2011 AGM PRESENTATION 24th Annual General Meeting of Shareholders – 29 November 2011

ASX codes OBL , OBLOA & OBLOB

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Disclaimer

This presentation is for the sole purpose of preliminary background information to enable recipients to review the business activities of Oil Basins Limited ABN 56 006 024 764 (ASX code OBL). The material provided to you does not constitute an invitation, solicitation, recommendation or an offer to purchase or subscribe for securities. Copies of Company announcements including this presentation may be downloaded from www.oilbasins.com.au or general enquires may be made by telephone the Company (613) 9692 7222.

Oil Basins Limited (ABN 56 006 024 764) and its subsidiaries are not the legal entity / corporation of the same name registered in Bermuda ("the Bermuda Corporation") and does not dispense the BHP Billiton Petroleum-ExxonMobil Weeks Royalty pertaining to oil & gas production from Bass Strait. None of the Company or its Directors or officers are associated with the Bermuda Corporation and the Company has no interest in any such royalty.

The information in this document will be subject to completion, verification and amendment, and should not be relied upon as a complete and accurate representation of any matters that a potential investor should consider in evaluating Oil Basins Limited. Assumed in-the ground values of unrisked prospective potential resources assets as stated in text (ignoring finding and development costs). No assumption of either commercial success or development is either implied with their adoption by either the Company and its directors and representatives in the application of these indicative values to its assets.

Prospective Resources are those quantities of petroleum which are estimated, on a given date, to be potentially recoverable from undiscovered accumulations. Recipients should not infer that because “prospective resources” are referred to that oil and gas necessarily exist within the prospects and CSG / USG tenements. An equally valid outcome in relation to each of the Company’s prospects is that no oil or gas will be discovered.

The technical information quoted has been complied and / or assessed by Company Director Mr Neil Doyle who is a professional engineer (BEng, MEngSc - Geomechanics) with over 29 years standing and has been a full and continuous member of the US Petroleum Engineers since 1981 and by Mr Geoff Geary who is a professional geologist (Bachelor Science – Geology) with over 32 years standing and who is also a Member of Petroleum Exploration Society of Australia. Both Mr Doyle and Mr Geary have consented to the inclusion in this announcement of the matters based on the information in the form and context in which they originally appear – investors should at all times refer to appropriate ASX Releases.

Specifically the Gippsland Basin technical information is sourced from previous ASX Releases by Permit Operator Bass Strait Oil Company Limited (ASX code BAS). The technical contingent resources data relating to the Carnarvon Basin R3 is presently being independently assessed by RPS Energy – released 4 April 2011. The petroleum engineering technical data relating to the Carnarvon Basin R3/R1 was independently assessed by DU-EL Drilling Services (with principal conclusions of their Cyrano Development Scoping Study (refer to ASX Release 26 October 2011). Specifically the Canning Basin technical information relating to CSG & USG quoted has been complied and / or assessed by an Independent Expert Report by Mapcourt Pty Ltd released to the ASX on 8 July 2010. The Backreef Area technical assessment by an Independent Expert Report by RPS Energy Pty Ltd released to the ASX dated 23 November 2011.

Investment in Oil Basins Limited are regarded as speculative and this presentation includes certain forward looking statements that have been based on current expectations, about future acts, events and circumstances. These forward-looking statements are, however, subject to risks, uncertainties and assumptions that could cause those acts, events and circumstances to differ materially from the expectations described in such forward looking statements. These factors include, among other things, commercial and other risks associated with estimation of potential hydrocarbon resources, the meeting of objectives and other investment considerations, as well as other matters not yet known to the Company or not currently considered material by the Company.

Oil Basins Limited and its directors and representatives accepts no responsibility to update any person regarding any error or omission or change in the information in this presentation or any other information made available to a person or any obligation to furnish the person with further information and its Directors do not endorse or take any responsibility for investments made.

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• 2006 listed

• 2010 operator

• 2010 drilled first exploration well

• Currently operates 3 assets:

− Oil: offshore Carnarvon

− Oil, CSG/USG (designated

Operator), & potential LNG:

onshore Canning Basin

• Oil & Gas: 2 non-operated

interests offshore Gippsland Basin

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Oil Basins Limited

Objective: establish strategic production hubs near known oil & gas in mature basins

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Operated Assets:

Oil – 100% R3 (Cyrano Oil Field)

– 100% Rights Backreef Area (Shallow Backreef-1 Oil Show)

CSG – 50% 5/07-8EP (CSG Operator)

USG – 100% Rights Backreef Area (Backreef-1 Deepening)

– 50% 5/07-8EP (USG Operator)

LNG – 5/07-8EP has potential for significant feedstock to James Price Point

– OBL already has secured 30% Rights to Future Canning LNG Plant

Non-Operated Assets:

Oil & Gas – 12.5% Rights Vic/P41- of which 5% being transferred to OBL direct

– 17% Vic/P66

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The Assets F

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• Listed purely as explorer now developer with two active projects.

