QUARTERLY REPORT FOR THE PERIOD ENDING 30 SEPTEMBER 2006

EXPLORATION AND DEVELOPMENT

AUSTRALIA
USA

AUSTRALIA

EP 413/L14
ONSHORE NORTH PERTH BASIN, WESTERN AUSTRALIA
VICTORIA PETROLEUM NL INTEREST - 5%

EP 413/L14
ONSHORE NORTH PERTH BASIN, WESTERN AUSTRALIA
VICTORIA PETROLEUM N.L. INTEREST: 5%

EP 413 covers an area of 508 square kilometres and is situated in the North Perth Basin, seven kilometres to the south of the giant 400 billion cubic feet Dongara Gas Field.

EP 413 contains Victoria Petroleum's onshore North Perth Basin oil producing asset, the Jingemia Oil Field, contained within Production Licence L14.

Victoria Petroleum N.L. considers the permit EP 413 to be very prospective and well-placed for the presence of and gas, an opinion supported by the October 2002 oil discovery at Jingemia-1, the Arc Energy Hovea and Eremia oil and gas discoveries five kilometres to the north east and the Roc Oil Cliff Head Oil Field, 15 kilometres to the west in the adjacent offshore permit WA-286-P.

The 2002 discovery well for the Jingemia Oil Field, Jingemia-1 intersected an oil column of between 29 and 33 metres in good reservoir quality Dongara sandstone at 2,414 metres, confirmed by subsequent wire line logging and production testing.

Following the completion of Jingemia-1 as the first producer on the field at rates of up to 4,000 barrels of oil per day, six other development wells were drilled. Three wells were oil producers and three wells were water injectors drilled for reservoir pressure maintenance.

Gross oil production for the year ended 30 June 2007 was 857,095 barrels at an average of 2,351 barrels of oil per day. The Victoria Petroleum share was 42,855 barrels of oil at an average rate of 118 barrels of oil per day.

Gross oil production during the coming year is expected to average 1,500 barrels of oil per day (75 barrels of oil per day net to Victoria Petroleum N.L.).

Reservoir modelling of the Jingemia Oil Field production strongly supports the premise that a proved and probable recoverable oil reserve in the range of 4.4 to 4.8 million barrels for the Jingemia Oil Field may be present. To date, the Jingemia Oil Field has produced 3.6 million barrels of oil.

Your company considers 90% of these reserves are located within the EP 413 Jingemia production licence L14.

Oil produced from the Jingemia Oil Field is being trucked to the BP Kwinana oil refinery, 360 kilometres to the south.

Adjacent to the Jingemia Oil Field discovery, additional prospects such as Drover and Moorba have been mapped and form attractive oil and gas exploration targets.

Additional prospects and leads in the southern part of the permit, Freshwater Point North and Stockyard, are interpreted from seismic and adjacent drilling data to have the potential to contain a mean recoverable resource of 38 million barrels of oil and 42 billion cubic feet of gas, if oil and gas are present. The Freshwater Point North Prospect is considered to be an onshore extension of the offshore Cliff Head-Vindarra trend, and is planned to be drilled in the fourth quarter of 2007.

The Jingemia oil discovery is of considerable value to Victoria Petroleum as it elevated Victoria Petroleum into the ranks of Australia's oil producers, and the excellent operating margins provide an associated quality cash flow.

Origin Energy is the operator of EP 413.

WA-254-P
OFFSHORE CARNARVON BASIN, WESTERN AUSTRALIA
VICTORIA PETROLEUM N.L. INTEREST: 9.31% (PART 2); 6.17% (PARTS 1, 3 & 4)

The permit was renewed on 12 June 2006 for a further term of five years and comprises four graticular blocks of 324 square kilometres in area on the Legendre Fault oil field trend in the offshore Carnarvon Basin.

The permit contains Victoria Petroleum N.L.'s first offshore oil discovery, Sage-1, drilled in April 1999 in the Sage Block with the testing of 2,155 barrels of 48.8 degree API oil per day from a net 25.5 metre oil column.

Subsequent seismic reprocessing and interpretation indicates the Sage oil discovery to have a potential recoverable oil reserve of between 8.3 and 13.4 million barrels. The potential also remains for a future Sage oil field development and tie-in to any nearby development in WA-254-P Part 2 or adjacent permits, should a significant discovery be made in those areas or with the continued maintenance of current high oil prices.

Within the permit, the Operator Apache Energy has delineated the Doumonte Prospect, Hellybelly, Dr Zeus and Janus prospects as promising candidates for further exploration.

The Duomonte Prospect is the most advanced, being a possible candidate for drilling in 2008. The oil potential of the Duomonte Prospect ranges from 20 (mean) to 44 (P10) million barrels of recoverable oil, if oil is present. Target is the Legendre Formation sand at 2,500 meters depth in a faulted horst block on the high side of the regional Rosemary Fault. The prospect lies approximately 26 kilometres from the Woodside operated Legendre Oil Field.

The Dr Zeus Prospect is a mature M. Australis prospect with structural closure that is interpreted from seismic data to have the potential for a recoverable oil target in the range of 23 (mean) to 52 (P10) million barrels of oil, if oil is present. Additional potential may be present in the deeper Angle Formation. The prospect lies approximately 23 kilometres from the Woodside operated Legendre Oil Field.

Apache Energy N.L. is the operator of the WA-254-P Joint Venture.

WA-261-P
OFFSHORE CARNARVON BASIN, WESTERN AUSTRALIA
VICTORIA PETROLEUM N.L. INTEREST - WITHDRAWN

A Victoria Petroleum review of the remaining potential of WA-261-P covering an area of 341 square kilometres in the offshore Carnarvon Basin indicated that with the significant increase in offshore drilling costs Victoria Petroleum's exploration dollars were best allocated to exploration in the company's core exploration areas in the Cooper Basin, the Surat Basin and the onshore Gulf Coast, USA.

Consequently, Victoria Petroleum N.L. has withdrawn from WA-261-P.

Apache Energy is the Operator of the WA-261-P Joint Venture.

EP 325
OFFSHORE CARNARVON BASIN, WESTERN AUSTRALIA
VICTORIA PETROLEUM N.L. INTEREST - 36.1%

EP 325 covers an area of 1,263 square kilometres in the Exmouth Sub basin of the central Carnarvon Basin and contains the Rivoli Gas Discovery.

The Joint Venture is focussing on the potential for development of the existing and predicted natural gas resources of the Exmouth Gulf. As the Government of Western Australia proceeds with its policy of private electricity generation, a market has developed for natural gas in the Cape Range Peninsular to which EP 325, containing the up to 19 billion cubic feet Rivoli-1 Gas Discovery, is ideally located.

The Commonwealth of Australia represented by the Department of Defence has commissioned Strike Oil as the operator of EP 325 to undertake Front End Engineering Design (FEED) to investigate the feasibility of supplying gas from the Rivoli Gas Field to fuel power generation for the Defence Communication Station located nearby.

If approved, subject to the drilling of a development well on the Rivoli Gas Field either from offshore or onshore, the first gas sales would be anticipated some time in 2009 with the gas price competitive with the current price of diesel.

The permit was renewed during the year for a further five years from March 2006.

Strike Oil N.L. is the Operator of the EP 325 Joint Venture.

EP 443 & EP 434
CARNARVON BASIN, WESTERN AUSTRALIA
VICTORIA PETROLEUM N.L. INTEREST - 88.8% (EP 433); 69.6% (EP 434)

EP 433 and EP 434, previously EP 41 parts 1 and 2 respectively, cover an area of 397 square kilometres situated onshore and partially offshore in the Carnarvon Basin on the Cape Range Peninsula and Exmouth Gulf. The historically significant site of the first major oil flow in Australia, Rough Range-1, currently in commercial production as Rough Range-1B, lying within EP 432 provides evidence for the presence of oil in the area.

Victoria Petroleum retains a 10% interest in two prospects within EP 432, a 69.6% interest in EP 434 and 88.8% interest in EP 433.

Current exploration activity is focused on the offshore portion of EP 433, following up potential oil and gas bearing prospects on tend and to the south west of the Rivoli Gas Field.

These prospects and their hydrocarbon target potentials are Rivoli South West (20 BCF) and Champion West (11 million bbls/21 BCF), if oil and gas are present.

Victoria Petroleum N.L. is the Operator of the EP 433 & 434 Joint Venture.

EP 359
CARNARVON BASIN, WESTERN AUSTRALIA
VICTORIA PETROLEUM N.L. INTEREST - 63.3%

EP 359 covers an area of 1,096 square kilometres situated in the Carnarvon Basin predominantly onshore on the Cape Range Peninsula and partially offshore in the Exmouth Gulf.

In September 2006, Victoria Petroleum and the EP 359 Joint Venture entered into a farmin agreement with Phoenix Resources PLC ("Phoenix") whereby Phoenix can earn a 50% interest in EP 359 by paying 100% of both an Airborne geophysical and ground soil geochemical survey and exercising an option to drilling one well in late 2007/early 2008.

In the event Phoenix exercises its option to drill the well, Victoria Petroleum N.L. will have a 31.65% free carried interest through the drilling of the well to a capped cost of $1.5 million.

Significant hydrocarbon soil geochemical anomalies with associated seismic features have been identified by Empire Oil & Gas N.L. along the Rough Range - Bullara Trend within EP 359, as the Bee Eater, Whaleback, Farnham, Anagonda and Sextant prospects and leads.

The Bee Eater Prospect with a resource of up to 5 million barrels of recoverable oil, if oil is present, has been identified by Empire Oil & Gas N.L. as the next well to be drilled in EP 359 as the Phoenix earning well in early 2008.

The recommencement of production of oil at Rough Range at rates of up to 250 barrels of oil per day by Empire Oil NL in August 2005 in EP 432 immediately adjacent to EP 359 has highlighted the viability of even small fields in this region to be economic, given the strength of Australian oil prices.

Empire Oil & Gas N.L. is the Operator of the EP 359 Joint Venture.

EP 406
CARNARVON BASIN, WESTERN AUSTRALIA
VICTORIA PETROLEUM N.L. INTEREST - 95%

EP 406 covers an area of 4,749 square kilometres situated in the southern part of the Carnarvon Basin over the Bernier and Dorre Islands, the adjacent eastern area of Shark Bay and onshore area adjacent to the town of Carnarvon.

