JOHN KOPCHEFF
MANAGING DIRECTOR
VICTORIA PETROLEUM N.L.
AUSTRALIA
USA
EP 413/L14
ONSHORE NORTH PERTH BASIN, WESTERN AUSTRALIA
VICTORIA PETROLEUM N.L. INTEREST - 5%
EP 413 contains Victoria Petroleum's onshore North Perth Basin oil producing asset, the Jingemia Oil Field contained within Production Licence L14.
Oil production from the Jingemia Oil Filed over the quarter was 176,262 barrels of oil at an average rate of 1,872 barrels of oil per day.
Victoria Petroleum's net Perth Basin production for the quarter totalled 8,813 barrels of oil for an average of 96 barrels of oil per day generating net production income of $458,944 for a net profit of A$52 per barrel.
The Jingemia Oil Field and permit operator Origin Energy is planning to achieve rates of up to 5,000 barrels of oil per day in the fourth quarter of 2005 following the installation of artificial lift facilities and the drilling of the Jingemia-5 and 6 development wells in August and September 2005.
EP 413 covers an area of 539 square kilometres and is situated in the North Perth Basin 7 kilometres to the south of the giant 400 billion cubic feet Dongara Gas Field.
Victoria Petroleum NL considers the permit EP 413 to be very prospective and well placed for the presence of oil and gas, an opinion supported by the October 2002 oil discovery at Jingemia-1, the Arc Energy Hovea and Eremia oil and gas discoveries 5 kilometres to the north east and 15 kilometres to the west in the adjacent offshore permit WA-286-P, the Roc Oil Cliff Head oil discovery.
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.
Subsequently, the Jingemia-2 well to test the southern extent of the field and the Jingemia-3 well to provide water injection pressure maintenance for higher flow rate field production were successfully drilled in September 2003.
Jingemia-4 was successfully drilled as a second oil production well in April 2004, tested at up to 5,000 barrels of oil per day and was brought on production in August 2004 at 2,000 barrels of oil per day. Oil production was increased to 5,000 barrels per day in January 2005, resulting in a net 250 barrels of oil per day to Victoria Petroleum.
Importantly, the results of the extended production tests of Jingemia-1 and Jingemia-4 strongly support a significant upgrade to reserves in the field. There is general agreement by the Origin Energy operated Joint Venture that there is potential for up to 15 million barrels of recoverable oil in the field, of which 70-75% could be located within the EP 413 Jingemia production licence L14.
Victoria Petroleum is confident that proved and probable recoverable reserves mean case of 8 to 11 million barrels are present but require additional development drilling on the 3D seismic data recorded in January 2005 to convert to proved reserves.
Victoria Petroleum based on current development plans, projects estimated net revenue of over $2 million during 2005 from Jingemia Oil Field production
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, Drover and Moorba have been mapped and form additional attractive 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 mean recoverable reserves 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.
Victoria Petroleum NL considers it has a prospective permit in the North Perth Basin, in an exciting re-emergent area of exploration activity surrounded by the significant offshore Cliff Head and onshore Hovea and Eremia oil and gas discoveries and associated infrastructure, and within the permit, the recent Jingemia oil field discovery.
Victoria Petroleum NL is encouraged by the wildcat exploration success rate in excess of 50% in this resurgent phase of drilling in the Northern Perth Basin.
The Jingemia oil discovery is of considerable value to Victoria Petroleum as it has elevated Victoria Petroleum into the ranks of Australia's oil producers with the associated 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 comprises four graticular blocks of 322 square kilometres in area on the Legendre Fault Oil Field trend in the offshore Carnarvon Basin.
The permit contains Victoria Petroleum NL'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 (formerly Marauder), Hellybelly, Lead Z and Jayasurya prospects as promising candidates for further exploration. The Duomonte Prospect is the most advanced being a possible candidate for drilling in the December quarter 2005. The oil potential of the Duomonte Prospect ranges from 22.5 (mean) to 46.7 (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.
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 - 12.5%
WA-261-P covering an area of 299 square kilometres in the offshore Carnarvon Basin is located immediately to the south and adjacent to the Apache Energy/Santos Limited permit WA-209-P containing the 50 million barrel Stag Oilfield, currently producing approximately 10,000 barrels of oil per day.