• Committed to building strategic portfolio of oil & gas assets both onshore & offshore (close to

hubs / markets) and that deliver shareholder value.

• OBL has been almost surgical in the focus of building its portfolio – Company already

owns 100% of an offshore oil development asset (potential 2 to 4 MMbbls 2C resources

via an EWT) and 100% rights of a future onshore Oil Play (mapped potential recoverable

resources – expectation circa 20.6MMbbls – 8 drill-ready Leads).

• Established history of & committed to being a low cost operator and explorer.

• Maximising new technologies & engineering techniques to minimise risk & maximise

development opportunities.

• Management – highly experienced with proven skill sets to deliver.

• Company has established a portfolio of 4 Diverse Projects, all potential “company

makers, all in established mature basins “all good addresses near known oil” and all with

potential to significantly re-rate the Company in the near-term.

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What sets Oil Basins apart? F

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Asset Update

R3/R1 Cyrano Oil Field – OBL 100%

Backreef Area – 100% Rights

USG / CSG – OBL 50% (upon Award)

Eastern Gippsland Gas – OBL 12.5% Rights

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Oil Projects – Carnarvon Basin 100% Retention Lease R3/R1 (incorporating the Cyrano Oil Field)

Oil Basins initially acquired

25% in 2008 and the

remaining 75% in October

2010

OBL awarded interest in

April 2011 and successfully

renewed it as R3 /R1 in

October 2011

5 year retention lease

Field contains10m net

heavy 22.8°API, low

Sulphur oil, 21m gas cap;

crude oil viscosity 3.95cp

Water depth only 15m to

17m & TD modest 600m

Nearby to Airlie Island –

Jetty & 2 x 150,000 storage

tanks, gas lift and gas /

water separation facilities

Airlie Island Oil Hub

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Oil Projects – Carnarvon Basin 100% Retention Lease R3 (Cyrano Oil Field)

Oil Basins now owns 100%

New re-mapping & risked OIP Assessment

P90=5.42 MMbbls

P50=10.13 MMbbls

P10=18.19 MMbbls

Risked 2C is conservatively assessed at

1.5MMbbls

Cyrano -1, 2 (2002/03) is on tend to a similar

undeveloped Nasutus Oil Field discovery (1999)

New mapping reveals scope for significant

extension of R5 Nasutus Oil Field into R3

Oil field defined by 3D seismic >$12m spent (3

wells drilled in total – 5 if include the R5 wells)

Low-cost entry & hub-potential or Unitisation

Proximity to nearby infrastructure – Airlie Island

Field development, either standalone or unitised,

will require electric submerged pumping (ESP)

and horizontal drilling technologies

New OBL Assessment – March 2011

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Completed the acquisition of 75% interest in R3 – Ministerial assent 8 April 2011.

Contingent resources assessment by RPS completed in April 2011.

Sought extension for R3 renewal lodgement to 30 June 2011.

Lodged renewal 9 June based upon a USD$140m unmanned development tied-back to Airlie

Island (previous operators view).

Indicated in early September that renewal would be granted – commissioned DU-EL to

undertake a scoping study covering development options and technologies.

11 October Ministerial assent granted – OBL moves to operator & 100% owner R3/R1

Draft report released to ASX on 26 October – changes development options to a feasibility of

a rapid EWT using mostly re-deployable equipment – costs below USD$30m.

Future reservoir simulation studies – potential to enhance resources per EWT using

sophisticated pumps.

Presented findings to DMP on 23 November 2011.

Farmout ready.

R3/R1 – Work Completed 2011

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Cyrano Oil Field – Development Study EWT – Basic Concept (Artificial Lift Only)

Rig Type

Jack Up / Jack Up Barge

Production Unit

MOPU / Monopod

Well Design

One well – 15m to 17m water depth Horizontal / Deviated (1000m)

Development Concept

The first production well within the Cyrano Oil field has been identified as a horizontal well to optimise the recovery of the heavy oil in place. Using an artificial lift concept such as Electrical Submersible Progressing Cavity Pumps (ESPCPs) can aid in maintaining production rates due to low reservoir pressures.

The Cyrano Oil Field comprises of an oil column with 23°API, high viscosity, low pressures and low permeability reservoir characteristics. This to date has caused uneconomical scenarios for developing this area.

For a well with these reservoir characteristics and conditions the concept of artificial lift by using a ESPCP for aiding and stimulating the production of the oil in place is the minimum requirement for developing this field.

