BPH ENERGY LTD — Audit Report / Information 2010

Dec 21, 2010

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22 December 2010

Companies Announcement Office Australian Securities Exchange Limited 10th Floor, 20 Bond Street SYDNEY NSW 2000

Dear Sir,

ADVENT ENERGY PEP11 INDEPENDENT EXPERT REPORT – PERMIO TRIASSIC

MEC Resources (ASX:MMR) is pleased to provide the attached independent geological expert’s report on the Permio Triassic section commissioned by investee company Advent Energy Limited (Advent) for Advent’s PEP11 project in the offshore Sydney Basin.

The report was prepared by Mr Tim Berge of Pangean Resources LLC. Tim Berge is an internationally recognised geophysicist with over 30 years experience, including time with Exxon Ventures and Forest Oil, and is credited with a number of significant field discoveries including the multi-Tcf Ibhubesi Field in South Africa.

Of key significance is the conclusion that PEP11 has all the working components of a gas-charged hydrocarbon system and is a potential giant gas province. The mean estimate of the portfolio aggregate prospective resources has been calculated to be 15.9 Tcf recoverable.

The major shareholders of Advent are:

MEC Resources (ASX: MMR) BPH Energy (ASX: BPH) Talbot Group Investments Grandbridge (ASX: GBA)

Yours sincerely,

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David Breeze Media Enquiries: Executive Director Bill Kemmery MEC Resources Ltd Fortbridge Consulting PO Box 317 Tel: +61 2 9331 0655 North Perth WA 6906 Mobile: +61 400 122 449 Tel: +61 8 9328 8477

About MEC Resources

ASX listed MEC Resources (ASX: MMR) invests into exploration companies targeting potentially large energy and mineral resources. The Company has been registered by the Australian Federal Government as a Pooled Development Fund enabling most MEC shareholders to receive tax free capital gains on their shares and tax free dividends.

About Advent Energy

Advent Energy Ltd is an unlisted oil and gas exploration company, held by major shareholders MEC Resources (ASX: MMR), BPH Energy, Grandbridge (ASX: GBA) and Talbot Group Investments. Advent holds a strong portfolio of exploration and near-term production assets throughout Australia. Advent’s cornerstone project lies off the coast of NSW in Petroleum Exploration Permit 11 (PEP11), and comprises gas prospects of multi-Tcf capacity. Advent Energy’s wholly owned subsidiary Asset Energy Pty Ltd will increase its interest from 25% to 85% of PEP11 by drilling the first well. Bounty Oil and Gas (ASX:BUY) will thereby reduce their interest from 75% to 15%.

Notes: In accordance with ASX listing requirements, the geological information supplied in this report has been based on information provided by geologists who have had in excess of five years experience in their field of activity.

MEC is an exploration investment company and relies on the resource and ore reserve statements compiled by the companies in which it invests. All Mineral Resource and Reserve Statements have been previously published by the companies concerned. Summary data has been used. Unless otherwise stated all resource and reserve reporting complies with the relevant standards. Resources quoted in this report equal 100% of the resource and do not represent MEC’s investees’ equity share.

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MEC Resources Ltd

ACN 113 900 020 PO Box 317, North Perth, WA 6906

14 View Street, North Perth 6006, Western Australia T: +61 8 9328 8477 F: +61 8 9328 8733 info@mecresources.com.au www.mecresources.com.au

INDEPENDENT EXPERT REPORT

PEP11 Block Offshore Sydney Basin Australia

Prepared by PANGEAN RESOURCES LLC T.B. Berge, P.G., TBPG#6318 November, 2010

Prepared for Advent Energy Ltd

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CONTENTS

CONTENTS
SUMMARY CONCLUSIONS	4
INTRODUCTION	5
REGIONAL GEOLOGY	6
PETROLEUM SYSTEMS ELEMENTS	11
SOURCE	11
RESERVOIR	15
SEAL	18
PROSPECTS SUMMARY	20
INDIVIDUAL PROSPECT DETAILS AND RISKS	20
KEY PARAMETERS	22
PORTFOLIO AGGREGATION	31
CONCLUSION	32
FIGURES
Figure 1, Location of Block PEP 11 offshore Australia.	5
Figure 2, Major sedimentary basins of Australia.	6
Figure 3, Global Magnetic and Gravity Field Data for SW Australian region.	7
Figure 4, Structural Model of the Sydney Basin.	8
Figure 5, Depth structure map.	9
Figure 6, General Stratigraphy of the Sydney Basin.	10
Figure 7, Seismic profile showing generation and migration pathways.	12
Figure 8, Line B19 Neural Network.	13
Figure 9, Details of seafloor mound.	14
Figure 10, Isotopic analysis of Catherine Bay seeps.	14
Figure 11, Complete log suite from Munmorah.	16
Figure 12, Log analysis of select interval from -550m to -760 m depth, Munmorah.	16
Figure 13, Log analysis of select interval from -1650m to -1870m depth, Munmorah.	17
Figure 14, Scaled correlation of Munmorah section with the Fish prospect location.	18

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Figure 15, Log analysis of interval -1270m to -1490m, Munmorah well.	19
Figure 16, Leads Map.	20
TABLES and CHARTS
Table 1, Prospect List and 3P Reserves Summary	4
Table 2, Permeability by formation and age.	15
Table 3, Porosity values by formation and age.	15
Table 4, Prospective reserves distribution, all prospects.	21
Table 5, Individual prospect assessment and risking details.	23
Table 6, Portfolio Aggregation Plot.	31
Table 7, Table of Aggregate Portfolio values.	31
DIGITAL APPENDIX	33
BIBLIOGRAPHY	33
CONSENT LETTER	34

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SUMMARY CONCLUSIONS

Evaluation of all available Geologic and geophysical data, summarized here, show that PEP11, which covers a majority of the Sydney Basin offshore NSW Australia, has all the working components of a gas-charged Hydrocarbon system and is a potential Giant Gas province. The Fish Prospect, confirmed through ongoing seismic data review, is a fault bounded 4-way dip-closed anticline structure estimated to comprise 11.5 Tcf (Mean) prospective recoverable gas resources. A large prospect named Baleen is located in the northern sector of the Permit in an average depth of 125m of water and is situated on the crest of the Offshore Uplift on a thrusted anticline. With a closure of over 202 km[2] (50,500 acres), the Baleen target has potential to hold 1.4 Tcf (Mean) of prospective recoverable gas resources.

Looking past any single initial test, and assuming success, we may wish to assess the possible value of the entire portfolio by a defined process known as Portfolio Aggregation. Calculating the Aggregate Sum of the Prospective Reserves, the Mean of the Portfolio Aggregate is 15.9 Tcfg recoverable. These are “Undiscovered Prospective Reserves” as defined by the SEC and SPE 2005. The equivalent classification if terms of a 3P assessment would be: (Low) P1= 410 Bcfg, P2= 4.25 Tcfg, (Best) and P3 (High)= 47 Tcfg, the equivalencies are allowed and defined specifically by the SPE (Etherington, 2005), these are also by those same definitions and guidelines considered “Undiscovered Prospective Reserves” and assume successful outcomes.