Chamois-1 was drilled in September 2000, targeting the Jurassic Athol and Triassic Mungaroo formations that are becoming prolific producing horizons in the Carnarvon Basin. While the Mungaroo Formation was dry, the Athol Formation contained approximately 6 metres of net oil pay and the M. Australis sandstone contained about 3 metres of net gas pay.
At present the Chamois Oil Field of up to 3.9 million barrels of recoverable is deemed sub-commercial, but the recovery of oil from the target Jurassic formation provides encouragement that further drilling on the Chamois Prospect may yet result in the discovery of a commercial pool of hydrocarbons in the permit.
A large Stag Sand pinch out trap, south of the 50 million barrel Stag Oil Field was tested by the Ceres-1 well in November 2002. Although only minor oil shows were observed in the Stag sand resulting in the well being abandoned, good oil shows in the underlying Athol sands provided encouragement for the presence of further potential Athol sand oil pools in the permit to the east in the Hestia (formerly Vesta) Prospect.
The Hestia Prospect buttress-stratigraphic trap lies southward of the Ceres-1 location and south westwards of Gats. The C halosa sand only is targeted in the prospect which ranges in size from 11.5 (mean) to 23.2 (P10) million barrels of recoverable oil, if oil is present.
The primary target reservoir at Hestia-1 at 747 metres is in the Athol sandstone found to contain oil in very porous (29% porosity) and very permeable (890md) sands in Chamois-1 15 kilometres to the west.
The Gats Prospect is a structural-stratigraphic trap that resides mainly in WA-261-P (80%) but overlaps in part into the northern adjacent Apache operated Stag Oilfield Production Licence 15-L and WA-209-P. Reserve potential for the Gats Prospect is 17.1 (mean) to 36.9 (P10) million barrels of oil recoverable, if oil is present.
A favourable attribute of the Gats Prospect is the fact that the "Greater Gats" (P2 outline) encompasses the small Antler hydrocarbon accumulation structure in 15-L. Antler 1 intersected 2.4 metres of gas sitting on a 1.4 metre oil column in a good 16.3 metre thick mid M Australis Stag sand reservoir with an oil/water contact at 705.5 metres AHD. For the Gats Prospect, the target reservoir is the Stag Sand, oil productive in the Stag Oil Field, 10 kilometres to the north.
The Hestia and Gats prospects are interpreted from 3D seismic data to have the potential to contain up to 23 and 37 million barrels of recoverable oil respectively, if oil is present.
The Operator of WA-261-P, Apache, has advised the joint venture that the back to back drilling of two shallow (780 to 816 metres depth), non commitment wells in the permit to evaluate both the Hestia Prospect and the Gats Prospect is now scheduled for late August 2005.
If the drilling evaluation of these prospects is successful, any subsequent field development could be tied back to the facilities of the nearby Stag Oil Field which Apache operates and has a majority interest.
Success at Hestia-1, located about half way between the Chamois Oil Field and the Stag Oil facilities, 22 kilometres to the north east, or at Gats-1 12 kilometres to the south of the Stag Oil Field, or both wells, will lower the minimum economic field size requirement to 4.5 million barrels of oil for discoveries in WA-261-P and assuming the oil price is sufficient, may justify the development of the Chamois Oil Field, in addition to a Hestia/Gats oil discovery.
Apache Energy is the Operator of the WA-261-P Joint Venture.
WA-340-P
OFFSHORE CARNARVON BASIN, WESTERN AUSTRALIA
VICTORIA PETROLEUM N.L. INTEREST - 20%
Operator Strike Oil N.L. continued geological and seismic studies on the permit in the quarter to upgrade four Jurassic to Cretaceous age structural stratigraphic leads. Further seismic is to be run in early 2006 over the Sherlock (114 million barrels of oil recoverable, if oil is present) and Peawah (45 million barrels of oil recoverable, if oil is present) prospects to bring these prospects to drill status for possible drilling in the next one to two years.
Strike Oil NL is the Operator of the WA-340-P.
EP 325
OFFSHORE CARNARVON BASIN, WESTERN AUSTRALIA
VICTORIA PETROLEUM N.L. INTEREST - 32.5%
EP 325 covers an area of 1,093 square kilometres in the Exmouth Sub basin of the central Carnarvon Basin and contains the Rivoli Gas Discovery.