Victoria Petroleum N.L. has an agreement with Pancontinental Oil & Gas N.L, the previous sole permittee whereby Victoria Petroleum N.L has been assigned a 95% interest in the permit and operator ship for free carrying Pancontinental Oil & Gas N.L. through the drilling of the first well in the permit.

Victoria Petroleum N.L. considers the permit is prospective for hydrocarbons in the Birdrong Sandstone formation and underlying Devonian sequence based on the gas shows recorded in wells drilled onshore adjacent to the permit.

An initial stratigraphic well to test the prospectivity of the Birdrong and Devonian formations in the permit is planned to be drilled following renewal of the permit and receipt of the necessary environmental and EPA government approvals and farm out.

Victoria Petroleum N.L. is the Operator of the EP 406 Joint Venture.

SOUTH AUSTRALIA
PEL 86, 87, 89, 94, 104, 111
VICTORIA PETROLEUM N.L. INTEREST - 40%
PEL 115
VICTORIA PETROLEUM N.L. INTEREST - 100%
COOPER/EROMANGA BASIN, SOUTH AUSTRALIA

Victoria Petroleum now has the largest gross acreage position of 24,640 square kilometres in the South Australia Cooper/Eromanga Basin, with a net acreage position second only to Beach Petroleum Ltd.

Within the overall South Australian/Queensland portion of the Cooper/Eromanga Basin Victoria Petroleum maintains its position as the largest gross and net holder of exploration acreage with a gross holding of 49,847 square kilometres.

The 48 prospects and leads identified to date in permits PEL 104, PEL 111 and PEL 115 provide an extensive range of drilling opportunities over the next three years.

With some 30 wells planned to be drilled in the next 12 months by the industry, including Victoria Petroleum, the South Australian Cooper Basin will be a "hot spot" of drilling exploration activity.

The discovery of the Mirage and Ventura Oil Fields in late 2004, the current combined Mirage and Ventura Oil Fields gross production of 206 barrels of oil per day is a good sign for further commercial exploration success in PEL 115.

The September 2006 Growler-1 oil discovery, the first well drilled by Victoria Petroleum in PEL 104 and subsequent April 2007 Wirraway-1 oil discovery is a particularly encouraging start for further exploration in PEL 104 and adjacent PEL 111.

With the 50% exploration success rate for the ten exploration wells drilled to date on Victoria Petroleum's South Australian Cooper Basin permits PEL 104, PEL 111 and PEL 115, plus the current industry exploration success rate of 45% in the South Australian Cooper/Eromanga Basin, further exploration success is anticipated for the next eight well drilling program planned for the Company permits PEL 104, PEL 111 and PEL 115, a "core area" of exploration focus.

PEL 104
VICTORIA PETROLEUM N.L. INTEREST - 40%

PEL 104 covers an area of 1,068 square kilometres and is immediately adjacent to the Tirrawarra Oil Field, the largest oil field in the Cooper Basin and onshore Australia with estimated recoverable reserves of 70 million barrels of oil and 340 billion cubic feet of gas. The block is also immediately adjacent to the Fly Lake Oil & Gas Field and surrounds the Santos operated Callabonna Jurassic oil field production licence.

PEL 104 is considered highly prospective for a Jurassic and Permian oil and gas in view of its immediate proximity to producing oil and gas fields and the presence of prospective Permian and Jurassic section within the major portion of the block.

The extensive database of 2,117 kilometres of 2D seismic and 12 square kilometres of 3D seismic provides a strong initial database for the delineation of prospects within the block. Only three wells have been drilled in the permit by the previous permit holder, Santos and partners, with two wells with interpreted by passed gas pay and the other well with oil shows.

Preliminary mapping of this new seismic data and reprocessed seismic data indicate some twenty nine prospects and leads with Jurassic and Permian target horizons, with the chance for a major Permian stratigraphic pinch out trap in the western portion of the block.

For these prospects and leads, an unrisked cumulative maximum (P10) recoverable oil and gas resource potential for the Birkhead/Hutton, Tirrawarra and Patchawarra targets of up to 30 million barrels of oil and 58 billion cubic feet of gas is interpreted, if oil and gas are present.

Growler-1 was completed for a clean up flow with the April 2007 short term production test achieving a stabilised flow rate of the order of 30 barrels of oil per day. Analysis of the data from this test indicates likely flow rates of the well on pump of between 160 to 250 barrels of oil per day. An Extended Production Test is planned to commence at Growler-1 in December 2007.

The Growler Prospect commenced drilling in September 2006 and rewarded the faith in the oil potential of the western apart of PEL 104 with an oil discovery in the Jurassic Birkhead sands. On drill stem test, 32 barrels of oil were recovered over a two-hour flow period from a 19 metre gross oil column.

The Growler Prospect as currently mapped has the potential to contain a P10 resource of up to 4 million barrels of recoverable oil, if proved by subsequent development drilling. As a first step to the evaluation of the Growler Oil Field, after drilling delays due to unexpected excessive rain, Growler-2 completed drilling in July 2007 and cored a 15 metre gross oil column up dip to Growler-1. Short term production testing of Growler-1 and Growler-2 in August 2007 indicates an initial cumulative production rate of 300 barrels of oil per day when the Growler Oil Field commences production in late December 2007/January 2008.

The Wirraway Prospect was drilled in April 2007 and was an oil discovery from the Birkhead sands at the same horizon as in Growler-1. On open hole drill stem test, the Birkhead sands in Wirraway-1 flowed at a rate of 67 barrels of oil per day from a gross 17 metre interval.

The continuing exploration success in PEL 104 with the April 2007 oil discovery at Wirraway-1 following on from the initial Growler-1 oil discovery in September 2006 and Growler-2 oil discovery in July 2007, provide further confirmation of a possible aerially significant Jurassic "Oil Fairway" in the western portion of PEL 104 extending into the adjacent PEL 111.

This Jurassic "Oil Fairway" covering approximately 1,200 square kilometres is interpreted from seismic data to have the potential with further exploration success to contain a resource of up to 100 million barrels of oil in place, if oil is present. The exploration success rate to date on the Jurassic "Oil Fairway" in PEL 104 stands at 100%.

Additional to the Growler and Wirraway Oil Fields, another two Jurassic prospects have been mapped in PEL 104 and form future attractive drilling targets. Any further oil discoveries in PEL 104 can be connected to the Growler Oil Field production facilities.

Support for the gas prospectivity of the southern part of PEL 104 was provided by the 2006 gas discoveries in the adjacent Great Artesian Oil and Gas Pty Ltd operated permit PEL 106. The Typhoon and Tempest prospects have been defined as attractive farmout candidates for the industry.

Victoria Petroleum N.L. is the Operator for PEL 104.

PEL 111
VICTORIA PETROLEUM N.L. INTEREST - 40%

PEL 111 lies to the north of and adjacent to PEL 104 and covers 1,178 square kilometres. The permit surrounds the Santos operated Charo Jurassic Oil Field production licences.

Mapping of the permit seismic data and reprocessed seismic data has identified 20 leads and prospects, with an unrisked cumulative maximum (P10) recoverable oil and gas potential for the Birkhead/ Hutton, Tirrawarra and Patchawarra targets of up to 40 million barrels of oil and 39 billion cubic feet of gas, if oil and gas are present.

Drilling of the Ascender Prospect up dip and 16 kilometres to the northwest of the Jurassic Charo Oil Field took place in September 2007 without hydrocarbons being encountered. Post drill seismic mapping indicates that as a result of unexpected velocity variations in the area, it is likely that the well was drilled out of closure and the Ascender Prospect remains a future exploration target.

However, more structurally robust prospects such as Gannet and Warhawk, similar in style to the Growler and Wirraway interpreted oil filled structures are now considered higher priority exploration targets.

The Warhawk (P10 resource of up to 2 million barrels of oil, if oil is present) and Gannett (P10 resource of up to 11 million barrels of oil, if oil is present) have been interpreted as potential targets for drilling in the second half of 2007.

The Birkhead sand oil discoveries at Growler-1, 2 and Wirraway-1 in PEL 104, the adjacent permit to the south are considered to have significantly upgraded the chances for exploration success in the western part of PEL 111.

Over 20 Jurassic prospects and leads have been mapped in PEL 111. Seven drillable prospects have been identified with unrisked P50 recoverable reserves of 21 million barrels of oil in the Birkhead formation, if oil is present.

The Catalina Prospect is mature for drilling. The proposed Catalina-1 will test the Catalina Prospect, interpreted from seismic data to have the potential to contain up to 14 billion cubic feet of gas, and 1 million barrels of oil, if oil and gas is present in target Permian Patchawarra Sands. The Catalina Prospect lies six kilometres to the north of the Santos group Fly Lake-Brolga Gas Field.

It is intended to drill a further two Jurassic wells in PEL 111 on the Warhawk and Gannet Prospects in 2008, with drilling of the Catalina Prospect in mid 2008 after farmout, in keeping with the permit's firm work commitment, subject to Joint Venture approval.

Victoria Petroleum N.L. is the Operator for PEL 111.

PEL 115
VICTORIA PETROLEUM N.L. INTEREST - 100%

PEL 115 is located on the south-eastern edge of the Cooper Basin and covers 1,105 square kilometres. The permit is "broken up" into six separate areas and surrounds the oil and gas producing fields at Dullingari, Toolachee, Strzelecki, Della and Kidman with cumulative recoverable reserves of 104 million barrels of oil and 2.5 trillion cubic feet of gas.

The permit represents one of the lowest risk areas for exploration in the Cooper Basin. Initial studies of the available seismic data have identified several leads and prospects with the potential to contain commercial recoverable reserves of oil and gas, if oil and gas are present. The proximity to infrastructure suggests that the economic viability of any exploration success is assured.

PEL 115 contains the Mirage and Ventura Oil Field Petroleum Production Licences (PPL) 213 and PPL 214 respectively.

MIRAGE OIL FIELD - PPL 213
VICTORIA PETROLEUM N.L. INTEREST - 40%

Following on from the completion of the Mirage-1 and Ventura-1 oil discoveries for commercial oil production in mid January 2005, the PEL 115 Joint Venture commenced an Extended Production Test (EPT) in late April 2005 on Mirage-1 with a free flow rate of 274 barrels of oil per day. Subsequently a production licence, PPL 213 was granted over the Mirage Oil Field in August 2006.

