, state production and ad valorem taxes, future capital costs, operating expenses and abandonment costs, but before any income taxes.

NGL’s currently trade at approximately 50% of WTI crude prices

• At the effective date of the NSAI Report of 31.12.2011 there were 15 wells producing• As at end 1 June there are 30 wells on production and by end 2011 it is estimated that more than 70 

wells will be on production of approx 80 in total drilled• A summary of assumptions applied by NSAI is included in “Additional Slides”• The NGL/CND column is condensate only ‐ NSAI have made no allocation for NGLs in this report. 

Management estimate NGL’s would represent an additional approx 14 mmbbls and stripping from gas would, due to shrinkage, reduce gas reserves by approx 20%.

Aurora Net Reserves and NPV (post Royalty Interests) L/M Oil NGL/CND Gas BOE NPV(0) NPV(10) Reserve Category (bbls) (bbls) Mcf (bbls) USD million USD million

Proved Developed Producing 0 634,195 2,422,833 1,038,001 52.50 34.74Proved Undeveloped 271,070 5,381,291 24,101,427 9,669,266 371.74 207.52

Total Proved (1P) 271,070 6,015,486 26,524,260 10,707,266 424.23 242.25

Probable 289,535 5,903,066 31,170,818 11,387,737 415.72 199.25

Proved + Probable (2P) 560,605 11,918,552 57,695,078 22,095,003 839.95 441.51

Possible 18,392,324 22,442,489 119,780,026 60,798,151 2,375.39 942.71

Proved + Probable + Possible (3P) 18,952,929 34,361,041 177,475,104 82,893,154 3,215.34 1,384.21

Possible Reserves are those reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of the proved plus probable plus possible reserves.

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High liquids yield drives strong economics

• Liquids are significantly more valuable than gas

• Aurora wells have ranged from 60‐400bbls/mmscf condensate ratio, with average of 270+

• Majority of acreage is gas shale, which is positive for productivity, but this is a liquids play!

• 90% of forecast revenue is based on liquids sales

Incremental Value of Production from SugarkaneRich Gas Condensate Wells

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$0

$5,000

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Assumes gas price $4 mscf, condensate price $100/bbl and LPG price $50/bbl

A well produces 1 mmscf of gas, and generates $4,000 in 

revenue – if sold as rich gas then + 25% or $5,000

The gas is treated and 80 bbls of LPGs are stripped, this shrinks 

the gas by 20%. Revenue is now:‐Gas ‐ $3,200

Condensate ‐ $27,400LPG ‐ $4,000

The gas contains condensate and 274 bbls are recovered. 

Revenue is now:‐Gas ‐ $4,000Condensate ‐

$27,400

Case 1 Case 3Case 2

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Sharp ramp up in production and cash flow generation

• Net production expected to increase to 5,000 boe per day by year end

• Excellent cash flow generation based on high oil prices and high liquid content 

• Proposed ramp up of drilling will accelerate growth

• Further upside potential from:– optimised production 

processes and outperformance of wells

– tighter well spacing

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Annual and Cumulative Cash Flow including Capex (US$MM)

Annual Cash Flow Cumulative Cash Flow

29NSAI development plan assumptions at 31.12.2010

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Production forecasts

• Before proposed ramp up in development net production forecast to peak at 29,000 boe per day in 2019

• Long life and high EUR wells

• Upside potential from optimised production processes and tighter well spacing

• Excellent early performance, consistent execution of drilling plan and continued delivery of improvements0

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Single well economics

Key Assumptions

• NGL yield 80 bbl/mmscf with 20% shrinkage of dry gas• NPV10 Post State Taxes and Royalties but pre Corporate Tax. NRI 74%• Opex flat $20,000/month• NSAI high Condensate yield Gas type curve from NSAI Report• *Realised Oil price to give breakeven Pre Tax NPV10 keeping Gas price at $4.0/mmbtu and NGL price at 50% of Oil Price

NSAI Gas/Condensate Type Curve

Gross EUR 748 mboe

CGR 274 bbl/mmscf

NPV10 (Pre Corporate Tax) $15.8 million

IRR (Pre Corporate Tax) 150%

Realised Oil / Condensate Price $100 bbl

Realised Gas Price $4 mscf

Realised NGL Price $50 bbl

Payout from 1st Production 6  months

Drill Complete & Tie in cost $6.80 millionBreakeven Oil/Condensate Price* $32 bbl

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0 12 24 36 48 60 72 84 96 108 120 132 144 156 168 180 192 204 216 228 240

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Sugarkane Liquids Rich Well Type EconomicsNSAI Type Curve

Production (boe/d) Pre Tax Cumulative Cashflow  (US$Million)

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Initial production results

• Improvements in decline curves have a significant impact on EUR’s.

• Decline after 10 months ~ 58%, additional 27,000 boe (14%) produced in 10 months compared to NSAI type curve.  

• These figures do not yet include the effect of NGL stripping32

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Core section from Luna #1H Well

• Example of Eagle Ford Shale• Shows variation in lithologybetween Calcareous sediments and Organic shales

• Shows horizontal deposition and some lamination

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Sugarkane field drilling & stimulation

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The additives enable the water‐sand mixture to transport the sand deep into the fracture and then change its properties to allow thewater to be removed while the sand remains, holding the fracture open. The newly created fissures are propped open by the sand.This allows the hydrocarbons to flow into the wellbore and be collected at the surface.

Fluids (typically 99% water & sand+ 1% additives) are pumped undergreat pressure to generatemillimetre‐thick fissures orfractures in the target formation.

Well design has moved towards more stages and significantly larger fracture stimulations with more propantClosest potable aquifer is at approximately 3,000’ true vertical depth or approximately 8,500 – 9,000 shallower than the well horizontal sectionAquifers are secured behind casing prior to drilling of horizontal sections

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