TABLE 1: Prospect List and 3P Reserves Summary

	Reserves, Bcfg	Reserves, Bcfg
Prospect Name	Mean	P90	P50	P10
Fish	11508.6	28.6	2131.2	35491.8
Baleen	1452.0	17.2	472.2	4193.3
Shark	3510.9	44.1	752.2	10656.0
N Sei	435.3	8.5	162.3	1226.1
W Sei	192.9	3.7	71.9	543.4
E Sei	327.3	6.4	122.0	921.9
Trout	623.9	12.1	232.6	1757.3
Humpy	429.7	8.3	160.2	1210.4
Orca	810.7	15.7	302.3	2283.7
Octopus	471.4	9.2	175.7	1327.9
Squid	585.0	11.4	218.1	1647.7
Blue	799.0	15.5	297.9	2250.6
Blue Whale	3410.8	66.2	1271.6	9607.6
S Squid	777.2	66.2	289.7	2189.1
S Humpback	87.7	1.7	32.7	247.1

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Introduction

Advent Energy has been granted an option to acquire up to an 85% interest in PEP 11, an oil and gas permit located in the offshore Sydney Basin, from Bounty Oil and Gas NL (Bounty).

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Fig. 1 Location of Block PEP 11 offshore Australia.

The block is a 200km long, 8,250km[2] permit area that covers most of the offshore extent of the Sydney Basin.

Petroleum system elements all seem to be present and active. There is gas production onshore and abundant gas seeps in both offshore and onshore parts of the basin. There is ready market and infrastructure for gas development. Three 2D seismic surveys (a total 2525 line miles), reprocessed in 2007 and in 2010, have been interpreted and mapped. A number of prospects have been defined from this database that are the subject of this study.

Mapped prospects and leads within the offshore Sydney Basin are generally located less than 50km from Australia’s largest energy market, the Sydney-Wollongong-Newcastle greater metropolitan area. This area has a population of approximately 5,000,000 people. Traditionally, all natural gas used in New South Wales has been piped in from South Australia and the Bass Strait. However, studies by the Australian Bureau of Agricultural and Resource Economics (ABARE) and the Australian Petroleum Production and Exploration Association (APPEA) state that those sources may not be able to meet the demand for gas in the medium to longer term. NSW government forecasts suggest an increased power requirement of 10,000 GWh by 2015.

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Regional Geology

New South Wales / Offshore Sydney Basin

The Sydney Basin is a Late Paleozoic cratonic basin that was rifted first during Pangea breakup in Mid Jurassic, and during continued separation of the Lord Howe Rise.

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Figure 2. Major sedimentary basins of Australia

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Australian
PEP11
Plate
(approx)
Pacific Plate
Global Magnetic Field Data, Austral Region
Austral Region NOAA, NGDC, and CIRES
EMAG2- New Global mag coverage, compiled sat, ship, and air mag measurements, released Feb., 2009 (Maus et al, 2009)
Australian
Plate
Pacific Plate
Global Gravity Field Data, Austral Region
from GRACE- twin sats deployed in 2002, CSR, GFZ Potsdam, NASA, and DLR
Pacific-Antarctic Ridge
Pacific-Antarctic Ridge
New Caledonia
New Caledonia
New Hebrides
New Hebrides
Tasman Ridge
Tasman Ridge
Tonga-Kemadec Arc
Tonga-Kemadec Arc
Lord Howe Rise
Lord Howe Rise
V
V
V
V
V
V
V
V
V
V
V
V
V
V
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Figure 3. Global Magnetic and Gravity Field Data for SW Australian region showing major plate elements, ridges, trenches, and Plate transform margins.

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This later rifting is a result of oceanic crust generation at the Tasman ridge south of the Sydney Basin. The Offshore extent of the basin is untested but prospective for gas (Blevin, 2001). The onshore extent of the basin produces some coal-associated gas, and has play elements that may be extended directly and by analogy into the offshore.

The Northwestward motion of oceanic crust and it’s subduction into the New Caledonian Trench, relative to the stable Australian Craton, places the Sydney Basin in left-lateral shear. Bends in a strikeslip system may be either restraing or releasing depending on the curve of the zone or faults. We hypothesise that a structural model of a restraining bend in a left-lateral system is valid for this area. We can match the highs and major faults with highs and faults predicted in such a model. Compare the Model (Fig. 4) with the mapped features (Fig. 5).

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Peel-
Manning
Thrust
Thrusting
develops in
confining
bend
Restraining Bend,
Sinistral (left- lateral)
Strike -Slip
deformation
V
V
Anticline
Anticline
V
V
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Fig. 4, Structural Model of the Sydney Basin

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Fig 5, Depth structure map. Note how the 2 main fault trends and locations of the 2 highs ( compare fig. 5 with fig. 4 above) correspond to the model predictions.

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Fig. 6, General Stratigraphy of the Sydney Basin (from Bradley, Graham)

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Although there have been over a thousand wells drilled in offshore Australia, no exploration drilling has ever taken place in the offshore Sydney Basin. The Fish and Baleen prospects will be the first primary structural targets drilled to test this basin.

Recent interrogation and reprocessing of seismic data has allowed for observation of Direct Hydrocarbon Indicators (DHI), including Amplitude Versus Offset (AVO) analysis, with positive results. Gas chimneys and hydrocarbon related diagenetic zones (HRDZ) have been identified, and flat spot events coincident with the Baleen prospect are being investigated.

The prospectivity of the northern sector has been further enhanced by the confirmation of the presence of ongoing hydrocarbon slicks. Originally detected on 1996 satellite imagery, a repeat analysis of 1998 and 2001 images again identified apparent slicks directly over the Baleen prospect. Inferred gas seepage along the PEP 11 / continental margin from Geoscience Australia’s 2006 continental slopes survey, and inshore observed hydrocarbon seepage has further evidenced the offshore Sydney Basin as an active hydrocarbon system. Independent study has found that 79% of wells drilled in positive geochemical anomalies resulted in commercial oil or gas discoveries.

Advent has secured a rig slot to drill PEP 11 in the 4[th] Quarter 2010.

Petroleum System Elements

The Sydney Basin has long been known as having resource potential and a having a working thermogenic gas-prone petroleum system. The first area assessment was done by Exon et al in 1991 (4.5 Mboe, or about 27 Bcfg) was and indicated a thermogenic source rock. Here are the details of the Petroleum System elements;

Summary

• Source: Permian Coal Beds, Permian/Carboniferous marine shales

• active seeps, Thermogenic Methane, gas production onshore

• Reservoir: Triassic/Permian/Sands

• Documented reservoirs Onshore

• • Porosity range 8 – 12 % (Triassic to 30%) Permeability. 1mD to 1 Darcy

• Net Sand Thickness ~ 100ft

• Seal: Triassic and Permian mudrocks

Source

“Although the high inertinite and vitrinite content of the coals indicate that they are primarily a potential source of gas, the Upper Permian coals of the Sydney Basin compare favourably as a potential source for both oil and gas with the Toolachee Formation, the main late Permian source in the Cooper Basin of southwest Queensland and South Australia. The Late Permian coal measures attain a thickness of about 1600m at the coast between Newcastle and Terrigal-1, and thicken and dip offshore.” (Alder, 1998).