Mirage-1 is currently producing on optimised beam pump operation at an average rate of 206 barrels of oil per day following the initial "clean up" production rate of 372 barrels per day over the perforated 16 metre interval from 1,320 metre to 1,336 metres. Production rates on pump of up to 480 barrels of oil per day were achieved in 2006 since continuous production, when not interrupted by road flooding, commenced on 27 July 2005.

An initial review of the Mirage-1 well 2D seismic geophysical mapping and production test data provides an interpretation for the Murta Formation of a net pay of 6 metres over a gross oil column of 17 metres with the Mirage structure mapped as full to spill point.

The interpreted Proved and Probable (2P) recoverable oil reserve for the Mirage Oil Field using this information now stands at 1.3 million barrels up to a maximum of 3.6 million barrels.

The interpretation of the 3D data set suggest that Mirage-1 could be part of a larger feature covering approximately 20 square kilometres that includes the Lightning and Jindivik prospects five kilometres to the north east. Such an area has the unrisked possibility of containing up to 23 million barrels of oil in place, subject to the presence of suitable Murta sand reservoir.

Further exploration drilling was carried out first quarter 2006 to confirm this possibility with the drilling of three Mirage development wells and the drilling of the Lightning-1 and Jindivik-1 exploration wells.

The three production wells, Mirage-2, 3 and 4 drilled on the Mirage Oil Field in 2006 to increase oil production and cash flow were brought on production in December 2006.

Appraisal of the Mirage Oil Field commenced with Mirage-2 well located approximately 500 metres north east of Mirage-1.

The well commenced drilling on 31 January 2006 and reached a total depth of 1,655 metres on 16 February 2006. The objective Murta Formation exhibited oil shows and two cores were cut from 1,322 to 1,337 metres. The well was cased ready for production and is currently awaiting pumping equipment to determine the productivity of the well.

Mirage-3 located 400 metres north of Mirage-2 commenced drilling on 27 February 2006 and reached a total depth of 1,661 metres on 10 March 2006. The well had oil shows in the Murta Formation and a subsequent Drill Stem Test (DST) over the interval 1,317 - 1,300 metres recovered 27 barrels of oil over a two-hour period. The well was cased ready for production.

Mirage-4, located 700 metres south east of Mirage 1, commenced drilling on 19 March 2006 and reached a total depth of 1,447 metres on 30 March 2006. The well-encountered oil shows in the Murta Formation and a DST over the interval 1,319 - 1,330 metres recovered 3 barrels of oil cut mud. The well was cased for production.

In August 2006 fracture stimulation of Mirage-3 and Mirage-4 was performed to hopefully enhance production from the initially modest unstimulated flow rates observed during their respective open hole drill stem test. Both wells were tied into the Mirage Oil Field production facilities in late November 2006 contributing an initial combined production rate of 70 barrels of oil per day to the Mirage/Ventura production facilities.

RESULTS OF THE MIRAGE OIL FIELD PHASE 1 APPRAISAL PROGRAM

The three well appraisal drill program has confirmed the existence of oil saturated Murta Formation over the four wells drilled to date. Each of the wells appear to have a common Lowest Known Oil (LKO) which, after examination of 3D seismic date set coincides with the current 'spill point' mapped for the Mirage structure.

The LKO, when extrapolated onto depth mapping of the 3D seismic data, indicates that there is the possibility that a closed area of some 20 square kilometres exists broadly to the east of the current producing Mirage Oil Field.

This area has been termed the "Greater Mirage-Lightning" structure. Initial evaluation of the oil bearing nature was provided by the drilling of the Lightning-1 and Jindivik-1 wells. Lightning-1 drilled in April 2006 encountered oil shows in the Murta and recovered two barrels of oil cut mud on test. The well was cased and suspended as a potential Murta oil well subject to further evaluation.

Jindivik-1 drilled in May 2006 recovered a small volume of water currently interpreted to be associated with the oil water contact at the Jindivik location and was plugged and abandoned.

Lightning-1 is interpreted to prove the existence of oil in the Murta horizon as is present at Mirage and it can be extrapolated that the Murta Formation in the whole area of 'Greater Mirage' could be oil saturated and have the possibility of containing up to a maximum unrisked 23 million barrels of oil in place, subject to suitable Murta reservoir sand development. Further analysis and study is required and is currently in progress as the drilling program has shown a highly variable Murta reservoir from good reservoir at Mirage-1 to poor reservoir at Jindivik-1.

The "Greater Mirage-Lightning" area drilling results may represent a considerable recoverable reserve net to Victoria Petroleum's 40% working interest. If the "Greater Mirage-Lightning" field is proven, then it is likely an ongoing development program over several years will be required to fully exploit the reserves.

With the successful Mirage three well development program and the subsequent fracture stimulation operation and the placement of the Mirage-3 & 4 development wells on artificial lift with beam pumps, gross oil production for the Mirage Oil Field is currently at 206 barrels of oil per day. Further development drilling is being considered for the first half of 2008 to increase production from the Mirage Oil Field with a Mirage-5 development well likely to be drilled.

VENTURA OIL FIELD - PPL 214
VICTORIA PETROLEUM N.L. INTEREST - 40%

Extended Production Testing of the more modest reserve but commercial Ventura-1 oil well commenced in September 2005 with the installation of a surface pumping unit providing production of 160 barrels of oil per day. Subsequently a production licence, PEL 214 was granted over the Ventura Oil Field in August 2006.

The Ventura-1 well flowed clean 54 degree API oil at rate of 84 barrels of oil per day on a ½ inch choke during the "clean up" production test phase from an interpreted net pay of 2 metres over the perforated oil column interval of 1,365 metres to 1,376 metres in the McKinlay/Namur.

The Ventura-1 well commenced 24 hour operations on 11 October 2005. The well is currently producing 29 barrels of oil per day.

The interpreted recoverable oil reserves for the Murta McKinlay/Namur formation of the Ventura Oil Field using this information range from a Proved and Probable (2P recoverable reserve of 150,000 barrels of oil up to an unrisked maximum 3P recoverable reserve estimate of 640,000 barrels of oil.

RESERVES & PRODUCTION - MIRAGE AND VENTURA OIL FIELD

Gross Oil Production from the Mirage and Venture Oil Field for the year ended 30 June 2007 was 93,838 barrels at an average rate of 257 barrels oil per day.

Victoria Petroleum's 40% interest share was 37,535 barrels of oil at an average rate of 118 barrels of oil per day.

In these times of strong oil prices, this oil production provides a good cash flow.

Victoria Petroleum is also pleased that the Mirage and Ventura Oil Fields have been interpreted to have a recoverable oil reserve range potential of 1.59 million (2P) up to 3.6 million barrels of oil (3P), a field size on the high side of the range of oil fields discovered in the southern part of the South Australian Cooper Basin by the other successful oil explorers and producers, Santos Limited, Stuart Petroleum Ltd and Beach Petroleum Ltd.

PEL 115
VICTORIA PETROLEUM N.L. INTEREST - 100%
EXPLORATION

Exploration during 2006 and 2007 has focussed on the northern part of PEL 115 in the Nappacoongee High area, the southern part of PEL 115 in the Burruna - Lightning structural high area and the Sabre Block in the western part of PEL 115.

Five prospects with an interpreted oil and gas resource potential in Jurassic and Permian targets, if oil and gas are present, are ready to drill immediately as part of the Year 5 permit drilling commitment.

PEL 115 - NORTHERN PART

Interpretation of an extensive reprocessed seismic and well control data base in the northern part of PEL 115 generated the Jurassic Tomcat and Skyhawk oil prospects and the Permian Delta, Hurricane, and Harrier gas prospects.

The Tomcat Prospect is interpreted from seismic data to have the potential to contain up to a total 6 million barrels of recoverable oil, if oil is present in the Jurassic Namur Sandstone formation in an up thrown fault trap on the southern flanks of the Nappacoongee High.

Confidence in the oil potential of the Tomcat Prospect was provided by the interpreted oil water contact observed in the down dip Santos drilled Wilpinnie-3 well which free flowed 785 barrels of oil per day on test before going to water. A maximum of 4.2 million barrels of recoverable oil potential is mapped as present in PEL 115, if oil is present.

As the Tomcat Prospect is interpreted as being shared with the adjoining permit PPL 93 held by Santos and partners, the PEL 115 parties entered into a farmout agreement with PPL 93 parties, whereby the PEL 115 parties would earn a 50% interest in the Tomcat Farmout block of PPL 93 by paying 100% of the cost of Wilpinnie-4, 200 metres up dip from Wilpinnie-3 and proving commercial production greater than 50 barrels of oil per day from Wilpinnie-4.

The PPL 93 parties under the terms of the Tomcat Farmout agreement also have an option to farmin to the portion of the Tomcat Prospect in PEL 115 following the drilling of Tomcat-1 in PEL 115.

Wilpinnie-4 was drilled in January 2007 in PPL 93 adjacent to the northern part of PEL 115 as a test of the Tomcat Prospect. Wilpinnie-4 was drilled and operated by Santos under a farmout agreement with Santos and the PPL 93 parties.

Drilling was successful at Wilpinnie-4 with Wilpinnie-4 cased and suspended as a potential future oil producer.

The potential for the oil pool in Wilpinnie-4 to extend from PPL 93 into PEL 115 is considered promising based on the up dip gross oil column of 18 metres drilled and partially tested in Wilpinnie-4 at an inferred rate of 144 barrels of oil per day.

The results of the drilling of Wilpinnie-4 were as follows:

WIRE LINE AND TEST RESULTS SUMMARY

Initial analysis of the wire line logs, side wall core, FMT data and fluid samples indicates an oil zone of gross 18 metres in the mid Namur sandstone over the interval 1,476 - 1,494 metres RKB with an interpreted oil water contact at 1,494 metres RKB.

DST-1 (1476m to 1487m RKB) recovered approximately 24 barrels of oil during the main four hour flow period. This influx equates to a flow rate of 144 BOPD. The packer seat was lost during start of main flow period.

DST-2 (1468m to 1489m RKB) Tool plugged immediately upon opening. Misrun.

Repeat formation testing near the base of the interpreted oil column at 1,493m recovered a sample of oil and mud filtrate.