Drilling

In order to drill this horizontal well a Jack Up Drilling Rig or Jack Up Barge with a modular land drilling unit can be used. The advantages of using a Jack Up Barge with a modular land drilling unit are purely financial. The limiting factor of utilising the barge option would be availability and mobilisation. These two factors alone have potential to eliminate the use of a Jack Up Barge with a modular land rig to drill the well.

• A Jack Up Drilling Rig was selected in the Basic Concept.

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Cyrano Oil Field – Development Study EWT Base Concept (Artificial Lift Only)

Completions

With the well conditions and reservoir characteristic this concept will utilise an artificial lift technique for

recovering the Oil in Place. Schlumberger, Baker Hughes and Weatherford have high quality

equipment specifically designed for Cyrano’s well conditions.

The Basic Concept development required for the Cyrano first phase development plan is a

horizontal well with a pump (ESPCP) in aid in extracting the heavy oil.

Production and Offloading

Once well testing is complete, producing and offloading is the next phase of the operation. Due to the

field being in only 15m of water, it poses a challenge. There are two feasible alternatives identified in

overcoming this challenge.

The First Option is to divert all produced returns via standard methods to a monopod or Mobile

Offshore Production Unit (MOPU) which has been installed within the Cyrano field. From this phase the

produced oil can be directed to an offloading point to a FPSO or FSO.

In order to utilise option one, if more than one well was drilled, a X-mas Tree would be required to be

tied into a subsea manifold and then pumped through a flowline to the Monopod or MOPU.

The Second Option is to pipeline directly from the subsea manifold which joins multiple production

wells to the Airlie Island Production Facility (or alternatively to an onshore storage and shipping facility

at Onslow Harbour. These pipeline options may still pose the same shipping hazard as above, and

would probably require a trench.

A Jack Up Storage Barge (capacity 60,000 - 100,000 bbls) was selected in the Basic Concept.

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Cyrano Oil Field – Development Study EWT – Basic Concept (Artificial Lift Only)

After consideration of all the available options, based on the information at hand and the RPS reservoir

report. DU-EL Drilling Services recommended best option is a standalone low cost development

initially in the form of an Extended Well Test (EWT) or series of EWT’s using functional removable and

redeployable equipment.

The Airlie Island option is not economical, mainly due to the likely disproportionally high tolling cost.

The most cost effective development would be using a Jack Up Drilling Rig or Barge with a modular rig

to drill the wells. If a 1000m horizontal section of the well is required, it is possibly going to make the

option of a Jack Up Barge more limiting due to the lifting capability of the crane and the size of the rig

required to drill the extended reach drilling (ERD) phase. This should not be ruled out until a full

production profile and simulation of the field is completed.

For the purpose of conclusion the RPS recommendation of the ERD aspects of the well have to be

taken into account. This study is concluding that the most feasible option would be to start with a two

horizontal ERD wells into the Mardie Greensand formation, as this appears to be the best producing

sands for siting the ERD’s (& majority of OIP resources are located in the Mardie). Once the wells

have been drilled and completed with ESPCP pumps, as per Basic Concept to aid in production rates

of a low pressure reservoir. The Basic Concept development required for the Cyrano first phase

development plan is a horizontal well with a pump (ESPCP) in aid in extracting the heavy oil.

The wells should then be flowed over a period of time to assess the feasibility of the development

design and gain further information about the field. For this phase of the development it is

recommended a smaller Barge be mobilised in order to reduce the OPEX. Bringing in a Jack-up

storage barge with the capacity of 60,000 barrels would in addition reduce the costs of an FSO on site

full time.

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Jack-Up Drilling

& EWT Facility

Jack-Up Oil Storage Barge

FSO & Shuttle Tanker

Downhole ESPCP (shown blow-up) Pumps

Cyrano Oil Field – Development Study DU-EL Scoping Study : EWT Base Concept (Artificial Lift Only)

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Cyrano Oil Field – Development Study DU-EL Scoping Study : Phase #2 – Multiple EWTs (Leap-frogging along Field)

Jack-Up Drilling &

Production Testing

Unit

Jack-Up

Storage Unit

EWT #1

EWT #2

Lateral #1

Lateral #2

Lateral #2

Lateral #1

Jack-Up Storage Unit

re-deployed for

EWT #3

Jack-Up Drilling &

Production Testing

Unit, re-deployed for

EWT #2

Target

795,000 bbls

Target

795,000 bbls

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Full Field Development Concepts showing different development

strategies (and possible subsea producer and/or injector wells)

Subsea Wells

Option #2

JU or MOPU Wells

Option #1

Cyrano Oil Field – Development Study DU-EL Scoping Study : Phase #3 – Full Field Development

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Asset Update

R3/R1 Cyrano Oil Field – OBL 100%

Backreef Area – 100% Rights

USG / CSG – OBL 50% (upon Award)

Eastern Gippsland Gas – OBL 12.5% Rights

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Oil Projects – Canning Basin Assets

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Backreef-1 Oil Show

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interpretation Backreef Area

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• OBL drilled the Backreef-1 exploration well in L6 portion of the Backreef Area in October 2010.