It is expected, given the abundance of gas indications, that there is an active, coal source rock in the basin.

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It is worthwhile to note some of the abundant indications of migrated gas (Heggie, et al, 1997, Clennel et al, 2009, Kroh, 2009) ;

• 1) Active seeps Chemotropic mounds

• 2) Shallow BSR’s

• 3) Amplitude anomalies

• 4) Seismic evidence of seepage

If so, intervention would have positive environmental impacts besides being a significant energy resource.

Profile of proposed well Baleen # 1 [Seismic Line B4-19]

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Baleen #1
-200m
-1250m
-4000m
Cenozoic Layer S1
Top Tri-Permian
Top Dalwood Group ?
Basement?
Baleen #1
Oil/Gas
Pliocene + Q
Miocene
Middle Triassic
Early Triassic
Late Permian
Early Permian
Basement?
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Fig. 7, Seismic profile and interpretation showing proposed source generation and migration pathways and eventual leakage to surface. Compare suggested migration routes to fig.9 seep routes.

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Fig. 8, Line B19 Neural Network (Chimney Cube”) processing showing seep class in green. Demonstrates Nonfault seal trap type. Documents gas primary and secondary migration routes. These seeps can be seen to form seafloor mounds .

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Fig. 9, Details of seafloor mound on line 19 seep.

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Fig. 10, Isotopic analysis of samples from the area of Baleen mounds. Heavier hydrocarbons are to the right. There is an abundance of gas phase light compounds, and the range to heavier aromatics and aldehydes is indicating a mature petroleum source. Advent Energy report, “Gore” sampling, June 2010. Note the Gore technology does not sample methane.

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Reservoir

Direct evidence supporting the presence and quality of possible reservoir rock offshore is welldocumented. A summary of permeability and porosity measurements from numerous onshore wells is shown in Tables 3 and 4 below;

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Tables 2(left) and 3(right). Permeability and Porosity values by formation and age from Sydney Basin onshore wells. From Maung et al, 1997, modified by Sayers, 2004 .

This clearly demonstrates reservoir presence with porosity ranging up to 31% and permeability over 1 Darcy. Best reservoir development is from the Triassic Narrabeen Group.

Offshore an important datapoint is a dredge sample identified as Triassic sediments from offshore (Maung et al, 1997), proving the offshore extent of the proposed sedimentary basin. Another is the Munmorah well recently drilled on the west edge of the block from a surface location onshore correlates directly into the Fish prospect. Initial analysis of this well shows that it drilled a clastic sand-shale sequence with interbedded coals from surface to a total depth of 2227.42 meters.

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Fig. 11, Complete log suite from Munmorah. The section consists almost entirely of clastic rocks; 2 coaly sequences separated by a shaley interval. Resistivity in some sands is unusually high indicating possible gas saturation. There is a downward shift in Facies from coastal plain to offshore silts and shales at -1340, indicating a sequence boundary.

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Sequence Boundary
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Error! Objects cannot be created from editing field codes.

Fig. 12, Log analysis of select interval from -550m to -760 m depth, Munmorah. Gamma curve in green, SP in dark blue, Deep resistivity in Red, Sonic in light Blue, and bulk density in magenta. Gamma shading is yellow indicating possible reservoir SP is shaded in Blue above 320 mv. The few thin intrusives logged are characterized by very high SPs. Resistivity above 20 Ohmm is shaded red. When these high resistivities are found in reservoir indicated by gamma response, these may indicate possible gas-charged zones.

The sands here with distinct bases and fining-upward profiles may represent channel environments and good reservoir development.

Error! Objects cannot be created from editing field codes.

Fig. 13, Log analysis of select interval from -1650m to -1870m depth, Munmorah. The shading and facies analysis is similar to figure 12 above. This deeper interval is for a coaly section and shows correlation of the logged samples with the logs. The interval shows a transition from coarsening-upward shoreface sands (exp., 1790-1800) upward into a coastal plane environments evidenced by the thin coals. These coarsening-upward shoreface environments are expected to be wide-spread and are excellent reservoir candidates. The coals show high resistivity, normal in coal, that may also indicate source potential.

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Error! Objects cannot be created from editing field codes. Fig. 14, Scaled correlation of Munmorah section with the Fish prospect location (projected) and line B4-29. Distance between Munmorah and South Fish II locations is 22 kms.

The correlation suggests that the section at the Fish prospect may be older than the rocks drilled at Munmorah. It is thought that the Munmorah section is similar of overall lithology to the deeper Fish prospect section. These correlations are somewhat speculative but it is a reasonable expectation that there will be sedimentary section drilled at the Fish prospect.

Seal

The Cainozoic section that overlies the Mesozoic unconformity is a system seal. This is evidenced by the proliferation of seeps around the subcrop of the exhumed unconformity, the collocated presence of shallow gas indications, and the seismic chimneys associated with this feature. The unconformity is a long-lived one- developing in the late Jurassic at the break-up of Pangea. It was essentially exposed from Mid-Jurassic to the Cainozoic. It is a major reflection in the seismic dataset and is easily mapped and identified. This amplitude is no doubt due to a velocity and density increase at the unconformity. It also marks the top of the Hydrocarbon system.

There are many interbedded seals in the section below the unconformity that would act as topseals for the prospects mapped. They may be exemplified by the shaley interval in the Munmorah well, and in fact thin shales like the shale that seals the sand at -1790 m, only a few meters thick, seems to be sufficient to seal that sand.

Error! Objects cannot be created from editing field codes.

Fig. 15, Log analysis of interval -1270m to -1490m, Munmorah well, shows possible trapped gas beneath prominent seal formed by a flooding surface/sequence boundary at -1353 m.

In regards to Petroleum Systems elements, this is all good evidence to suggest that there is a working hydrocarbon system in the PEP11 area.

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Prospect Summary

The structure map below is the basis for the assessed prospects. The actual correlation of this reflection with any known stratigraphic section is equivocal as discussed elsewhere, but it is a useful seismic marker and area-wide horizon.

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Prospects list, Mean Reserves
Fish 11.5 Tcfg
Baleen 1.5 Tcfg
Shark 3.5 Tcfg
North Sei 435 Bcfg
West Sei 193 Bcfg
East Sei 327 Bcfg
Trout 624 Bcfg
Humpy 430 Bcfg
Orca 811 Bcfg
Octopus 471 Bcfg
Squid 585 Bcfg
Blue 799 Bcfg
Blue Whale 3.4 Tcfg
S Squid 777 Bcfg
Fig. 16, Leads Map S Humpback 88 Bcfg
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Individual Prospect Reserves and Risks

All of the prospects evaluated here have been evaluated using SPE/AAPG guidelines and are considered Undiscovered Prospective Resources (SPE 2001, 2005, 2008). A probabilistic resource analysis is most applicable for projects such as evaluating the ‘potential’ resources of the subject area, where a great deal of uncertainty exists in the reservoir parameters.