Core-1 (1472m to 1487m RKB) was cut in the primary objective the Jurassic Mid Namur Sandstone and exhibited good oil shows and fluorescence in the mid Namur Jurassic sands.

Subsequent production testing by Santos of Wilpinnie-4 in August 2007 recovered formation water. This perplexing result is being analysed and was unexpected given the oil recovery from the open hole drill stem test.

The Skyhawk Prospect is mapped as a down thrown fault trap on the northern side of the Nappacoongee High with the unrisked maximum potential to contain up to 37 million barrels of recoverable oil, if oil is present. Twenty three million barrels of recoverable oil potential is mapped as present in PEL 115, if oil is present.

PEL 115 - Southern Part

In the southern part of PEL 115, interpretation of the 3D Mirage acquired in late 2005 defined the Lightning and Jindivik prospects.

The Jindivik and Lightning structures lie to the east of Mirage. Jindivik is approximately two kilometres to the north-east while Lightning lies about three kilometres to the east.

The Lightning Prospect was drilled in April 2006. Oil shows over the 14 metre interval 1,317 to 1,331 metres were encountered in the Murta. An open hole drill stem test over the interval 1,312 to 1,325.6 metres recovered 1.9 barrels of oil cut mud.

A deeper Permian Patchawarra target did not contain any hydrocarbons.

The recovery of oil from the Murta in Lightning-1 is encouraging for the presence of the interpreted Greater Mirage Murta oil pool.

The well was cased and suspended for future fracture stimulation of the Murta oil zone and subsequent production.

An up dip well to Lightning -1 at the Murta, Hutton at Permian levels, Fury-1 is a candidate for drilling in the second half of 2007. The Fury Prospect is interpreted to have the potential to contain up to 5 million barrels of oil, if oil is present.

The Jindivik Prospect was drilled in May 2006. A small amount of water was tested from the Murta oil show. The well was plugged and abandoned.

Further mapping of the Mirage 3D seismic data in the southern part of PEL 115 has generated the Lancer and Fury prospects as candidates for drilling. The Lancer and Fury prospects lie some 8 kilometres north of the Mirage production facilities and will target Murta, Jurassic and Permian reservoirs. The Lancer and Fury prospect are each interpreted to have the potential to contain a P50 resource of up to 1 million barrels of oil, if oil is present.

The Lancer prospect was drilled in September 2007 with minor oil shows observed in the Permian reservoir.

Following the Mirage and Ventura Oil Field discoveries, Victoria Petroleum is confident that further oil discoveries will be found on this highly prospective Murta oil trend in the southern part of the permit by the 2007 exploration drilling program.

This Murta oil trend extends from west to east, through the Ventura-Mirage-Lightning-Murta structures into the Voodoo-Coobowie High area. Seismic reprocessing is currently being analysed to determine possible future exploration drilling targets.

The additional stratigraphic Murta potential in the greater Mirage-Burunna-Lightning structure, if proved by further drilling, will provide additional potential reserves.

Victoria Petroleum N.L. looks forward to further exploration drilling success in PEL 115 in the first half of 2008.

Victoria Petroleum N.L. is the Operator for PEL 115.

PEL 86, 87, 89
VICTORIA PETROLEUM N.L. INTEREST - 40%

These permits cover a total of 13,566 square kilometres and lie to the north and west of permits PEL 104, PEL 111 and PEL 88.

The permits cover a huge area of under explored but prospective Eromanga Basin sediments. Drilling density is low with only three wells having been drilled, one with recorded oil shows. Data review of the sparse seismic and well control in these permits continues with the south eastern corner of PEL 89 possibly lying within the Jurassic "Oil Fairway" currently being explored in the adjoining permit to the south, PEL 111.

Victoria Petroleum N.L. is the Operator for PEL 86, 87, 89.

PEL 88
COOPER/EROMANGA BASIN, SOUTH AUSTRALIA
VICTORIA PETROLEUM N.L. INTEREST - 10%

Victoria Petroleum N.L. has a 10% interest in Petroleum Exploration Licence PEL 88 covering an area of 5,002 square kilometres.

The oil shows observed in wells drilled within the permit, such as Eucalyptus-1 along with the adjacent Santos James Oil Field oil flows provide encouragement for the potential for commercial reserves of oil to be discovered in the prospects present in the permit.

The Santos James Oil Field discovery well, James-1, reported a combined oil flow rate of 3,210 barrels of oil per day from Triassic Sandstones, a target in the southern part of PEL 88.

Prospects to the north of the James Oil Field and the Eucalyptus-1 well are the Acacia Prospect with the potential to contain recoverable oil reserves of up to 15 million barrels, if oil is present and the Casuarina Prospect with the potential to contain recoverable oil reserves of up to 18 million barrels, if oil is present.

Very large structures associated with the Haddon Downs surface anticline in the north of PEL 88 are also of exploration interest, with the potential to contain significant recoverable oil reserves, if oil is present.

Following on from the July 2004 133 kilometre 2D seismic survey, the Kitson Prospect was drilled in May 2005 in the northern part of PEL 88 without encountering hydrocarbons in the target Jurassic.

Exploration focus in the permit then shifted to the south where the Geordie Prospect and the Transit Prospect were mapped as drilling targets in the southern part of PEL 88, primarily due to their close proximity to the James Oil Field area.

Geordie-1 was drilled in February 2006 to a total depth of 2,476 metres. Minor oil shows were observed and the well was plugged and abandoned.

The Transit Prospect is interpreted to have the potential to contain a mean recoverable 13 million barrels of oil, if oil is present in Jurassic and Triassic targets.

Victoria Petroleum remains confident that an oil pool with be discovered in PEL 88 with more drilling.

Cooper Energy N.L. is the Operator for PEL 88.

PEL 94
COOPER/EROMANGA BASIN, SOUTH AUSTRALIA
VICTORIA PETROLEUM N.L. INTEREST - 15%

PEL 94 covering an area of 2,710 square kilometres lies in the southern part of the Cooper Basin adjacent to PEL 113 containing the Harpoono Murta Oil Field.

Current exploration in the permit is focussed on the northern part of the permit adjacent to the southern part of PEL 113 containing the recent Harpoono-1 Murta Formation oil discovery by Stuart Petroleum and Cooper Energy.

The Harpoono Oil Field lies on the northeast-southwest trending Dunoon Horst, which straddles the border of PEL 113 and PEL 94. Recent exploration success in the Harpoono-2 and 3 step out wells provides encouragement for hydrocarbon prospectively in the adjacent PEL 94.

A 3D seismic survey was acquired over the Dunoon Horst in August 2005 and the Tunkallila and Telowie prospects drilled in January 2007. Both wells were plugged and abandoned although a minor Murta oil recovery on test from Telowie-1 provides encouragement for further exploration in the permit.

Exploration drilling will now focus on the prospects mapped on the extension of the oil productive Dunoon Horst into the northern part of PEL 94 adjacent to PEL 113.

The Dunlop Prospect is mapped as a Murta prospect shared by PEL 94 and PEL 113 and may possibly be drilled by the PEL 113 permitees in 2008.

Beach Petroleum Limited is the Operator for PEL 94.

QUEENSLAND
ATP 560P
EROMANGA BASIN, QLD
VICTORIA PETROLEUM N.L. INTEREST - MCIVER BLOCK - 50%

This 100 square kilometre sub block of permit ATP 560P is located in the central Eromanga Basin of southwest Queensland.

Evaluation of the future exploration potential of the prospects in the McIver Block is in progress.

Victoria Petroleum N.L. is the Operator for the McIver Block.

ATP 560P
EROMANGA BASIN, QLD
VICTORIA PETROLEUM N.L. INTEREST - UELEVEN BLOCK - 17%

This 105 square kilometre sub block of permit ATP 560P is located in the central Eromanga Basin of southwest Queensland.

Further evaluation of the prospects and leads in the Ueleven Block is planned by the Operator for the Ueleven Block, Lakes Oil N.L.

ATP 794 (ex ATP 589P)
COOPER / EROMANGA BASIN, QUEENSLAND
VICTORIA PETROLEUM N.L. INTERESTS:
ATP 794P (Part 1) - 60%
ATP 794P (Part 2) comprised of:
BARCOO BLOCK - 35%
SPRINGFIELD AND REGELEIGH BLOCK - 24%
BRIGHT SPOT BLOCK - 15%
BARCOO JUNCTION BLOCK - 12%

Victoria Petroleum N.L. has varying interests in ATP 794P, in accordance with the relevant farm outs in ATP 794P which covers an area of 14,947 square kilometres in the southwest Queensland portion of the Cooper/Eromanga Basin. The permit was granted for a 12 year term from 1 November 20005.

This Cooper/Eromanga Basin Permit is adjacent to the 9.4 million cubic feet per day Bunya-1 gas discovery and the 4 million cubic feet per day Thylungra-1 gas and condensate discovery.

Significant Jurassic oil potential has been interpreted to be present in ATP 794P based on the oil shows in the numerous wells drilled in the permit and the extensive seismic data grid.

Several other prospects and leads identified in ATP 794P, Part 2 on the Canaway Ridge have been identified as potential drilling targets.

Victoria Petroleum N.L. entered into a farmin agreement with Bow Energy Ltd, whereby Bow Energy earned a 25% interest in the Barcoo Block of ATP 794P by free carrying Victoria Petroleum N.L. through a program of 500 kilometres of seismic reprocessing and the drilling of Banff-1 in October 2006 to a depth of 1,650 metres. Hydrocarbons were not encountered in Banff-1.

As part of Bow Energy's farmin to ATP 794, Part 2, Bow has assumed the role of operator for ATP 794 and is carrying out this role in an exemplary manner.

Mapping has identified the Eight Mile Prospect on the Canaway Ridge as a prospect worthy of drilling with its potential to contain up to 33 million barrels of oil, if oil is present. Eight Mile-1 is a possible candidate for drilling in 2008.

Within ATP 794P, Part 1, the joint venture has entered into a farmin agreement with Coomooroo Exploration whereby Coomooroo can earn equity in the Moonscape Block by contributing to the cost of an airborne survey, soil geochemical survey, 100 kilometres of seismic and the drilling, testing and completion of three wells.