• According to Weatherford’s proprietary Petrolog CPX, Backreef-1 encountered a gross reservoir interval

of some 48.9m was intersected and a net oil pay of some 39.2m was intersected

• As no reservoir samples and satisfactory pressure tests could be obtained and recognising that

Backreef-1 may have intersected a hitherto unknown New Oil Play, OBL decided (with DMP’s

concurrence) to case and suspend Backreef-1.

• The well was cased and suspended at 1155m PBTD and the site has been restored pending further

evaluation of results and a the proposed cased hole test.

• OBL’s evaluation of the result included

• > petrophysical assessment of Backreef-1,

• > collection of vintage seismic data and interpretation of the New Oil Play

• > seismic inputs for PSDM (derived from PSTM) with OBL interpretation via modern

• Schlumberger PetrelTM seismic interpretation software

• Weatherford conclude that gross pay was circa 49m, net pay thickness was circa 39m and best

producing zone was circa 3.9m thick.

OBL New Regional Mapping Interpretation The first application of modern techniques to Backreef Area

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OBL New Regional Mapping Interpretation Backreef Area appears to be highly prospective

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Backreef-1 Cased & Suspended (site visit 13 Nov 2011)

\

Backreef-1 well site

Backreef-1 well site & Company’s water bore

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Shallow Drilling Rig (possible use in Backreef Area 2012)

Lead A - East Blina well site (site visit 13 Nov 2011)

OBL New Regional Mapping Interpretation Backreef Area appears to be highly prospective

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OBL Geological Interpretation Line BV93-17 Cross-section of southern portion of potential New Oil Play

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The possible extension of the Backreef Prospect updip to the East is postulated to extend

some 10km plus to the North North West (NNW) – providing Subcrop seal can be established

Potential OWC

@ 963m RT

Possible Channel

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Backreef Area – New Oil Play RPS Scope of new work - an independent “Peer Review”.

RPS Energy (RPS) was engaged by OBL in October 2011 to perform a ‘peer review’ of Backreef-1 and the

New Oil Play and to delineate potential prospective resources in accordance with strict PRMS guidelines.

> Petrophysical analysis of Backreef-1

> Independent interpretation of prospect mapping also using Schlumberger PetrelTM

> Definition of possible new leads within the possible New Oil Play Area

> Recommendations for future work

RPS re-evaluated the wireline logs – leading to some ambiguity with RPS and Weatherford results

showing considerable differences

• Evaluated logs and reservoir properties for Backreef-1 – independently verified.

• Well developed dolomite section encountered Net pay difficult to determine because of log response and

no fluid samples (39m previously estimated Weatherford) and minimum of ~12 metres (RPS Energy).

• RPS’s evaluation of interval 917-994m MD was found to contain 12.1m net pay.

• Major accumulation (6.8m) centred between 956.7m to 963.5m MD in the Yellow Drum – this compares

with a 9m producible zone within the Yellow Drum in the Blina Field (some 6km to the west and down dip

of Backreef-1). 22

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Backreef Area – New Oil Play Well correlations – Blina-1 (1981) and updip Backreef-1 (2010)

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Backreef Area – New Oil Play RPS interpreted & mapped 8 Leads – 7 (Yellow Drum Fm) and 1 (Nullara Fm)

Production

Licence L6

Permit

EP129R3

Buru Energy

L6

Blina Oil

Field

Non-OBL

Permits

RPS considered the seismic data quality to be generally sufficient to delineate the

two primary reservoir intervals (Yellow Drum Formation and Nullara Limestone).

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Backreef Area – New Oil Play 7 Leads in the Yellow Drum – 6 Leads within L6 and 1 within EP129R3

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Backreef Area – New Oil Play New Lead in Nullara Fm situated within L6

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Lead Target Undiscovered OIP

MMbbls

P90 P50 P10 Mean GPoS

East Blina (Lead A) Yellow Drum 1.00 1.86 3.08 1.97 8

Backreef Yellow Drum 0.63 1.17 1.94 1.24 12

B Yellow Drum 1.18 2.18 3.61 2.31 8

C Yellow Drum 0.81 1.49 2.47 1.58 6

D Yellow Drum 3.44 6.37 10.6 6.75 8

E Yellow Drum 11.5 21.3 35.4 22.6 4

F Yellow Drum 16.7 30.9 51.2 32.7 4

G Nullara 3.86 8.93 16.8 9.79 6

Probabilistic Total 45.6 72.8 117.0 77.7

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Eight (8) Leads have been independently derived by RPS within the southern and south-eastern

portions of the Company’s Backreef Area – GPoS will likley improve upon Backreef-1 testing success.