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The uncertainty in the reservoir data is quantified by probability distributions, and an iterative approach yields an expected probability distribution for potential resources. This approach allows consideration of most likely resources for planning purposes, while gaining an understanding of what volumes of resources may have higher certainty, and what potential upside may be for the project. The analysis for this project was carried out considering uncertainty for all parameters in the volumetric equations. A good summary of the principles used in this analysis is summarized in Quirk and Rothrauff, 2008 and use principles and methodology developed and taught by Rose and Associates. All the estimates described herein represent the potential size of hydrocarbon deposits in the prospect areas if discovered to be present in economic quantity, in SPE terms, Undiscovered Prospective Resources. SPE allows use of either deterministic or probabilistic methodologies. While the SEC does not forbid probabilistic analyses, the disclosed quantities must be demonstrated to meet the defined deterministic criteria as they are here.

A Detailed Descriptions of Agencies’ Classifications/Definitions including summary and detailed (tables) comparison to SPE Reserves Definitions may be found in Etherington et al, 2005. Agencies included in the comparison are;

o US Security and Exchange Commission (SEC-1978)

o UK Statement of Recommended Practices (SORP-2001)

o Canadian Security Administrators (CSA -2002)

o Russian Ministry of Natural Resources (RF-2005)

o China Petroleum Reserves Office (PRO–2005)

o Norwegian Petroleum Directorate (NPD–2001)

o United States Geological Survey (USGS-1980)

o United Nations Framework Classification (UNFC-2004)

The output distributions were then used to characterize the Prospective Resources. Prospective resources are defined as “those quantities of oil and gas estimated on a given date to be potentially recoverable from undiscovered accumulations. They are technically viable and economic to recover.”

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Sydney Basin Offshore
Prospective Reserves, Tcfg
All Prospects
Tcfe
0.001 0.01 0.1 1 10 100
0
Fish
10 Baleen
Shark
20
N Sei
30 W Sei
E Sei
40
Trout
50 Humpy
Orca
60
Octopus
70 Squid
Blue
80
Blue Whale
90 S Squid
S Humpback
100
Probability
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Table 4 Prospective reserves distribution, this study, all prospects.

The distribution represents a distribution of possible outcomes given the input distributions of individual prospect parameters. Points may be used to represent individual outcomes, such as the pink

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square representing the prospect Baleen on the chart above. This point, located at a probability of 10% and 4 Tcf, that is, 90% of the outcomes for this prospect will have reserves less than 4Tcf.

It should be noted that difference between the P90 and P10 cases represents a broad range in possible value between the minimum and maximum expected resources. This is reflective of the high degree of uncertainty associated with any evaluation such as this one prior to actual field discovery, development, and production. These numbers represent percentile in a population, inverse of probability. These populations are produced by Monte Carlo simulation of 500 cases or more, and the sorted by rank from highest reserve outcome ( 99 Percentile) to lowest (1 Percentile). A 10% probability would be equivalent to a 90 Percentile of the population meaning that 90% of the cases have those reserves or less, ie., a high case. Also note that, in general, the high probability resource estimates at the left side of these distributions represents downside risk, while the low probability estimates on the right side of the distributions represent upside potential.

Principle Risks are Seal and Reservoir. There is generally a low Source Risk due to numerous and different observances of hydrocarbons. Risk for each individual prospect is estimated using a 4-element risk matrix; Trap, Seal, Reservoir, and Source and Migration. The prospect risk varies by prospect, and ranges from the least-risky (Fish, 21% COS) to the most risky (Blue Whale, 7.5% COS). Individual Average Prospect COS is 16.6%.

Because of the abundant evidence of a charged gas system there is thought to be a low risk of migration and charge in general, although this varies by fetch area (Blue and Whale) and distance from suspect kitchen (Orca, SEI’s).

Some of the more shallow prospects may have more seal risk, certainly there is much evidence of leakage where the Mesozoic unconformity is breached to the seafloor, both mounds and seismic chimneys. Some of the less well documented or subtle closures have higher trap risk (Blue Whale, Squid).

Key Parameters

For Fish, Baleen, and Shark maps were derived for each of 3 possible cases representing P10, P50, and P90 percentiles. It is important to note that a success at Fish of the P10 area includes the Baleen and Shark prospects. Other prospect areas are map-based for the P50 area andP10 and P90 areas are estimated using a lognormal distribution.

Net intervals that were used for all prospects are 30 ft for P90, 100 ft. for P50 and 200 ft. for P10. These are based on values used in a previous evaluation by Santos and are consistant with field and reported values. Porosity was likewise varied from 10% to 15% to 20% for P90, P50, and P10 cases respectively. Hydrocarbon saturations varied from 60% to 72% to 85% based on analogy with similar clastic reservoirs. Temperatures, pressures and Gas expansion were calculated using a ‘normal’ pressure gradient of .433 psi/ft, temperature gradient of 1.5 degrees F/100 ft. and Boyles Law. Geometric correction factors were estimated from mapped shapes. Recovery is varied from .5 to .75 to .8 for P50 and 200 ft. for P10 cases respectively representing a gas, pressure-depletion production mechanism. References for equations, fluid and gas properties, and other miscellanea can be found at the Texas A&M website at: http://www.pe.tamu.edu/virtuallab/OilFVbelowBP.aspx A complete glossary of terminology is at; http://www.glossary.oilfield.slb.com .

Mean values were calculated from the resulting distributions. The mean is a statistical representation of the average expected successful outcome of a well drilled at the prospect.

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Table 5 - Individual prospect assessment and risking details

Input Values in Red	P1	4.23144355	Sum of Means	Sum of Means	235.7840106	Bcfg in- place		p10	694.5662909				75.55390045
	P2	21.19086091	Sum of Means		25.42230446	Tcfg Recoverable		P50	65.62631674				6.692563404		25.42230446
	P3	206.1302626	Sum, risked means		4.23144355	Tcfg Recoverable		p90	3.878655581				0.263696534
Name		Case	area	Net Interval	Porosity	Shc	geom correction	ft2/ac	In-place	gas expansion Factor		Rf	Recoverable Reserves	Cond ratio	Cond
Sydney Basin Offshore			acres	ft	%	%			Bcfg				Tcfg	bblo/Mcfg	Mbo
Fish Prospect		10	244780	200	20.0%	85.0%	0.9	43560	326.2760741	135.9731631		0.8	35.49183187	50	1.774591594
		50	55528	100	15.0%	72.0%	0.8	43560	20.89842924	135.9731631		0.75	2.131219146	50	0.106560957
		90	7162	30	10.0%	60.0%	0.75	43560	0.421168572	135.9731631		0.5	0.028633811	50	0.001431691
Reservoir (Depth, ft):	4395.2	m:	1340
Deg/100 ft:		1.5	psi/ft	0.43300
res temp:		125.928	res pressure:	1917.2216			Swanson's Mean:	106.3685445	Gas, Bcfg in-place
surf temp		60	deg F					11.50862736	Gas, Tcf recoverable				Mbo recov Swanson's Mean=		0.575431368
surf pressure		14.1	psi
Risk:	Trap	70%	Seal	50%	Reservoir	60.0%	Source Migration	100.0%	Total Risk	21.00%
			Mounds and BSR indicate charge, mounds									http://www.pe.tamu.edu/virtuallab/OilFVbelowBP.aspx
			Risked Expected Outcome:			2.41681175	Tcf risked recoverable					http://www.glossary.oilfield.slb.com