The Cooper-1 well was drilled on the Champion Prospect in late December 2004 to a total depth of 2,103 metres and failed to encounter hydrocarbons in the target Birdrong Sandstone reservoir at 1,892 metres.
The Joint Venture is now 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.
Engineering and economic studies are proceeding to determine the feasibility of development of the Rivoli trend to supply natural gas to Exmouth and the region.
Following the farmin of Strike Oil N.L. into the permit by contributing to the drilling of Cooper-1, Strike Oil N.L. is now the Operator of the EP 325 Joint Venture.
EP 41
CARNARVON BASIN, WESTERN AUSTRALIA
VICTORIA PETROLEUM N.L. INTEREST - 88.8% (Part 1); 69.6% (Part 2)
EP 41 parts 1 and 2, cover an area of 393 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, recently in commercial production as Rough Range-1B, lies within EP 41 Part 3, adjacent to EP 41 Part 2.
Following the farmin drilling program in EP 41, Part 3, by Empire Oil & Gas NL, Victoria now retains a 10% interest in two prospects within EP 41 Part 3, a 69.6% interest in Part 2 and 88.7% interest in Part 1.
Current exploration activity is focused on the offshore portion of EP 41 Part 1, 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).
Victoria Petroleum NL is the Operator of the EP 41 (Parts 1 & 2) Joint Venture.
EP 359
CARNARVON BASIN, WESTERN AUSTRALIA
VICTORIA PETROLEUM N.L. INTEREST- 55.85%
EP 359 covers an area of 1,954 square kilometres situated in the Carnarvon Basin predominantly onshore on the Cape Range Peninsula and partially offshore in the Exmouth Gulf.
The up to 25 million barrel Fiona and up to 15 million barrel Suzanna oil prospects identified by Empire Oil & Gas NL are potential drilling targets in EP 359.
Significant petroleum geochemical anomalies have been identified by Empire Oil & Gas NL in the permit along the Rough Range - Bullara Trend and are possible future drilling targets.
Further evaluation of the drilling targets in EP 359 for farm out and drilling in 2005 is in progress.
The production of oil at Rough Range at rates of up to 1,106 barrels of oil per day by Empire Oil NL in May 2000 has highlighted the viability of even small fields in this region to be economic, given the strength of Australian oil prices.
Victoria Petroleum NL 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 4,750 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 NL 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 NL is the Operator of the EP 406 Joint Venture.
SOUTH AUSTRALIA
PEL 86, 87, 89, 104, 111 AND 115
COOPER/EROMANGA BASIN, SOUTH AUSTRALIA
VICTORIA PETROLEUM N.L. INTEREST - 40%
Victoria Petroleum now has the largest gross acreage position of 21,890 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 50,300 square kilometres.
With the 50% exploration success rate on the four well drilling program carried out in 2004 on Victoria Petroleum's South Australian Cooper Basin permit PEL 115, plus the continuing current exploration success rate of 45% in the South Australian Cooper/Eromanga Basin for the ex-Santos acreage, exploration success is anticipated for the minimum five well drilling program planned for 2005 in permits PEL 104, PEL 111 and PEL 115.
The discovery of the Mirage and Ventura Oil Fields in late 2004 and the commencement of Mirage oil production in late April 2005 at a free flow rate of 274 barrels of oil per day and the planned August 2005 start of Ventura oil production at a rate of 180 barrels of oil per day is a good sign for further commercial exploration success in PEL 115.
With the South Australian Cooper Basin as an immediate "core area" of exploration focus for the Company, a further 11 wells are planned to be drilled over the next 3 years, in addition to the planned 2005 "back to back" six well firm permit commitment drilling program.
The fifty 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 twenty two wells planned to be drilled in the next nine months by the industry, including Victoria Petroleum, the South Australian Cooper Basin will be a "hot spot" of drilling exploration activity.
With the drilling activity within and adjacent to Victoria Petroleum's permits, it is considered that Victoria Petroleum is well placed to continue to enjoy exploration success in the forthcoming second half 2005 drilling program.
PEL 104
PEL 104 covers an area of 1,095 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 July 2003 Christies-1 commercial oil discovery and the August 2002 Sellicks-1 2,160 barrels of oil per day discovery by the Beach Petroleum/Cooper Energy consortium 32 kilometres to the south of PEL 104 have significantly upgraded the Permian oil potential on the western edge of the Permian Cooper Basin where PEL 104 is located.