RPS has concluded in accordance with strict PRMS guidelines that the Backreef Area could host a

significant aggregated undiscovered potential Oil in Place (OIP) volume of between 45.6 to 117

MMbbls with an expectation of 77.7 MMbbls and a mean estimate of 20.6 MMbbls Prospective

Resources

Backreef Area – New Leads Inventory F

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Lead Target Prospective Resources

MMbbls

Low

Estimate

Best

Estimate

High

Estimate

Mean

estimate

East Blina (Lead

A)

Yellow Drum 0.18 0.47 0.96 0.49

Backreef Yellow Drum 0.11 0.29 0.60 0.31

B Yellow Drum 0.21 0.55 1.12 0.58

C Yellow Drum 0.15 0.37 0.77 0.40

D Yellow Drum 0.62 1.59 3.29 1.69

E Yellow Drum 2.07 5.33 11.0 5.65

F Yellow Drum 3.01 7.73 15.9 8.18

G Nullara 0.70 2.23 5.21 2.45

Probabilistic

Total

8.85 17.7 35.7 20.6

Four (4) Leads have potential to be larger than the Blina Oil Field which has an initial OIP of circa

5.7 MMbbls (with circa 1.9 MMbbls produced since 1981) and is the largest field so far discovered

within this region of the Fitzroy Trough).

Two newly mapped stratigraphic Leads, notably Lead E and Lead F, are potentially large with

indicative areas greater than 4 km2. RPS has delineating a gross recoverable Prospective

Resource greater than 5 MMbbls for these two Leads.

Backreef Area – New Leads Inventory F

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Lead A – East Blina Yellow Drum

Backreef Lead Yellow Drum

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Backreef Area – New Leads F

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Backreef Area – New Leads (continued)

Lead B Yellow Drum

Lead C Yellow Drum

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Lead D Yellow Drum

Lead E Yellow Drum

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Backreef Area – New Leads (continued) F

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Lead F Yellow Drum

Lead G Nullara Limestone

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Backreef Area – New Leads (continued) F

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Completed the data collection in Australia and Canada and re-processing of 16 vintage 2D

seismic – was complete end of July 2011

Data quality again was exceptional for data that was 30 to 40 years old (albeit limited)

Seismic inputs were sufficient for PSDM (derived from PSTM) with OBL interpretation via

modern Schlumberger PetrelTM seismic interpretation software was complete end-August

OBL interpreted a number of potential Leads for follow-up exploration drilling and tried to

expedite stakeholder clearances for a production test of Backreef-1 (assuming a farmout

could also be finalised) – unfortunately neither could be obtained by the end of October.

RPS conducted an independent peer review of the work undertaken and determined that OBL

work was on vintage 2D was adequate to delineate some 8 new Leads – supporting the

Company’s belief that the Backreef Area is a good address for oil exploration.

RPS study was complete 22 November and they have determined that the Backreef Area

could host a significant undiscovered potential Oil in Place (OIP) volume of between 45.6 to

117 MMbbls with an expectation of 77.7 MMbbls and a mean estimate of 20.6 MMbbls

prospective recoverable resources.

Backreef Area – Work Completed 2011

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Asset Update

R3/R1 Cyrano Oil Field – OBL 100%

Backreef Area – 100% Rights

USG / CSG – OBL 50% (upon Award)

Eastern Gippsland Gas – OBL 12.5% Rights

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• Independent expert coal measures

study commissioned & completed

assessed historic data

• 2 coal depocentres delineated

considered highly suitable for CSG –

thick & deep coal

• 1 petroleum well, Booran-1 (only 3km

from Derby), max coal thickness 20m

> previous perception of 4m across

entire coal province

• Historic coal exploration concentrated

on shallow coal near known out-crop

of Permian Lightjack Formation (eg

Rio Tinto 2004 & Rey Resources

2009/2010 to South & South East &

Curran 2010 to East

CSG Projects – Canning Basin Permit 5/07-8EP appears to be “sweet spot” for CSG – OBL 50% Designated Operator

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Permit 5/07-8EP appears to be “sweet spot” – uniquely favourable for CSG exploration

Company’s future “hollow log” – waiting upon NT Mediation to be finalised with the KLC

Extent of northern Coal Measures – uplifted 67 Mile Fault

Very High Ash Content >45% south of Fenton Fault

Permit is large at 5,087 km2

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CSG Projects – Canning Basin Permian Lighjack coal extensive & favourable for CSG

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Nearby Permian Lightjack coal cores

Rio Tinto Exploration (2004)

• Study shows coal occurs at least 300 m depth & 3 m thick over entire Permit 5/07-8 EP

– these settings are considered minimum for analogous CSG production Surat Basin

Permian Thermal Coals.