21

Name		Case	area	NetInterval	Porosity	Shc	geomcorrection	ft2/ac	In-place	gas expansion Factor	Rf	Recoverable Reserves	Condratio	Cond
SydneyBasinOffshore			acres	ft	%	%			Bcfg			Tcfg	bblo/Mcfg	Mbo
**Baleen **		10	28920	200	20.0%	85.0%	0.9	43560	38.54850912	135.9731631	0.8	4.193250175	50	0.20966251
		50	12302	100	15.0%	72.0%	0.8	43560	4.629961037	135.9731631	0.8	0.472162835	50	0.02360814
		90	4299	30	10.0%	60.0%	0.75	43560	0.252806994	135.9731631	0.5	0.017187483	50	0.00085937
Reservoir Depth,ft:	5195.5	m:	1584
Deg/100ft:		1.5	psi/ft	0.43300
res temp:		137.9328	res pressure:	2263.7602			Swanson's Mean:	13.4923792	Gas,Bcfgin-place
surftemp		60	degF					1.45199643	Gas,Tcf recoverable			Mbo recov Swanson's Mean =		0.07259982
surfpressure		14.1	psi
Risk:	Trap	70%	Seal	50%	Reservoir	60.0%	SourceMigration	90.0%	Total Risk	18.90%
			better seal preservation at DHI(mound)		Baleen. Good
			Risked Expected Outcome:			0.27442733	Tcf riskedrecoverable

Name		Case	area	NetInterval	Porosity	Shc	geomcorrection	ft2/ac	In-place	gas expansion Factor	Rf	Recoverable Reserves	Cond ratio	Cond
SydneyBasinOffshore			acres	ft	%	%			Bcfg			Tcfg	bblo/Mcfg	Mbo
Shark		10	73492	200	20.0%	85.0%	0.9	43560	97.96013251	135.9731631	0.8	10.65595926	50	0.53279796
		50	36746	100	8.0%	72.0%	0.8	43560	7.375821742	135.9731631	0.8	0.75218536	50	0.03760927
		90	18373	30	6.0%	60.0%	0.75	43560	0.648265583	135.9731631	0.5	0.044073361	50	0.00220367
Reservoir Depth,ft:	5149.6	m:	1570
Deg/100ft:		1.5	psi/ft	0.43300
res temp:		137.244	res pressure:	2243.8768			Swanson's Mean:	32.5328481	Gas,Bcfgin-place
surftemp		60	degF					3.51088393	Gas,Tcf recoverable			Mbo recov Swanson's Mean =		0.1755442
surfpressure		14.1	psi
Risk:	Trap	70%	Seal	50%	Reservoir	60.0%	SourceMigration	80.0%	Total Risk	16.80%
			Risked Expected Outcome:			0.58982850	Tcf riskedrecoverable

22

Name		Case	area	NetInterval	Porosity	Shc	geomcorrection	ft2/ac	In-place	gas expansion Factor	Rf	Recoverable Reserves	Cond ratio	Cond
SydneyBasinOffshore			acres	ft	%	%			Bcfg			Tcfg	bblo/Mcfg	Mbo
**NSei **		10	8456	200	20.0%	85.0%	0.9	43560	11.27130682	135.9731631	0.8	1.226076192	50	0.06130381
		50	4228	100	15.0%	72.0%	0.8	43560	1.591243315	135.9731631	0.8	0.16227479	50	0.00811374
		90	2114	30	10.0%	60.0%	0.75	43560	0.124315884	135.9731631	0.5	0.008451812	50	0.00042259
Reservoir Depth,ft:	5726.9	m:	1746
Deg/100ft:		1.5	psi/ft	0.43300
res temp:		145.9032	res pressure:	2493.839			Swanson's Mean:	4.05518414	Gas,Bcfgin-place
surftemp		60	degF					0.43526832	Gas,Tcf recoverable			Mbo recov Swanson's Mean =		0.02176342
surfpressure		14.1	psi
Risk:	Trap	70%	Seal	50%	Reservoir	60.0%	SourceMigration	80.0%	Total Risk	16.80%
			Risked Expected Outcome:			0.07312508	Tcf risked recoverable

Name		Case	area	Net Interval	Porosity	Shc	geom correction	ft2/ac	In-place	gas expansion factor	Rf	Recoverable Reserves	Condratio	Cond
Sydney Basin Offshore			acres	ft	%	%			Bcfg			Tcfg	bblo/Mcfg	Mbo
**WSei **		10	3748	200	20.0%	85.0%	0.9	43560	4.995844128	135.9731631	0.8	0.543440583	50	0.02717203
		50	1874	100	15.0%	72.0%	0.8	43560	0.705295642	135.9731631	0.8	0.071925959	50	0.0035963
		90	937	30	10.0%	60.0%	0.75	43560	0.055101222	135.9731631	0.5	0.003746144	50	0.00018731
Reservoir Depth,ft:	6054.9	m:	1846
Deg/100ft:		1.5	psi/ft	0.43300
res temp:		150.8232	res pressure:	2635.863			Swanson's Mean:	1.79740186	Gas,Bcfgin-place
surftemp		60	degF					0.1929264	Gas, Tcf recoverable			Mbo recov Swanson's Mean =		0.00964632
surfpressure		14.1	psi
Risk:	Trap	70%	Seal	50%	Reservoir	60.0%	Source Migration	100.0%	Total Risk	21.00%
			Risked Expected Outcome:			0.0405145	Tcf riskedrecoverable				http://www.pe.tamu.edu/virtuallab/OilFVbelowBP.aspx
											http://www.glossary.oilfield.slb.com