The presence of the southwest Queensland to Mt. Isa gas pipeline adds to the strategic exploration value of the acreage position that Victoria Petroleum N.L. holds in this area of the Cooper/Eromanga Basin.

This Queensland permit along with the significant interest held by Victoria Petroleum N.L. in the South Australian portion of the Cooper/Eromanga Basin makes Victoria Petroleum N.L. a significant player in the newly resurgent Cooper/Eromanga Basin.

Bow Energy Ltd is the Operator for ATP 794P, Part 1 and the Barcoo, Springfield, Regeleigh Blocks and Bright Spot blocks of ATP 794P, Part 2.

ATP 736P, ATP 737P, ATP 738P
COOPER/EROMANGA BASIN, QUEENSLAND
VICTORIA PETROLEUM N.L. INTEREST - 80%

Permits ATP 736P, ATP 737P and ATP 738P covering an area of 6,611 square kilometres, were successfully applied for by Victoria Petroleum N.L. in early 2003 as part of the Company's strategy to become a major exploration player in the Cooper/Eromanga Basin in Queensland as well as South Australia. This strategy has been successfully achieved.

These permits have been granted following a successful conclusion of Right to Negotiate agreements with traditional owners. Data review of the permits is currently in progress by the operator, Bow Energy.

ATP 752P
COOPER/EROMANGA BASIN, QUEENSLAND
VICTORIA PETROLEUM N.L. INTEREST - 15% AFTER FARMOUT

Following the granting of ATP 752P for a 12 year term on 1 August 2006, a permit covering an area of 3,512 square kilometres and considered to be very prospective for the discovery of oil and gas, planning for a program of seismic reprocessing, acquisition and exploration drilling commenced.

Permit ATP 752P, ex-Santos released acreage is comprised of the Barta Block in the north and Wompi Block in the south.

Victoria Petroleum N.L. entered into a farmin agreement with Bow Energy Ltd, whereby Bow Energy earned a 30% interest in ATP 752P by free carrying Victoria Petroleum N.L. for its 50% interest through a program of 500 kilometres of seismic reprocessing and the drilling and testing of a well.

As part of Bow Energy's farmin to ATP 752P, Bow assumed the role of operator for the permit and carried out this role in an exemplary manner.

Subsequent to the Bow Energy farmin, Avery Resources farmed into ATP 752P to provide Victoria Petroleum with a 25% free carried interest through 100 kilometres of new 2D seismic and the drilling of five wells made up of three wells in the Wompi Block and two wells in the Barta Block.

Subsequent to the Avery Resources farmin, Santos Ltd has farmed into ATP 752P to provide Victoria Petroleum with a 15% free carried interest through a staged farmin program of seven wells and 300 square kilometres of 3D seismic.

The estimated total cost for this farmin work program is $18.5 million.

Santos Ltd is the Operator for ATP 752P.

WOMPI BLOCK

Geophysical mapping of the southern part of ATP 752P, the prospective Wompi Block, indicates the presence of 21 prospects and leads with a cumulative unrisked P10 recoverable potential resource of up to 31 million barrels of oil, if oil is present in the Jurassic target reservoirs. Oil flow rates of up to 3,112 barrels of oil per day from adjacent Jurassic oil fields have been recorded by Santos.

Two farmin wells were drilled in early 2007 at no cost to Victoria Petroleum.

Marracoonda-2 commenced drilling in early 2007 and encountered non commercial oil shows in the target basal Birkhead sands with the recovery of a minor amount of oil and filtrate on drill stem test after reaching total depth of 1,775 metres. The oil shows were deemed to be residual and the well was plugged and abandoned.

The rig then, after severe weather delays due to unseasonable rains and attendant floods, drilled Gamma-1. Gamma-1 was drilled to a total depth of 1,517 metres and penetrated the primary target reservoirs without encountering significant shows. The well was plugged and abandoned.

The Joint Venture then agreed to suspend further drilling in the block until 3D seismic was carried out over the Nora Prospect. The Watson 3D seismic of 67 square kilometres was acquired in May 2007.

The drilling of the two wells under the Santos farmin, subject to the results of the 3D seismic data interpretation is planned for the second quarter of 2008 with Nora-1 being a likely candidate for drilling.

The Nora Prospect is interpreted to have the potential to contain a resource of up to 6.5 million barrels of oil, if oil is present.

BARTA BLOCK

The Barta Block is considered particularly prospective as it lies between the Triassic sands 4,200 barrels of oil per day James Oil Field 15 kilometres to the west and the Jurassic sand 897 barrels of oil per day Cook Oil Field on the permits eastern boundary.

Within the Barta Block, the Yanbee-1 well is interpreted from wire line logs to have untested oil zones in the Jurassic Murta, Hutton and Poolawanna sands. Yanbee-1 will make an attractive exploration target when exploration drilling can commence in the permit, as the Hutton sand flowed 897 barrels of oil per day in Cook-1, two kilometres to the east of ATP 752P.

Geophysical mapping of the northern part of ATP 752P, the Barta Block, indicates the presence of four high oil flow potential prospects with a cumulative P10 recoverable oil reserve potential of up to 10 million barrels, if oil is present.

A 3D seismic survey in conjunction with the adjoining Santos Cook Oil Field 3D was carried out on the Barta Block in October 2006 to further define the interpreted extensions of the Cook Oil Field into the Barta Block. Additional 510 km 2D seismic reprocessing program has detailed 19 leads and prospects in the Barta Block with commercial oil potential. Two of these prospects are to be selected as the drill targets for the first two wells in the Santos/Avery Farmin program.

The Hudson Prospect with an interpreted resource potential to contain up to 11 million barrels of recoverable oil in multiple horizons, if oil is present, is the largest prospect and will be most likely proposed for drilling as one of the first two Santos/Avery Farmin wells in the first quarter 2008 along with possibly the NW Cook Prospect with its potential resource of 5 million barrels of oil, if oil is present.

Santos Ltd is the Operator for ATP 752P.

PL 231
BOWEN BASIN, QUEENSLAND
VICTORIA PETROLEUM N.L. INTEREST - 40%

PL 231, (previously ATP 333P) covers an area of 181 square kilometres on the western flank of the Bowen Basin in Queensland. The Reids Dome Gas Field is situated within PL 231 and based on initial reservoir studies, a reserve of up to 1 billion cubic feet of gas is indicated for the three wells drilled on the Reids Dome Gas Field prior to November 1994.

The 1993 appraisal well in the Reids Dome Gas Field, drilled by Victoria Petroleum, Aldinga North-1, flowed gas at a rate of 1.2 million cubic feet per day.

Victoria Petroleum has assigned operatorship of the PL 231 Joint Venture under the Farmin Agreement with White Sands Petroleum (WSP). Under the farmin agreement WSP will drill the Primero-1 well to 2,700 metres in the northern part of the Reids Dome twinning the original shallow gas discovery well, AOE-1.

Victoria Petroleum has a 40% free carried interest through the drilling and testing of the well.

WSP commenced the drilling of Primero-1 in late June 2006. Early exploration success was encountered in July 2006 with Primero-1 testing a gas flow of 2.8 million cubic feet per day from a shallow gas sand at 150 metres.

Drilling of the deeper target which encountered numerous oil and gas shows in the original heavily mud invaded AOE-1was carried out. Additional gas zones have been intersected in the Reids Dome Beds around 1500 metres.

Following the completion of drilling at Primero-1, an extensive testing program was commenced and will continue to determine the reserves of the Reids Dome Gas Field both at the shallow and deeper horizons with a view to the potential commercialisation of the gas field, subject to sufficient gas reserves being proved.

White Sands Petroleum Ltd is the Operator for PL 231.

PL 171
BOWEN BASIN, QUEENSLAND
VICTORIA PETROLEUM N.L. INTEREST - 20%

PL 171 replacing the previous ATP 465P covers an area of 161 square kilometres within the central portion of the Bowen and Surat basins in Queensland.

Queensland Gas Company Limited (QGC) has drilled two coal seam gas (csg) wells and one core hole in the Walloon Coal Measures of the Cherwondah Anticline, with the drilling of Trafalgar-1, Lawton-1 and the core hole Lawton-2.

Trafalgar-1 intersected 19.6 metres of coal within the four upper seams of the Walloon Coal Measures. Testing of the well during drilling produced gas at a rate of 20,000 cubic feet per day (570 cubic metres per day) and water production measured at 360 barrels per day. These results are typical of the initial flows from wells drilled in the Powder River Basin in the USA.

After dewatering, these wells can produce significant gas flow rates. Trafalgar-1 demonstrated that the coals of the Walloon Coal Measures are gas saturated and the 360 barrels of water production indicates that the coals have good permeability. Gas saturation and good permeability are the essential criteria for successful coal seam gas production.

Lawton-1 had similar results, in which a flow test of the interval 129-378 metres produced gas at rates up to 19,400 cubic feet per day.

Current results indicate the Walloon Coal Measures of PL 171 have the potential to contain an inferred resource of up to 200 billion cubic feet of recoverable coal seam gas, if gas is present. Coal seam gas exploration will resume in November 2007 with the drilling of a coal seam gas well.

Interest in methane gas produced from coal deposits is increasing in Australia, particularly in the Bowen Basin. PL 171 is adjacent to the Peat coal seam gas field, which is now producing sales gas into the pipeline linking it to Brisbane markets.

The Permian Triassic gas potential of the Cherwondah Anticline as seen from the gas flow of 250,000 cubic feet of gas per day from North Cherwondah-1 is the subject of a farm out entered into with Dome Petroleum PLC. Under this farm out, Dome Petroleum proposes in November 2007 to re-enter the North Cherwondah-1 well and re-drill the target Triassic gas sands with a high angle sidetrack and fracture stimulation to earn a 60% interest in any Production Licence granted over the Triassic gas sands.

Victoria Petroleum will have an 8% free carried interest through the drilling of this well, a test of the ability of high angle drilling and fracture stimulation to increase gas flow rates in the known gas bearing Triassic sands.

Victoria Petroleum N.L. is the Operator of the PL 171 Joint Venture.

ATP 471P
WERIBONE BLOCK, SURAT BASIN, QUEENSLAND
VICTORIA PETROLEUM N.L. INTEREST - 20.65%

This 12 square kilometre sub-block of the greater ATP 471P located in the Surat Basin in central Queensland contains the Yarrabend-5 gas well, which may be part of the Yarrabend Gas Field in adjacent licences to the north.