• Canning Basin Permian coals more deeply buried than presently & suggested high average

vitronite values measured for these coals indicate that gas saturation maybe higher than

occurring in Surat Basin Permian coals.

i. High Estimate 118.2 Billion tonnes

ii. Best Estimate 80.2 Billion tonnes

iii. Low Estimate 50.6 Billion tonnes

Above estimated Lightjack Formation

‘in-situ coal volumes’ - substantial

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GROSS GROSS GROSS

LOW ESTIMATE BEST ESTIMATE HIGH ESTIMATE

(TCF) (TCF) (TCF)

PERMIT EP5/07-8EP 4.1 6.5 9.6

BACKREEF AREA 0.2 0.3 0.4

4.3 6.8 10.0

Possible Recoverable Gross CSG 2P Resources (TCF)

NET NET NET

LOW ESTIMATE BEST ESTIMATE HIGH ESTIMATE

(TCF) (TCF) (TCF)

50% - PERMIT EP5/07-8EP 2.05 3.25 4.80

100% - BACKREEF AREA 0.20 0.30 0.40

2.25 3.55 5.20

Possible Recoverable Net CSG 2P Resources (TCF)

CSG Projects – Canning Basin Ind. Exp. Report delineated substantial CSG prospectivity

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Company’s net prospective risked 2P resources assessed at between 2.2 Tcf to 5.2 Tcf

As coal occurs at favourable depths for CSG – exploring for CSG may “de-risk Canning”

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USG Projects – Canning Basin Ind. Exp. Report concluded both Permits are highly attractive for USG

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The un-risked USG prospectivity assessment based upon only ‘one’ of ‘six’ evident shales

• Potential new energy source

• Independent Expert Report

delineated USG prospective potential

of both exploration areas

• 6 formation units ALL occurring

within 5/07-8EP are ALL relevant to

USG – evidence of high TOC’s

approx 10%

• USG potential of Kimberley Downs

Embayment feature requires deeper exploration to > 2500m with cores cut

& analysed from circa 1700m

• Potential to re-enter and deepen

Backreef-1, preliminary results

encouraging for USG

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USG Projects – Canning Basin Ind.Expert Report has delineated substantial USG prospectivity

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Early stage exploration but the gross potential is big

Best Estimate – Gross GIP 264 Tcf in each shale formation.

The shallow overlying CSG potential has the ability to potentially de-risk USG exploration.

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OBL Canning portfolio USG comparisons

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The un-risked USG prospectivity

assessment based upon only ‘one’ of

‘six ’ evident shales

Backreef Area circa net 10 to 21TCF

GIP potential

Exploration Permit 5/07-8EP circa net

51 to 253 TCF GIP potential

Recently New Standard Energy (NSE)

farmed out to ConocoPhillips

Transaction was for circa USD$108M

or circa USD$1.1m per point

NSE’s assessed Goldwyer Shale Play

(circa 120km to south of Permit 5/07-

8EP) – based upon 40 to 460 Tcf GIP

potential

Permit 5/07-8EP has both shallow oil

and CSG prospectivity & is closer to

infrastructure & James Price Point.

Approximate location of

NSE Goldwyer Shale Play

OBL interests

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Blanket marine shale of Ordovician age

Black to dark grey shales and claystones with inter-bedded silty

intervals

4 distinct shale units with total thickness of between 200m and 500m

Depths to top of the Goldwyer range from 1,000m to 3,000m

Appropriate maturity, TOC levels and free gas from limited database

Unrisked GIP 40 to 480 Tcf

Well positioned in the prospective gas window

Infrastructure will need to develop

NSE transaction with ConocoPhillips

Farmin value USD$108M or USD$1.1M per % point

NSE net free carry worth circa USD$27M

Permit 5/07-8 EP 5,062 km2 – 1.23 million acres

6 very thick distinct intervals of thermally mature organic rich marine

shales of total thickness are present 50m to 500m

Permian Noonkanbah Formation with approximately 400m of net

shale with TOCs of up to 9.37%

Permian Winifred Formation average of 325m of shale in the

combined Grant Group with an average TOC value less than 2%

Carboniferous Anderson Formation is a good oil or wet gas

potential source rock which has an average net shale thickness of

105m and has TOC values as high as 7.25%

Carboniferous Laurel Formation excellent oil source rocks with an

average of 155m of net shale and has TOC values of up to 7.25%.