23

Name		Case	area	NetInterval	Porosity	Shc	geomcorrection	ft2/ac	In-place	gas expansion Factor	Rf	Recoverable Reserves	Cond ratio	Cond
SydneyBasinOffshore			acres	ft	%	%			Bcfg			Tcfg	bblo/Mcfg	Mbo
**ESei **		10	6358	200	20.0%	85.0%	0.9	43560	8.474807088	135.9731631	0.8	0.921877061	50	0.04609385
		50	3179	100	15.0%	72.0%	0.8	43560	1.196443354	135.9731631	0.8	0.12201314	50	0.00610066
		90	1589.5	30	10.0%	60.0%	0.75	43560	0.093472137	135.9731631	0.5	0.006354851	50	0.00031774
Reservoir Depth,ft:	6396	m:	1950
Deg/100ft:		1.5	psi/ft	0.43300
res temp:		155.94	res pressure:	2783.568			Swanson's Mean:	3.04906111	Gas,Bcfgin-place
surftemp		60	degF					0.32727483	Gas,Tcf recoverable			Mbo recov Swanson's Mean =		0.01636374
surfpressure		14.1	psi
Risk:	Trap	70%	Seal	50%	Reservoir	60.0%	SourceMigration	80.0%	Total Risk	16.80%
			Risked Expected Outcome:			0.05498217	Tcf riskedrecoverable

Name		Case	area	NetInterval	Porosity	Shc	geomcorrection	ft2/ac	In-place	gas expansion Factor	Rf	Recoverable Reserves	Cond ratio	Cond
SydneyBasinOffshore			acres	ft	%	%			Bcfg			Tcfg	bblo/Mcfg	Mbo
Trout		10	12120	200	20.0%	85.0%	0.9	43560	16.15518432	135.9731631	0.8	1.75733721	50	0.08786686
		50	6060	100	15.0%	72.0%	0.8	43560	2.280731904	135.9731631	0.8	0.232588748	50	0.01162944
		90	3030	30	10.0%	60.0%	0.75	43560	0.17818218	135.9731631	0.5	0.012113997	50	0.0006057
Reservoir Depth,ft:	6560	m:	2000
Deg/100ft:		1.5	psi/ft	0.43300
res temp:		158.4	res pressure:	2854.58			Swanson's Mean:	5.81230271	Gas,Bcfgin-place
surftemp		60	degF					0.62387086	Gas,Tcf recoverable			Mbo recov Swanson's Mean =		0.03119354
surfpressure		14.1	psi
Risk:	Trap	70%	Seal	50%	Reservoir	60.0%	SourceMigration	85.0%	Total Risk	17.85%
			Risked Expected Outcome:			0.11136095	Tcf riskedrecoverable

24

Name		Case	area	NetInterval	Porosity	Shc	geomcorrection	ft2/ac	In-place	gas expansion Factor	Rf	Recoverable Reserves	Cond ratio	Cond
SydneyBasinOffshore			acres	ft	%	%			Bcfg			Tcfg	bblo/Mcfg	Mbo
Humpy		10	8348	200	20.0%	85.0%	0.9	43560	11.12734973	135.9731631	0.8	1.210416752	50	0.06052084
		50	4174	100	15.0%	72.0%	0.8	43560	1.570919962	135.9731631	0.8	0.160202217	50	0.00801011
		90	2087	30	10.0%	60.0%	0.75	43560	0.122728122	135.9731631	0.5	0.008343865	50	0.00041719
Reservoir Depth,ft:	7652.2	m:	2333
	2333
Deg/100ft:		1.5	psi/ft	0.43300
res temp:		174.7836	res pressure:	3327.5199			Swanson's Mean:	4.00339134	Gas,Bcfgin-place
surftemp		60	degF					0.42970907	Gas,Tcf recoverable			Mbo recov Swanson's Mean =		0.02148545
surfpressure		14.1	psi
Risk:	Trap	70%	Seal	55%	Reservoir	60.0%	SourceMigration	80.0%	Total Risk	18.48%
			Risked Expected Outcome:			0.07941024	Tcf riskedrecoverable

Name		Case	area	NetInterval	Porosity	Shc	geomcorrection	ft2/ac	In-place	gas expansion Factor	Rf	Recoverable Reserves	Cond ratio	Cond
SydneyBasinOffshore			acres	ft	%	%			Bcfg			Tcfg	bblo/Mcfg	Mbo
Orca		10	15750	200	20.0%	85.0%	0.9	43560	20.993742	135.9731631	0.8	2.283668404	50	0.11418342
		50	7875	100	15.0%	72.0%	0.8	43560	2.9638224	135.9731631	0.8	0.30225023	50	0.01511251
		90	3937.5	30	10.0%	60.0%	0.75	43560	0.231548625	135.9731631	0.5	0.015742199	50	0.00078711
Reservoir Depth,ft:	7242.2	m:	2208
Deg/100ft:		1.5	psi/ft	0.43300
res temp:		168.6336	res pressure:	3149.9899			Swanson's Mean:	7.55311615	Gas,Bcfgin-place
surftemp		60	degF					0.81072327	Gas,Tcf recoverable			Mbo recov Swanson's Mean =		0.04053616
surfpressure		14.1	psi
Risk:	Trap	70%	Seal	60%	Reservoir	60.0%	SourceMigration	80.0%	Total Risk	20.16%
			Risked Expected Outcome:			0.16344181	Bcf riskedrecoverable

25

Name		Case	area	NetInterval	Porosity	Shc	geomcorrection	ft2/ac	In-place	gas expansion Factor	Rf	Recoverable Reserves	Cond ratio	Cond
SydneyBasinOffshore			acres	ft	%	%			Bcfg			Tcfg	bblo/Mcfg	Mbo
Octopus		10	9158	200	20.0%	85.0%	0.9	43560	12.20702789	135.9731631	0.8	1.327862555	50	0.06639313
		50	4579	100	15.0%	72.0%	0.8	43560	1.723345114	135.9731631	0.8	0.175746515	50	0.00878733
		90	2289.5	30	10.0%	60.0%	0.75	43560	0.134636337	135.9731631	0.5	0.009153464	50	0.00045767
Reservoir Depth,ft:	6645.3	m:	2026
	2026
Deg/100ft:		1.5	psi/ft	0.43300
res temp:		159.6792	res pressure:	2891.5062			Swanson's Mean:	4.39183731	Gas,Bcfgin-place
surftemp		60	degF					0.47140341	Gas,Tcf recoverable			Mbo recov Swanson's Mean =		0.02357017
surfpressure		14.1	psi
Risk:	Trap	60%	Seal	55%	Reservoir	60.0%	SourceMigration	85.0%	Total Risk	16.83%
			Risked Expected Outcome:			0.07933719	Tcf riskedrecoverable

Name		Case	area	NetInterval	Porosity	Shc	geomcorrection	ft2/ac	In-place	gas expansion Factor	Rf	Recoverable Reserves	Condratio	Cond
SydneyBasinOffshore			acres	ft	%	%			Bcfg			Tcfg	bblo/Mcfg	Mbo
Squid		10	11364	200	20.0%	85.0%	0.9	43560	15.1474847	135.9731631	0.8	1.647721127	50	0.08238606
		50	5682	100	15.0%	72.0%	0.8	43560	2.138468429	135.9731631	0.8	0.218080737	50	0.01090404
		90	2841	30	10.0%	60.0%	0.75	43560	0.167067846	135.9731631	0.5	0.011358372	50	0.00056792
Reservoir Depth,ft:	5923.7	m:	1806
Deg/100ft:		1.5	psi/ft	0.43300
res temp:		148.8552	res pressure:	2579.0534			Swanson's Mean:	5.44975314	Gas,Bcfgin-place
surftemp		60	degF					0.58495614	Gas,Tcf recoverable			Mbo recov Swanson's Mean =		0.02924781
surfpressure		14.1	psi
Risk:	Trap	55%	Seal	55%	Reservoir	60.0%	SourceMigration	75.0%	Total Risk	13.61%
			Risked Expected Outcome:			0.07962716	Tcf riskedrecoverable