Due to recent ownership changes in the Joint Venture, the testing of Yarrabend-5 has been postponed indefinitely.

In the event that commercial rates of gas production are observed for Yarrabend-5, it is expected that the Yarrabend-5 would be tied into the existing production infrastructure and gas pipeline network 1.5 kilometres to the north.

Mosaic Oil N.L. is the Operator of the Weribone Block.

ATP 574P
BOWEN BASIN, QUEENSLAND
VICTORIA PETROLEUM N.L. INTEREST - 30% (Walloon Coals); 30% (Base Walloons to Base Jurassic); 75% (Triassic-Permian)

ATP 574P covers an area of 231 square kilometres within the central and southern portions of the Bowen and Surat Basins in Queensland.

Queensland Gas Company Limited (QGC) drilled two CBM farmin wells, Pinelands-1 and 3, which flowed gas at up to 10,600 cubic feet of gas per day, and the Pinelands-2 core hole to further evaluate the coal absorption properties of the target Walloon Coal Measures.

QGC's independent expert's report of July 2000 infers that the Walloon Coal Measures of ATP 574P have the potential to contain an inferred resource of up to 350 billion cubic feet of recoverable coal seam gas, if gas is present.

Victoria Petroleum N.L. has a 30% interest in the Walloon Coals.

Within the Base Walloons to Base Jurassic section of the permit, North Giligulgul-1 was drilled in February 2004 by Oilex N.L. under a farmin agreement with Victoria Petroleum, which provided Victoria Petroleum with a 30% free carried interest.

Minor oil shows were encountered in the target Jurassic Precipice Sandstone and the well was plugged and abandoned.

During 2005, the JV partners entered into a partial farm-out of the Jurassic portion of the permit with White Sands Petroleum Pty Ltd (WSP) to do a work over on the Conloi-1 oil well. The farm-out covers a small area of 40 acres (16.2 ha) centred on the Conloi-1 well to earn 60% of our interest. The farm out involves a work over of the Conloi-1 well and is aimed at reperforating the formerly producing interval to gather pressure and fluid data that will be an important data point for the assessment of the remainder of the blocks oil potential.

In the event that there is no production, the well will be plugged and abandoned at no cost to the JV. Operations to prepare the Conloi-1 well for re-perforating over the oil bearing Jurassic oil sequence commenced in July 2005 and have been subsequently suspended until the appropriate work over equipment is available. Operations by WSP are planned to resume in early 2008.

Victoria Petroleum N.L. retains a 70% interest in the deeper Triassic and Permian sequence in the permit where a major structure with significant Permian gas potential is interpreted.

Bow Energy Ltd is the Operator of the ATP 574P Joint Venture.

ATP 593P
SURAT / BOWEN BASIN, QUEENSLAND
VICTORIA PETROLEUM N.L. INTEREST - 45% WALLOON COAL MEASURES; 24% SUB WALLOON COAL MEASURES

ATP 593P situated on the western margin of the Surat/Bowen Basin covers an area of 617 square kilometres. The primary targets in the permit are structural traps along the Merivale High trend, which is the southern extension of the Merivale Fault system, along which the majority of the Denison Trough fields are located. Ten leads and prospects have been mapped along the Merivale High trend with the potential to contain up to 84 million barrels, if hydrocarbons are present. Victoria Petroleum has a 24% interest in these prospects.

Evaluation of potential drilling targets including coal seam gas resource potential continued during the year.

Bow Energy Ltd is the Operator of the ATP 593P Joint Venture.

ATP 771P VICTORIA PETROLEUM N.L. INTEREST - 45% WALLOON COAL MEASURES; 100% SUB WALLOON COAL MEASURES

ATP 771P situated on the western margin of the Surat/Bowen Basin covers an area of 541 square kilometres. The permit is considered to have coal seam gas resource potential.

In June 2007, Victoria Petroleum entered into a coal seam gas (CSG) joint venture in the Surat Basin on its ATP 593P and ATP 771P permits with Bow Energy Ltd. Victoria Petroleum and Bow Energy have combined their interests in these two permits in the northwest Surat Basin and in partnership with Roma CBM Pty Ltd (RCBM) have formed the Don Juan CSG Joint Venture.

The Don Juan CSG Joint Venture is located immediately adjacent to previously discovered CSG gas flows and 25 km northwest of Sunshine Gas's Lacerta CSG field. The Walloon Coal Measures, the primary target coal seams in the area, are interpreted to be present and gassy over all of the Don Juan CSG Joint Venture area at depths between 250 to 600 metres.

Assuming only 60% of the 1,158 km2 Don Juan CSG Joint Venture area contained a modest 1 BCF of gas per square kilometre, the area has the potential to contain a resource in excess of 650 BCF of methane gas, if gas is present.

A minimum of two and possibly three test core holes are planned to be drilled in October 2007 and assuming the results of the core hole tests are as anticipated, the intention is to commence a coal seam gas pilot by the end of 2007 with the goal to prove a commercial gas deposit in 2008.

The Don Juan CSG Joint Venture is the first of several joint ventures planned to bring to commercial production the approximate gross resource of 1.2 TCF of CSG interpreted as present within Victoria Petroleum's Surat basin permit interests, ATP 593P, ATP 771P, ATP 574P and PL 171 in Queensland's premier Coal Seam Gas production area, the Surat Basin.

Bow Energy Ltd is the operator for ATP 771P.

ATP 608P
SURAT BASIN, QUEENSLAND
VICTORIA PETROLEUM N.L. INTEREST, 29.688% (Rookwood Block); 24% (Remainder)

The permit covering an area of 1,680 square kilometres is located in the western Surat Basin adjacent to several oil fields and includes the zero edge of the Boxvale sandstone, the primary producing reservoir in the area. Several four-way dip closures are mapped and ready for drilling.

ROOKWOOD BLOCK

Victoria Petroleum N.L. entered into a farmin with Oilex N.L., whereby Victoria Petroleum N.L received a 29.69% free carried interest through the drilling and completion of Rookwood South-1.

The interpreted untested Boxvale sandstone oil zone in Rookwood-1 was confirmed by the successful drilling of Rookwood South-1 in September 2004 by Oilex N.L.

A Drill Stem Test in the Boxvale Sandstone recovered oil in the pipe at an interpreted rate of 352 barrels of oil per day. Rookwood South-1 was completed for production testing in late November 2004.

A subsequent four well appraisal drilling program indicated that the Rookwood Oil Field is probably limited to the area surrounding Rookwood South-1 and restricted to a 2 metre sandstone unit at the top of the Boxvale Sandstone.

Bow Energy as Operator commissioned a reservoir and production engineering work to determine the potential sustainable production of the Rookwood Oil Field, including any remedial action that may be taken to improve production flow rates. Poor seismic data coverage over the area limits the benefit of further mapping of the Rookwood Oil Field.

Bow Energy plans to increase field production by optimising the beam pump on the Rookwood South-1 well and also recomplete Rookwood North-1 as a potential oil producer.

During the year, production from the Rookwood South-1 well was 3,997 barrels of oil. All of the oil produced is currently being sold to Inland Oil Refinery.

STRATTON BLOCK

An independent geophysical and geologic review of ATP 608P commissioned by Bow Energy has identified the Stratton North Prospect located up dip from Stratton-1. Stratton-1 had excellent oil shows in the Jurassic aged Basal Evergreen sandstone which appears not to have been properly tested at the time of drilling. Bow estimates the up dip potential to be up to 6.5 million barrels, if oil is present.

Other prospects include the Myong Prospect, located west and adjacent to the Rookwood Oil Field. The prospect is interpreted as a large structural/stratigraphic trap with the potential to contain up to 26 million barrels of recoverable oil, if oil is present.

Bow Energy Ltd is the Operator for ATP 608P.

ATP 805P
SURAT BASIN, QUEENSLAND
VICTORIA PETROLEUM N.L. INTEREST - 15%

ATP 805P covers an area of 937 square kilometres in the western Surat Basin.

Two previously drilled wells within the ATP 805P area, Donga-1 and Donga-2 had small oil recoveries in Triassic aged sandstone above economic basement, indicating that oil has migrated into the permit. The Riverslea Oil Field is located adjacent to the area and the recent Rookwood Oil discovery is located to the northwest in the immediately adjacent permit ATP 608P.

Victoria Petroleum earned a 15% interest in the permit by contributing to the cost of Donga-3 drilled in October 2005.

Donga-3 was drilled to a depth of 1,630 metres and from a drill stem test of the Moolayember oil sand at a depth of 1,580-1,582.5 metres recovered 23 barrels of light 45oAPI oil and 39 barrels of drilling mud filtrate and water.

The Donga-3 oil discovery was brought into production on a long term test in February 2006. Following this test to determine from the pressure decline curve and the production rate the potential reserve volume and the sustainable production rate the well was shut-in. Results to date are being evaluated.

The average daily rate of production was 20 barrels of oil per day during the 30 day production test with 601 barrels of oil produced from Donga-3.

The Donga Prospect is interpreted from current seismic data to have the potential to contain between 0.7 and 0.9 million recoverable barrels of oil, with 8 to 9 wells required to drain the Field. Reservoir analysis and stimulation studies are in progress to determine the optimum production regime for the Donga Oil Field prior to any further development activity.

Donga-4 was drilled in the fourth quarter 2006 and intersected the oil sands of the Donga Oil Field. Evaluation of the well and its contribution to the Donga Oil Field reserves is in progress with the advice from the operator that plans are in progress to complete Donga-3 and 4 for oil production in late 2007.

Bow Energy Ltd is the Operator for ATP 805P.

PEL 57
OTWAY BASIN, SOUTH AUSTRALIA
VICTORIA PETROLEUM N.L. INTEREST - 10%

Victoria Petroleum N.L. has a 10% interest in PEL 57, which covers an area of 408 square kilometres in the onshore Otway Basin, adjacent to the Origin Energy operated Katnook/Hazelgrove producing gas fields.

Exploration has now focussed on the north-western portion of the area with the Honans Scrub seismic program of 60 kilometres over the Orana Prospect carried out in the second quarter of 2002.

A geochemical survey was carried out in early 2006 and has delineated several anomalous areas coincident with seismically mapped structures. A well is planned to be drilled in 2008 after farmout.