Devonian Gogo Formation has recorded TOCs of up to 8%, it

contains oil prone macerals and is thought to be the major contributor

to the Blina oil accumulation – expected to be circa 45 to 50m thick.

Ordovician Goldwyer Formation The unit attains a maximum

thickness in the order 500 m in tenements held by NSE to the south of

Oil Basins‟ acreage. The TOC values rage from 3.9-62.2%, hence

they are extremely rich source rocks and are known to be mature. The

average TOC value on the nearby Barbwire Terrace is approximately

6%. It is an exploration target to the south of Oil Basins‟ acreage.

Independent Expert estimates a large potential gas resource

within Permit 5/07-8 EP with an approximate range of gross USG

unrisked gas initial in place potential GIP from 106 – 527 Tcf

Infrastructure – ports, roads, airports, towns & facilities nearby.

Specific Permit 5/07-8EP USG comparisons

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NSE – Goldwyer Shale Play Permit 5/07-8EP Comparison

New USG Play potential ‘Company Maker’

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• Potentially significant New Oil Play in

Backreef Area

• Should future appraisal drilling and/or oil

production tests prove successful – oil could

self-fund the future CSG & USG Projects

• Apart from ‘domgas’ supply – potential for

large gas to liquid “GtL” Applications

(gasoline, diesel, methanol or wax); Gas to

Ammonia / Urea & related Petrochemicals

• Oil Basins’ new vision as operator designate

CSG Permit 5/07-8EP for range of

development options for potentially large

volumes of gas attractively located close to

established regional infrastructure nearby

Derby – Export CSG to LNG / USG to LNG

Summary – OBL offers best exposure to Canning Backreef-1 has reduced risk for New Oil Play, CSG/USG has potential to de-risk Canning

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LNG Limited’s Plant technology

ideally suited to moderate gas

production build-up CSG / USG

to LNG Projects – OBL has SAA

to attain upto 30% of Project

OBL’s has a non-exclusive Strategic Alliance Agreement (SAA) but if USG / CSG is

successful - can supply James Price Point LNG Hub Feedstock or Gas to Liquids

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Asset Update

R3/R1 Cyrano Oil Field – OBL 100%

Backreef Area – 100% Rights

USG / CSG – OBL 50% (upon Award)

Eastern Gippsland Gas – OBL 12.5% Rights

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Non-Operated Assets – Oil & NGL Projects Gippsland Basin - Rights to 12.5% Vic / P41 & 17% Vic / P66

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Operator signed a Joint Study Agreement with CNOOC on 2 August 2011

OBL protected its investment and was recently assigned 5% of Vic/P41 for nil$

These “gassy permits” will likely realise value with the advent of CO2 Tax on 1 July 2012

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Gippsland Basin – 12.5% Rights Vic/P41

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Gross P10 Vic/P41 upside 713 MMbbls Oil & 3.1 TCF Gas Oil Basins has Rights to circa net 96 MMBoe P50 prospective recoverable resources

OBL’s Farmin has been renewed in 2011 and the promote is now below 1.5 to 1 – creating

potential significant strategic upside in how OBL exercises these rights.

3D Defined Drill- Comments / Target Probability Gross Stochastic Net Oil Basins Share

Ready Prospect Reservoir of Prospective Res. Stochastic Prospective Res.

Defined by AVO Success (Recoverable) (Recoverable)

P50 P50 P50

OIL GAS OIL GAS Oil & Gas

MMbbls Bcf MMbbls Bcf MMBoe6

Kipling Within Vic/P41 only Gas 22% 124 620 15.5 77.5 28.4

Oil 15%

Benchley Golden Beach sst Gas 17% 145 1,366 18.1 170.8 46.6

Oil 13%

Benchley Halibut Sub-Group sst Gas 24% 39 75 4.9 9.4 6.4

Oil 16%

Cotton Golden Beach sst Oil / Gas 4% 60 1 7.5 0.1 7.5

Cotton Halibut Sub-Group sst Oil 16% 13 - 1.6 - 1.6

Oscar West Intra-Latrobe ssts Oil / Gas 25% 19 12 2.4 1.5 2.6

Oscar East Intra-Latrobe ssts Oil / Gas 19% 19 18 2.4 2.3 2.8

Totals 419 2,092 52.4 261.5 96.0

Farm-Out may be a ‘Company Maker’ even if OBL retains only 5% to 7.5% free-carried

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OBL’s strategic aim is to add incremental resources to its core operated assets at modest cost and to

deliver rapid development opportunities at low capital cost.

Company believes that 2011 has been a year of significant definition of incremental value-add to

the Company across all it’s core assets – Carnarvon (R3/R1), Canning (Backreef Area) and

Gippsland (Vic/P41) have become significantly more material to OBL.