26

Name		Case	area	NetInterval	Porosity	Shc	geomcorrection	ft2/ac	In-place	gas expansion Factor	Rf	Recoverable Reserves	Cond ratio	Cond
SydneyBasinOffshore			acres	ft	%	%			Bcfg			Tcfg	bblo/Mcfg	Mbo
Blue		10	15522	200	20.0%	85.0%	0.9	43560	20.68983259	135.9731631	0.8	2.250609586	50	0.11253048
		50	7761	100	15.0%	72.0%	0.8	43560	2.920917542	135.9731631	0.8	0.297874798	50	0.01489374
		90	3880.5	30	10.0%	60.0%	0.75	43560	0.228196683	135.9731631	0.5	0.015514312	50	0.00077572
Reservoir Depth,ft:	9075.8	m:	2767
	2767
Deg/100ft:		1.5	psi/ft	0.43300
res temp:		196.1364	res pressure:	3943.9041			Swanson's Mean:	7.4437758	Gas,Bcfgin-place
surftemp		60	degF					0.79898709	Gas,Tcf recoverable			Mbo recov Swanson's Mean =		0.03994935
surfpressure		14.1	psi
Risk:	Trap	50%	Seal	50%	Reservoir	60.0%	SourceMigration	50.0%	Total Risk	7.50%
			Risked Expected Outcome:			0.05992403	Tcf riskedrecoverable

Name		Case	area	NetInterval	Porosity	Shc	geomcorrection	ft2/ac	In-place	gas expansion Factor	Rf	Recoverable Reserves	Cond ratio	Cond
SydneyBasinOffshore			acres	ft	%	%			Bcfg			Tcfg	bblo/Mcfg	Mbo
BlueWhale		10	66262	200	20.0%	85.0%	0.9	43560	88.32300523	135.9731631	0.8	9.607646718	50	0.48038234
		50	33131	100	15.0%	72.0%	0.8	43560	12.46913015	135.9731631	0.8	1.271600301	50	0.06358002
		90	16565.5	30	10.0%	60.0%	0.75	43560	0.974150793	135.9731631	0.5	0.066229182	50	0.00331146
Reservoir Depth,ft:	3804.8	m:	1160
Deg/100ft:		1.5	psi/ft	0.43300
res temp:		117.072	res pressure:	1661.5784			Swanson's Mean:	31.7767989	Gas,Bcfgin-place
surftemp		60	degF					3.41080289	Gas,Tcf recoverable			Mbo recov Swanson's Mean =		0.17054014
surfpressure		14.1	psi
Risk:	Trap	50%	Seal	50%	Reservoir	60.0%	SourceMigration	50.0%	Total Risk	7.50%
			Risked Expected Outcome:			0.25581022	Tcf riskedrecoverable

27

Name		Case	area	NetInterval	Porosity	Shc	geomcorrection	ft2/ac	In-place	gas expansion Factor	Rf	Recoverable Reserves	Cond ratio	Cond
SydneyBasinOffshore			acres	ft	%	%			Bcfg			Tcfg	bblo/Mcfg	Mbo
S Squid		10	15098	200	20.0%	85.0%	0.9	43560	20.12466773	135.9731631	0.8	2.189131782	50	0.10945659
		50	7549	100	15.0%	72.0%	0.8	43560	2.841129562	135.9731631	0.8	0.28973803	50	0.0144869
		90	3774.5	30	10.0%	60.0%	0.75	43560	0.221963247	135.9731631	0.5	0.015090522	50	0.00075453
Reservoir Depth,ft:	8541.1	m:	2604
Deg/100ft:		1.5	psi/ft	0.43300
res temp:		188.1168	res pressure:	3712.405			Swanson's Mean:	7.24044112	Gas,Bcfgin-place
surftemp		60	degF					0.7771619	Gas,Tcf recoverable			Mbo recov Swanson's Mean =		0.0388581
surfpressure		14.1	psi			Risk
Risk:	Trap	60%	Seal	50%	Reservoir	60.0%	SourceMigration	75.0%	Total Risk	13.50%
			Risked Expected Outcome:			0.10491686	Tcf riskedrecoverable

Name		Case	area	NetInterval	Porosity	Shc	geomcorrection	ft2/ac	In-place	gas expansion Factor	Rf	Recoverable Reserves	Cond ratio	Cond
SydneyBasinOffshore			acres	ft	%	%			Bcfg			Tcfg	bblo/Mcfg	Mbo
SHumpback		10	1704	200	20.0%	85.0%	0.9	43560	2.271322944	135.9731631	0.8	0.247071172	50	0.01235356
		50	852	100	15.0%	72.0%	0.8	43560	0.320657357	135.9731631	0.8	0.032700596	50	0.00163503
		90	426	30	10.0%	60.0%	0.75	43560	0.025051356	135.9731631	0.5	0.001703156	50	8.5158E-05
Reservoir Depth,ft:	8692	m:	2650
Deg/100ft:		1.5	psi/ft	0.43300
res temp:		190.38	res pressure:	3777.736			Swanson's Mean:	0.81717523	Gas,Bcfgin-place
surftemp		60	degF					0.08771254	Gas,Tcf recoverable			Mbo recov Swanson's Mean =		0.00438563
surfpressure		14.1	psi			Risk
Risk:	Trap	60%	Seal	60%	Reservoir	60.0%	SourceMigration	60.0%	Total Risk	12.96%
			Risked Expected Outcome:			0.01136754	Tcf riskedrecoverable

28

Portfolio Aggregation

SPE recommends that probabilistic aggregation be confined to the field, property or project level. For the purpose of evaluating the combined potential of all prospects in PEP11 it may be useful to aggregate them statistically. Given the effect of the central limit theorem, the arithmetic summation of field Proved volumes in a large portfolio of properties would typically be much less than the P90 of the probabilistic aggregation of the distributions associated with these same properties. This same ‘portfolio effect’ will cause the arithmetic sum of P10 volumes to be much greater than the P10 of the probabilistic aggregate. (The actual variance is a function of the dependencies defined in the probabilistic aggregation model; the mean of the aggregate is not impacted by dependency variations.). The aggregate sum of the P10 and P90 are summed and re-projected to P2 and P98 respectively, and a P50 representing the summed aggregate is taken from this plot;

==> picture [478 x 395] intentionally omitted <==

----- Start of picture text -----

Sydney Basin Offshore
Probabilistic Reserves Assessment
Portfolio Aggregation
Tcfe
0.1 1 10 100 1000
0
x
10
20
30
40
All Prospects, Reserves Sum, Tcfg
50
Aggregate Portfolio
60
70 Aggregate
P50, 4.2 Tcfg
80
90
x
100
Table 6, Portfolio Aggregation.
Sums aggregated
Tcfg Tcfg
98 P98 0.263697
90 P90sum 2 0.263697 0.41
50 P50 5.05 4.25
10 P10 sum 75.5539 47
2 P2 75.5539
mean 24.76528 15.923
Probability
----- End of picture text -----

Table 6, Portfolio Aggregation.