Lakes Oil N.L. is the Operator of the PEL 57 Joint Venture

UNITED STATES OF AMERICA

TEXAS
FLOUR BLUFF GAS FIELD DEVELOPMENT PROJECT
ONSHORE GULF COAST BASIN
VICTORIA PETROLEUM N.L. INTEREST: 12.5 - 16.67%

Victoria Petroleum N.L. through its wholly owned Denver based subsidiary Victoria Petroleum USA, Inc. ("Victoria Petroleum") in early December 2004 entered into a Purchase and Sale Agreement to acquire a 12.5% Working Interest "WI" (8.75% Net Revenue Interest "NRI") in the relatively low risk, large, Flour Bluff Gas Project, onshore/offshore Gulf Coast, Texas, USA.

The Flour Bluff Gas Project is located adjacent to Corpus Christi in Nueces County on the Gulf Coast, South Texas. Project leases are some 41 gross square kilometres (10,200 acres) in extent encompassing both adjacent onshore and offshore production units within a larger Area of Mutual Interest.

The exploration and development program commenced in early February 2005 has increased production and enlarged the current Flour Bluff Gas Field 92.5 BCF (billion cubic feet) Proved, Probable and Possible (3P) reserve base of 96.9 billion cubic feet equivalent (BCFe) to an estimated total potential of 210 BCFe from multiple gas bearing sands between 1,980 and 3,500 metres in the large regional structure that underlies the Flour Bluff Gas Field leasehold sands.

During the year, Victoria Petroleum N.L., through its USA subsidiary, continued its participation in the first phase of the redevelopment of the old giant gas field at Flour Bluff on the southern outskirts of Corpus Christi, Gulf Coast, Texas. The three fields (west Flour Bluff, East Flour Bluff and Pita Island) are estimated to have produced between 1.2-1.3 trillion cubic feet of gas and 60 million barrels of oil (mainly as condensate) from more than 40 separate reservoirs in the Oligocene Frio Formation, mostly in shallow depths above 6,800 feet (2,100 metres) at collective production rates of up to 110 million cubic feet of gas per day.

The initial first phase Flour Bluff Gas Project development program from February 2005 to January 2006 was completed with the drilling of EFB E-10, EFB D-19, D-24 wells and the Petty #2 frac.

The Phase 2 development program will commence with the drilling of Flour Bluff-1 on the West Flour Bluff Gas Field, planned for early 2008. Flour Bluff-1 is the first well of an 8 to 9 well program over the next 18-24 months targeting 48.9 billion cubic feet gas equivalent of proved, probable and possible (3P) recoverable reserves. By the end of the development program, production from the field could be up to 20 million cubic feet per day. The commencement date of the drilling program and the rate of drilling are influenced by the availability of drilling rigs and partner approval.

GAS PRODUCTION/CASH FLOW

Gas production averaged 1.6 million cubic feet a day equivalent during the year.

To increase current gas production, a work over and completion of new gas reserves in the D-13, EFB D-24, EFB D-19 and Smith #1 wells was carried out in order to increase field production to 3 million cubic feet of gas per day. The work over of these wells has been successful with additional production of 2 million cubic feet per day observed during the past year.

With development success at Flour Bluff, Victoria Petroleum N.L. will be well positioned to benefit from gas sales to meet the strong US domestic demand for natural gas, now and into the future.

The Flour Bluff Gas Project has all the hallmarks of being a significant cash flow generator for Victoria Petroleum N.L. in the US.

The acquisition of the interest in the Flour Bluff Gas Project is a continuing part of Victoria Petroleum's strategy to build up low risk oil and gas development projects in the energy hungry USA oil and gas market.

As part of this strategy the Flour Bluff Gas Field Development Project joins the Vallecitos and Eagle Oil Development Project in California along with the West Florence Oil and Gas project in Colorado as a potentially very significant US development project for Victoria Petroleum N.L.

TEXAS
MARGARITA GAS EXPLORATION PROJECT
ONSHORE GULF COAST
VICTORIA PETROLEUM N.L. INTEREST: 20 - 37.5%

Project Margarita, is the first project of the Wandoo Joint Venture consummated in December 2005. Twenty five leads and prospects have been recognised in prospective stratigraphic/structural settings at various depths ranging from 1,000 to 4,000 metres in 428km2 of onshore Gulf Coast, 3D seismic.

Historic production and plays in the project area and environs are Frio and Vicksburg sands at less than 1,800 metres depth. Deeper Yegua and Wilcox sands between 1,800 and 4,000 metres are under explored and only four wells deeper than 2,400 metres have been drilled in the area of seismic coverage and were drilled pre 3D seismic.

Several low risk Frio shallow targets around 1 BCF recoverable with attractive economics have been identified, if gas is present.

A number of deeper targets have high impact Wilcox sands targets with 100 to 208 BCF gas potential, if gas is present.

The Wilcox targets are on the same trend where Strike Oil has recently enjoyed exploration success to the north east of the Margarita area.

During the year, successful drilling of the first three shallow Frio exploration wells based on 3D seismic data took place with El Viejito-1, and Dos Dedos-1 being gas discoveries and Milagro-1 being an oil discovery. The Milagro-1 well has been connected to sales line and are producing at a rate of 0.6 million cubic feet per day.

Subsequently the drilling of shallow Frio 3D derived prospects resumed in mid May 2007 with gas discoveries at Agavero-1 and Dona Carlota-1. Dona Carlota-1 has tested at rates of up to 1 million cubic feet of gas per day and is to be tied into the adjacent sales gas pipeline. Agavero-1 production tested at 0.65 million cubic feet per day and has been connected to the sales gas pipeline.

This successful shallow drilling program with a cumulative production rate potential of 1.6 million cubic feet per day will be a precursor to a further three shallow well Frio exploration program in early 2008 and after farmout a drilling program planned for late 2007 on deeper Wilcox prospects with much larger potential recoverable gas reserves in the range of 20 to 200 billion cubic feet.

REDBACK GAS EXPLORATION PROJECT
ONSHORE GULF COAST
VICTORIA PETROLEUM N.L. INTEREST: 20-37.5%

Following the successful outcome of the initial shallow drilling program on the Margarita Gas Exploration Project area, with Wandoo Energy, Victoria Petroleum has entered into a further joint venture with Wandoo Energy. The new joint venture, called "Redback", is on a 393 km2 3D seismic data base covering a small portion of an again highly productive, onshore Gulf Coast oil and gas trend in South Texas. This regional trend to date has produced some 1.2 billion barrels of oil and 6 trillion cubic feet of gas from near surface to 10,000 feet depth.

The object of the joint venture is to target the very under explored prospective stratigraphy below 10,000 feet depth in the Redback 3D seismic data base. A pilot screening program on the Redback 3D seismic data by Wandoo Energy, has already recognised several prospects with possible significant hydrocarbon potential.

A number of these prospects have multiple targets with high upside potential for both gas and accompanying condensate. One prospect has an upside to 116 billion cubic feet of gas with 6 million barrels of condensate (i.e. up to 152 bcfge). On trend to the Redback area are production analogues of the recognised prospects from the same targeted stratigraphic level. Individual wells from these production analogues have produced up to 10 bcfg plus 250,000 boc at high initial daily well production rates of up to 10 million cubic feet of gas per day with 300 barrels of condensate.

Interests in the Joint Venture are Victoria Petroleum 37.5%, Sun Resources 37.5% and Wandoo Energy 25%. The terms of the Joint Venture are similar to the Margarita Gas Exploration Project whereby Sun Resources and Victoria Petroleum will fund a six months evaluation of the seismic data ending 30 October 2007 for a first right of refusal to earn a 75% WI in any individual prospects generated within the Redback area by drilling a well on individual prospects on a non promoted "ground floor" basis. For successful wells, Victoria Petroleum and Sun Resources will carry part of Wandoo's 25% WI (i.e. a 10% WI) in the first well on any prospect to completion.

COLORADO
WEST FLORENCE OIL AND GAS PROJECT
VICTORIA PETROLEUM N.L. INTEREST: 17.5 - 25%

Victoria Petroleum N.L. holds a 25% working interest in 12,000 acres and up to 17.5% working interest in 13,000 acres in the West Florence Oil and Gas Project in the Florence sub basin of the Denver Basin, approximately 160 kilometres south of Denver, Colorado, USA.

The project area is to the west of the Florence Oil Field which produced approximately 15 million barrels of oil from fractured shales of the Pierre Formation up to the 1940's.

The potential petroleum resource for the West Florence play as estimated by the Operator Mountain Petroleum Corporation ranges between 100 BCF and 200 BCF of recoverable gas in the sands of the Muddy 'J' and Dakota Formation, and cumulatively up to 15 million barrels of oil for the three secondary targets, the Pierre, Niobrara and Codell Formations, if oil or gas be present.

The Operator drilled the first well in the project, West Florence-1 to a total depth of 1,957 metres in June 2007.

Multiple oil and gas shows were observed in all target formations including the Pierre Shade, Niobrara and Cadell, Muddy 'J' and Dakota sands.

The subsequent testing and fraccing program resulted in the recovery from swabbing operations of oil and water from four zones in the Upper Cretaceous section of the well between 1,646 and 1,737 metres.

The Operator, Mountain Energy, placed the well on production with the October 2007 installation of a pump to produce oil from the Codell Formation that previously reported from successful swabbing operations an estimated rate of inflow into the well of 25 barrels of oil over the 12 hour swabbing period with associated gas flow. The initial production rate for the well was 30 bopd with 100 bbls of water.

The first up success with West Florence-1 from these zones is promising for the interpreted presence of a large oil and gas development opportunity over the large acreage position held by the project, if oil and gas is present.

Victoria Petroleum envisages a scenario based on adjacent historical production of numerous modest rate producing oil wells providing cumulative significant oil production. Further testing and drilling is required to establish this scenario.

The joint venture is now planning the drilling of a further well in the West Florence acreage in November 2007 to advance development of the project.

CALIFORNIA
SAN JOAQUIN BASIN
VICTORIA PETROLEUM N.L. INTEREST: 3.75-20%

With the current price of oil around US$70+ per barrel (Australia $80+ per barrel) and the price of gas in Southern California in excess of US$6.00 per thousand cubic feet (Australian $7.89 per thousand cubic feet), with a strong likelihood of higher gas prices being revisited in the future, commercial success is most likely for any sustained oil and gas flows discovered in any of the wells in the California drilling program.