Excluding management and administration costs, the Company as a new WA operator (both offshore &

onshore) has spent circa $775k to-date during 2011 on furthering both geological and geophysical

exploration and assessment of its key operated assets Cyrano R3/R1 and Backreef Area (including some

$120k spent on production test approvals which will not be re-charged during 2012) and a further $150k on

maintaining its legal position in both its Backreef Area and non-operated strategic Gippsland assets.

Carnarvon Basin

The Company has increased Cyrano P50 Contingent Resources STOIIP from 4.6 to 10.1 MMbbls

and has indicated its preferred development method which may high-grade resources cheaply

The Company’s Cyrano Scoping Study has (using a novel Extended Well Test Concept) reduced the

estimated capex for a future development from USD$140m to below USD$30m.

Company will consider now moving the engineering studies more to reservoir simulation and assessment

of the extension of the R5 Nasutus Oil Field into R3

Seeking Farmin interest ahead of 2012.

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Canning Basin

• The Company has delineated within it’s Backreef Area a maiden Prospective Resources P50

STOIIP at circa 73 MMbbls

• The Company’s recent Backreef Area assessment has confirmed some 8 Leads all positioned at shallow

depth (less than 1000m – cf with >2500m more typical in the Canning) and conducive to the future

deployment of cheaper drilling rig.

• OBL has recently conducted a in-situ rig inspection in November of rig capable of drilling to 1200m to

1500m and has engaged experienced inspection engineers to conduct further detailed assessments of the

equipment and costings of modifications necessary under the Petroleum & Geothermal Act before a

decision is made whether to fund modifications in January 2012.

• Presently no contract has been entered into. It is anticipated that this rig option will likely be a lot cheaper

than mobilising a shallow CSG style rig from Queensland for future operations in Backreef Area & shallow

CSG operations in the 5/07-08EP.

• Seeking Farmin interest ahead of 2012 work program

Gippsland Basin

• During November, OBL successfully protected its long-term investment position in Vic/P41 and

was assigned by Farminor Moby Oil & Gas a 5% interest in Vic/P41 for nil cost – thereby removing

a AUD$1.65m contingent payment to Moby on the first well drilled in Vic/P41.

• Apart from now being on title with a full JV vote, the Company’s estimated net direct share of Prospective

Recoverable P50 Resources is circa 38 MMboe 47

Conclusions F

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OBL has four diverse Projects with a pipeline for growth.

Portfolio offers near-term potential re-rating impact and offering investors significant

leverage to Conventional Oil & Gas, Unconventional CSG & USG and exposure to

attractive mature hydrocarbon prospective Basins

OBL’s plan to liberate shareholder wealth

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R3 Renewal as R3 / R1

Define extent of Nasutus into R3

Upgrade booked 2C resources

Review Development Options

Upgrade recovery factor & 2C

resources. Review potential

Unitisation / EWT / Farm-Out

Pre-FEED / FEED

2011 actions Future potential 2012

Cyrano Oil Field

Backreef Area

USG / CSG / Oil

Eastern Gippsland

Define Backreef Oil Pool

Define extent of new oil play

Delineate new Prospects / Leads

Finalise NT Mediation with KLC

Seek Farm-In Partners

Seek USG partner interest

Finalise Permit Renewal & WP

CNOOC Joint Study

Acquire 5% interest

Subject to Rig availability &

Funding / Farm-Out

Production Test Backreef-1 asap

Farm-Out / Drill Prospects

Finalise Mediation asap

Farm-Out of USG / CSG & Oil

Exploration

Review exploration options

Seek Farm-Out on favourable

terms

Likely ‘near-term drivers of value’ & re-rating opportunity

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M Thousand

MM Million

B Billion

bbl Barrel of crude oil (ie 159 litres)

PJ Peta Joule (1,000 Tera Joules (TJ))

Bcf Billion cubic feet

Tcf Trillion cubic feet

BOE Barrel of crude oil equivalent – commonly defined as 1 TJ equates to circa158 BOE –

approximately equivalent to 1 barrel of crude equating to circa 6,000 Bcf dry methane on an

energy equivalent basis)

PSTM Pre-stack time migration – reprocessing method used with seismic

PSDM Pre-stack depth migration – reprocessing method used with seismic converting time into depth

AVO Amplitude versus Offset, enhancing statistical processing method used with 3D seismic

GIP Gas initially in place – also known as GIIP

OIP Oil in place – also known as Stock Tank Oil Initially in Placed (STOIIP)

fm Formation

sst Sandstone

OWC Oil water contact

Glossary & Petroleum Units

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www.oilbasins.com.au

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