Table 7, Table of Aggregate Portfolio values.

The Mean of the Portfolio Aggregate in this study is 15.9 Tcfg (Table 7). These are “Undiscovered Prospective Reserves” as defined by the SEC and SPE 2005. The problem is that it is impossible to represent a range of values by a single number, especially a distribution that is skewed or dominated by a few large successful outcomes.

29

If there was a discovery, the equivalent classification in terms of a 3P assessment would be: (Low) P1= 410 Bcfg, P2= 4.25 Tcfg, (Best) and P3 (High)= 47 Tcfg, the equivalencies are allowed and defined specifically by the SPE (Etherington, 2005), these are also by those same definitions and guidelines considered “Undiscovered Prospective Reserves”.

Conclusions

“Entirely covered by the PEP 11 permit (200km long, 8,250km[2] ) the offshore Sydney Basin is a significant exploration area with large scale structuring and potentially multi-Tcf gas and condensatecharged Triassic and Permian reservoirs.

The permit has well defined gas prospects and evidence of the potential for oil. PEP 11 contains all the elements for success needed in world class sized structures. Advent Energy Ltd, through wholly owned subsidiary Asset Energy Pty Ltd, is exercising its exclusive option to increase its interest from 25% to 85% in this highly prospective basin.

A rig contract has been finalised for drilling in Q4 2010.

Approximately A$1 million of sub-bottom profiles and swath data collected by the Federal Government in 2006 has been acquired, and reviews have been extremely positive leading to a reassessment of the petroleum prospectivity of the offshore Sydney Basin. Evidence for active gas seepage has been detected along the PEP 11/continental margin, LandSat analysis has revealed streaming slicks clustered over the Baleen prospect, and inshore thermogenic hydrocarbon seepage has been observed and analysed – the offshore Sydney Basin is now considered an active thermogenic hydrocarbon system.

The exploration programme, if successful, could meet Sydney’s gas consumption needs for the next decade; Permit resource estimates also allow for LNG project consideration. If available estimates were to be realised, PEP 11 would be on a par with some of the giant gas reserves in Australia such as those on the North West Shelf. The potential reward from a successful drilling programme makes this a very attractive and exceptional exploration opportunity in an inimitable geographical location.”

The Block is prospective for gas and if successful, could have giant (> 3 Tcfg field size is a possibility) gas potential. Gas production would displace other market sources and supply GTL facilities.

Our conclusion of block potential is based on the aggregate sum of the Prospective Reserves. The Mean of the Portfolio Aggregate is 15.9 Tcfg recoverable. These are “Undiscovered Prospective Reserves” as defined by the SEC and SPE 2005. The equivalent classification in terms of a 3P assessment would be: (Low) P1= 410 Bcfg, P2= 4.25 Tcfg, (Best) and P3 (High)= 47 Tcfg, the equivalencies are allowed and defined specifically by the SPE (Etherington, 2005), these are also by those same definitions and guidelines considered “Undiscovered Prospective Reserves” and assume successful outcomes.

30

Digital Appendix

Excel File “SydneyBasinPEP11block assessmentFinal” Word File “PEP11 Prospectivity Report2010” http://www.spe.org/industry/reserves/mapping.php www.tbberge.com

Bibliography

Alder, J.D., S. Hawley, T. Maung, J. Scott, R.D. Shaw, A. Sinelnikov, and G. Kouzmina, 1998, “Prospectivity of the Offshore Sydney Basin: A New Perspective”, in AAPEA Journal, pp 68 – 92.

Blevin, J., 2001, “Hydrocarbon Prospectivity of Australia’s Remote Frontier Areas in Offshore East and South-East Australia- Examples from the Basins of Lord Howe Rise”, PESA Eastern Australian Basins Symposium, Melborne, Vic., Nov. 2001. Abstract, p 25-35.

Bradley, Graham, 1992, “Evolution and Hydrocarbon Prospectivity of the Offshore Sydney Basin – NSW/P10” report by Bradley Oilsearch.

Clennell, B., Talukder, A., Dariush, N., Rajput, S., and Pevzner, R., 2009, “Advent Energy Seabed Studies Interim Report”, CISRO study, TOPAS data, April, 2009, Part 1, 11 p.

Etherington, John, Pollen Torbjorn, and Luca Zuccolo, 2005, “Comparison of Selected Reserves and Resource Classifications and Associated Definitions” “Mapping” Subcommittee Final Report- December 2005. Sandwell, D.T., and W.H.F. Smith, “Global marine gravity from retracked Geosat and ERS-1 altimetry; Ridge Segmentation versus spreading rate, J. Geophysical Res., 114, BO1411, doi: 10. 1029/2008JB006008.2009

Exon, N.F., Dickens, G.R., Auzende, J-M, Lafoy, Y., Symonds, P.A., and Van de Beuque, S., 1998, “Gas Hydrates and free gas on the Lord Howe Rise, Tasman Sea”, in PESA Journal, no. 26, pp 148 -156.

Gore “Report on sea floor sampling” unpub June 2010

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O’Brien, G.W., Lawrence, G.M., Williams, A.K., Glenn, K., Barrett, A.G., Lech, M., Edwards, D.S., Cowley, R., Boreham, C.J., and Summons, R.E., 2004, “Yampi Shelf, Browse Basin, North-West Shelf, Australia: a test-bed for constraining hydrocarbon migration and seepage rates using combinations of 2D and 3D seismic data and multiple, independent remote sensing technologies” in Marine and Petroleum Geology, vol 22, (2005) , pub. Elsevier Ltd., pp 517-549.

Quirk, David G., and Richard G. Ruthrauff, 2008, “Toward consistency in petroleum exploration: A systematic way of constraining uncertainty in prospect volumetrics”, in AAPG bull v. 92, NO. 10 (October 2008), pp. 1263-1291.

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CONSENT LETTER

Pangean Resources LLC hereby consents to the use of all or any part of this Resource Evaluation Report, for the Advent Energy Ltd. Block PEP11 offshore Australia as of 15 November 2010, In any document filed with any Securities Commission by Advent.

This document is fully compliant with SEC, SPE, and AAPG reserves estimation guidelines and Industry Best Practices.

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Company name: Pangean Resources LLC Company address: 2036 Ogden St. Denver, CO 80205

Company phone no.; 303-894-8811 Company EIN: 26-2760041 Authorizing Official: Timothy Berge Title: President

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