In order to maximise your Company's chances of a commercial success, the current California drilling program focus is on "close in" drilling adjacent to proven oil production as in the Eagle, San Antonio, and Vallecitos areas.

EAGLE OIL POOL DEVELOPMENT PROJECT
VICTORIA PETROLEUM N.L. INTEREST - 20%

Within the prolific oil and gas producing San Joaquin Basin of California, centred on Bakersfield, Victoria Petroleum holds a 20% interest in the Eagle North-1 appraisal well that commenced drilling early January 2006 on the Eagle Oil Pool Development Project.

During 2001, drilling of the company's Eagle Oil Pool Development Project resulted in the successful drilling of a 271 metre horizontal well bore leg into the Gatchell Sandstone oil reservoir, oil and gas productive at the rate of 223 barrels of oil per day and 0.7 million cubic feet per day in the initial Mary Bellocchi-1 well drilled in 1986.

Well site analysis indicated an interpreted 90 metres of oil pay to have been drilled. Regrettably, technical difficulties encountered while drilling have prevented immediate testing of the interpreted oil pay.

The Eagle drilling results to date and seismic and geological data confirm the Eagle Oil Pool Development Project is essentially low risk in geologic nature with the risks being of an engineering nature associated with deep horizontal drilling.

The commerciality of the oil and gas reserves present in the Eagle Oil Pool is dependent on the oil and gas flow rates obtained from horizontal well bores drilled into the field. For a successful horizontal well, flow rates of up to 1,000 barrels of oil per day are anticipated.

The indicated potential recoverable resource of up to 34 million barrels of oil and 58 billion cubic feet of gas for the Eagle Oil Pool make the Eagle Oil Pool an attractive appraisal and development target.

At Eagle North-1, an initial vertical "pilot" well was drilled in January 2006 to a depth of 4,200 metres with wire line logs confirming the presence of oil bearing sand at 4,080 metres. Production casing was then run and the well production tested for five days with the recovery of approximately 2 litres of crude oil and no water. The failure of the perforating guns to perforate the lower Mary Bellocchi Gatchell Sand or a local low permeability zone may have contributed to the low oil flow. Following production testing, several sidetracks were required to build a medium radius curve to allow 4-½ inch liner to be set into the top of the lower Mary Bellocchi oil sand. A 300 metre horizontal well commenced drilling with good oil shows encountered over 177 metres of the lower Mary Bellocchi oil sand until drilling operations stopped at 4,386 metres.

The horizontal well bore was then partially cased and a test attempted without success due to the mechanical failure down hole.

The production test was being carried out over 177 metres (580 feet) of the lower Mary Bellocchi Gatchell oil sand in the horizontal well bore over the interval from 4,209 to 4,386 metres (13,810 to 14,390 feet).

The interval being tested consist of 72 metres (235 feet) of lower Mary Bellocchi Gatchell oil sand cased behind the 4-½ inch liner from 4,209 to 4,291 metres (13,810 to 14,045 feet) and the 105 metres (345 feet) of open hole lower Mary Bellocchi oil sand from 4,281 to 4,386 metres (14,046 to 14,390 feet) which is being tested as a barefoot completion out of the base of the 4-½ inch liner at 4,386 metres (14,045 feet).

A deep work over rig arrived on location in late September 2006 to resume testing of the well as the oil sand remains untested. It was not possible to retrieve the unfired casing guns in the cased hole. The well has been suspended and left in a condition satisfactory for a future re-entry and side track to allow the oil zone behind casing to be retested.

Further work on the Eagle Oil Pool Development Project during the year focussed on an independent report evaluating past operations and proposing a forward drilling and evaluation program.

This report recommends a further well to be drilled to further appraise the Eagle Oil Pool with its potential recoverable resource of up to 23 million barrels of oil and 85 billion cubic feet of gas, if oil and gas is present.

Two well site options are available for potential farminees, to drill Shannon-1 and Tulago-1.

Shannon-1 is a low risk step out well to the 1986 Mary Bellochi-1 discovery well (223 bopd & 0.7 mmcfd), testing the potential 1.2 million barrels of oil and 3.8 billion cubic feet of gas for the small structural closure on the regional stratigraphic trap if, oil and gas is present. Tulago-1 is an aggressive step out 1.2 kilometres up dip of the Mary Bellocchi-1 well, testing the mean case (8.8 million barrels of oil and 33 bcfg) potential stratigraphic trap, if oil and gas is present. The exact timing of either well is currently unknown, but is tentatively placed in early 2008 and is subject to a successful farmout and availability of a deep rig and experienced drilling personnel.

Current Eagle Oil Pool Development Project equities are Sun Resources (10%), Operator Victoria Petroleum N.L. (20%), Empyrean Energy (38.5%), First Australian (15%), Lakes Oil N.L. (15%) and a USA private investor (1.5%).

In the event of significant oil production rates from any further wells drilled on the Eagle Oil Pool, a 3D seismic survey will be acquired to determine the location of an interpreted further nine development wells.

Victoria Petroleum N.L. is the operator for the Eagle Oil Pool Development Project.

SAN ANTONIO PROSPECT DEVELOPMENT PROJECT, SALINAS BASIN
VICTORIA PETROLEUM N.L. INTEREST - 5.5%

WEST SAN ANTONIO PROJECT
VICTORIA PETROLEUM N.L. INTEREST - 5%

In 2003, Victoria Petroleum N.L. participated in the drilling of the San Antonio Prospect, which resulted in the discovery of a cumulative net oil bearing interval of 314 metres in the target Vaqueros Sand and Monterey Shale horizons.

Fracture stimulation and testing operations to determine the ability of these target horizons to produce oil to surface at commercial rates were carried out in 2003 and resulted in the San Antonio-1 well being placed on pump production on 1 August 2003 with the well producing an initial oil flow of 135 barrels of 38º API oil per day from a total fluid production of 300 barrels of oil and water per day.

Oil production was subsequently suspended during 2003 after a decline in oil flow to a non-commercial rate at 2003 oil prices. With the current high oil prices, the Operator, Trio Petroleum is now carrying out a further stimulation program over the oil bearing Monterey Shale horizon and recommenced intermittent oil production in April 2006. Subsequent to this event, oil production has been suspended. The operator has proposed the drilling of an additional well on the San Antonio Project in the first half of 2008.

Encouragement for the ability of the San Antonio fracture stimulated horizons to produce greater quantities of oil are provided by the adjacent production of 500 million barrels of oil from the San Ardo Field.

Any oil and gas produced to surface from the San Antonio Oil Field in the future, that is in excess of what can be trucked to the San Antonio Oil Field, can utilise the oil and gas pipeline to the San Antonio Oil Field that runs within 400 metres of the San Antonio-1 well site.

FAIRGROUNDS PROSPECT
VICTORIA PETROLEUM N.L. INTEREST - WITHDRAWN

Victoria Petroleum N.L. participated in the drilling of the Fairground Prospect in September 2006 in the Kern County Fairgrounds, Bakersfield. The well encountered oil shows while drilling in the target Miocene sands over four discrete intervals providing a cumulative interval of 8 metres of potential oil pay in good sand reservoir over the interval from 1,562 to 1,582 metres with accompanying good drilling break and gas show.

The well was subsequently drilled to its total depth of 1,667 metres, wireline logs run to evaluate the oil shows and the well was cased for cased hole production testing. The well has not produced any significant oil flow on production testing during the quarter and has been declared non commercial.

Trio Petroleum is the operator of both San Antonio projects and the Fairgrounds Prospect.

VALLECITOS OIL FIELD DEVELOPMENT PROJECT
VICTORIA PETROLEUM N.L. INTEREST - 22.5%

Victoria Petroleum N.L. considers successful development drilling on the relatively shallow western and southern areas of the Vallecitos Oil Field has the potential to increase recoverable oil reserves by up to 5 million barrels and increase oil production at rates up to 1,200 barrels of oil per day assuming a successful 3 well development program.

The next Vallecitos development well is planned to be drilled in the first quarter 2008 following a planned 3D seismic survey in late 2007. In the event of the discovery of any oil and gas reserves, production from the new development wells can be tied very quickly into the existing oil production facilities of the Vallecitos Oil Field.

WYOMING
HAL OIL FIELD
VICTORIA PETROLEUM N.L. INTEREST - 100% BPO, 75% APO

Victoria Petroleum N.L. participated in a low risk oil development workover in Wyoming which resulted in initial net oil production to the Company of 50 barrels of oil per day. The Hal Oil

Field is currently suspended. A development well to drain an additional possible 500,000 barrels of recoverable updip oil reserves is being considered for the first half 2008.

OTHER ASSETS
SAMSON OIL & GAS LIMITED
VICTORIA PETROLEUM N.L. INTEREST - 5.3%

Victoria Petroleum N.L. has a 5.3% interest in Samson Oil & Gas Limited, an ASX Listed Company which is an active oil and gas development and production company with its producing properties in the Rocky Mountain region of Wyoming, Oklahoma and New Mexico.

GREENEARTH ENERGY LIMITED
VICTORIA PETROLEUM N.L. INTEREST - 33.3%

Victoria Petroleum N.L. has a 16 2/3% interest in the public unlisted geothermal energy company Greenearth Energy Limited, managed by Lakes Oil N.L.

Greenearth Energy was granted three promising geothermal exploration permits (GEP's) in Victoria. Two of these licences in the LaTrobe Valley, GEL 12 and 13 are adjacent to and containing the Trifon-2 well that has flowed steam and hot water at 90 degrees C from the relatively shallow depth of 2,200 metres. The third GEP is adjacent to Geelong, a major industrial energy consumer. Greenearth Energy is planned to list in December 2007 with a priority entitlement to Victoria Petroleum shareholders.

Cash and current investments as at September 30, 2007 to fund planned exploration and development drilling activities, as follows:

Yours faithfully,

JOHN KOPCHEFF
MANAGING DIRECTOR
VICTORIA PETROLEUM N.L.

For information on Kestrel Energy, Inc. U.S. drilling and development activities visit the Kestrel Energy, Inc. website at www.kestrelenergy.com

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