Upload
others
View
1
Download
0
Embed Size (px)
Citation preview
2011 AGM PRESENTATION 24th Annual General Meeting of Shareholders – 29 November 2011
ASX codes OBL , OBLOA & OBLOB
For
per
sona
l use
onl
y
2
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.
For
per
sona
l use
onl
y
• 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
3
Oil Basins Limited
Objective: establish strategic production hubs near known oil & gas in mature basins
For
per
sona
l use
onl
y
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
4
The Assets F
or p
erso
nal u
se o
nly
• 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.
5
What sets Oil Basins apart? F
or p
erso
nal u
se o
nly
6
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
For
per
sona
l use
onl
y
7
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
For
per
sona
l use
onl
y
8
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
For
per
sona
l use
onl
y
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
9
For
per
sona
l use
onl
y
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.
10
For
per
sona
l use
onl
y
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.
11
For
per
sona
l use
onl
y
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.
12
For
per
sona
l use
onl
y
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)
13
For
per
sona
l use
onl
y
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
14
For
per
sona
l use
onl
y
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
15
For
per
sona
l use
onl
y
16
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
For
per
sona
l use
onl
y
Oil Projects – Canning Basin Assets
17
Backreef-1 Oil Show
For
per
sona
l use
onl
y
interpretation Backreef Area
18
• 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
For
per
sona
l use
onl
y
OBL New Regional Mapping Interpretation Backreef Area appears to be highly prospective
19
Backreef-1 Cased & Suspended (site visit 13 Nov 2011)
\
Backreef-1 well site
Backreef-1 well site & Company’s water bore
For
per
sona
l use
onl
y
20
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
For
per
sona
l use
onl
y
OBL Geological Interpretation Line BV93-17 Cross-section of southern portion of potential New Oil Play
21
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
For
per
sona
l use
onl
y
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
For
per
sona
l use
onl
y
23
Backreef Area – New Oil Play Well correlations – Blina-1 (1981) and updip Backreef-1 (2010)
For
per
sona
l use
onl
y
24
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).
For
per
sona
l use
onl
y
25
Backreef Area – New Oil Play 7 Leads in the Yellow Drum – 6 Leads within L6 and 1 within EP129R3
For
per
sona
l use
onl
y
26
Backreef Area – New Oil Play New Lead in Nullara Fm situated within L6
For
per
sona
l use
onl
y
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
27
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
or p
erso
nal u
se o
nly
28
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
or p
erso
nal u
se o
nly
Lead A – East Blina Yellow Drum
Backreef Lead Yellow Drum
29
Backreef Area – New Leads F
or p
erso
nal u
se o
nly
30
Backreef Area – New Leads (continued)
Lead B Yellow Drum
Lead C Yellow Drum
For
per
sona
l use
onl
y
Lead D Yellow Drum
Lead E Yellow Drum
31
Backreef Area – New Leads (continued) F
or p
erso
nal u
se o
nly
Lead F Yellow Drum
Lead G Nullara Limestone
32
Backreef Area – New Leads (continued) F
or p
erso
nal u
se o
nly
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
33
For
per
sona
l use
onl
y
34
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
For
per
sona
l use
onl
y
• 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
35
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
For
per
sona
l use
onl
y
CSG Projects – Canning Basin Permian Lighjack coal extensive & favourable for CSG
36
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
For
per
sona
l use
onl
y
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
37
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”
For
per
sona
l use
onl
y
USG Projects – Canning Basin Ind. Exp. Report concluded both Permits are highly attractive for USG
38
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
For
per
sona
l use
onl
y
USG Projects – Canning Basin Ind.Expert Report has delineated substantial USG prospectivity
39
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.
For
per
sona
l use
onl
y
OBL Canning portfolio USG comparisons
40
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
For
per
sona
l use
onl
y
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
41
NSE – Goldwyer Shale Play Permit 5/07-8EP Comparison
New USG Play potential ‘Company Maker’
For
per
sona
l use
onl
y
• 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
42
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
For
per
sona
l use
onl
y
43
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
For
per
sona
l use
onl
y
Non-Operated Assets – Oil & NGL Projects Gippsland Basin - Rights to 12.5% Vic / P41 & 17% Vic / P66
44
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
For
per
sona
l use
onl
y
Gippsland Basin – 12.5% Rights Vic/P41
45
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
For
per
sona
l use
onl
y
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.
46
Conclusions F
or p
erso
nal u
se o
nly
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
or p
erso
nal u
se o
nly
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
48
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
For
per
sona
l use
onl
y
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
49
For
per
sona
l use
onl
y
www.oilbasins.com.au
For
per
sona
l use
onl
y