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, with two wells with interpreted by passed gas pay and the other well with oil shows.
A 150 kilometre seismic program to define drilling locations for the 2004 and 2005 drilling program was acquired in February 2004.
Preliminary mapping of this new seismic data and reprocessed seismic data indicate some eight prosects 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 eight prospects and leads, an unrisked cumulative recoverable oil and gas potential for the Hutton, Tirrawarra and Patchawarra targets of up to 119 million barrels of oil and 34 billion cubic feet of gas is interpreted, if oil and gas are present.
To further define potential drilling locations for the two wells planned to be drilled in the second half of 2005 on the Wirraway and Gannet Jurassic oil prospects, up dip and 15 kilometres to the northwest of the Callabonna Jurassic Oil Field, an additional 12.7 kilometres of seismic data is to be acquired in early September 2005.
The Wirraway Prospect as currently mapped has the potential to contain up to 16 million barrels of oil, if oil is present. The Gannet Prospect has the potential to contain up to 10 million barrels of oil, if oil is present.
Following the acquisition, processing and interpretation of this new seismic data into the existing extensive permit seismic database, the PEL 104 Joint Venture will select two drilling locations for drilling in the four quarter of 2005.
To enable this drilling to take place, discussions are taking place with other operators in the area to secure sufficient slots on available rigs to drill the wells approved by the PEL 104 Joint Venture.
A further indication of the high prospectivity of PEL 104 for oil and gas is provided by the successful farm out to industry participants of Victoria Petroleum's 80% of the cost of the first three years work program of 150 kilometres of seismic and two wells to provide Victoria Petroleum with a 40% free carried no cost interest through the 2005 two well drilling program.
Further support for the hydrocarbon prospectivity of PEL 104 was provided by the February 2004 gas discovery by Great Artesian Oil and Gas Pty Ltd at Smegsy-1, 25 kilometres to the south of PEL 104.
Victoria Petroleum NL is the Operator for PEL 104.
PEL 111
PEL 111 lies to the north of and adjacent to PEL 104 and covers 1,185 square kilometres. The permit surrounds the Santos operated Charo Jurassic Oil Field production licences. The February 2004 seismic survey in PEL 104 was extended to include PEL 111 to define potential drilling locations for the several leads and prospects interpreted as present in the permit adjacent to the Charo oil discovery.
Preliminary mapping of the February 2004 seismic data and reprocessed seismic data has identified at least eleven leads and prospects, with an unrisked cumulative recoverable oil and gas potential for the Hutton, Tirrawarra and Patchawarra targets of up to 150 million barrels of oil and 56 billion cubic feet of gas, if oil and gas are present.
Additional seismic data of 30.8 kilometres is being acquired in early September 2005 to further define a drilling location for the Ascender Jurassic oil prospect, up dip and 16 kilometres to the south west of the Jurassic Charo Oil Field.
The Ascender Prospect has the potential to contain up to 14 million barrels of oil, 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 56 billion cubic feet of gas, if gas is present. The Catalina Prospect lies six kilometres to the north of the Santos group Fly Lake-Brolga Gas Field.
It is intended to drill up to two wells in PEL 111 in the second half of 2005, Ascender and Catalina, in keeping with the permit's firm work commitment, subject to Joint Venture approval and rig availability.
Victoria Petroleum NL is the Operator for PEL 111.
PEL 115
PEL 115 is located on the south-eastern edge of the Cooper Basin and covers 1,106 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.
Five prospects with commercial petroleum potential and interpreted unrisked recoverable oil reserves in Jurassic and Permian targets, if oil is present, are ready to drill immediately.
A four well drilling program commenced in late August 2004 going through to mid December 2004. The first well, Hornet-1, defined by 3D seismic, encountering gas in the target Permian sands. Hornet-1 has been cased for production testing when a gas market has been identified.
Exploration drilling activity continued in the south-western part of PEL 115 with Ventura-1, where oil recoveries were made in the primary and secondary target sands, the Murta and Namur, with the Namur recovering oil at up to 352 barrels of oil per day.
Canberra-1 followed, testing a high risk but potentially high reward Permian sand stratigraphic gas trap, but hydrocarbons were not encountered.
The fourth well in the 2004 drilling program, Mirage-1, recovered oil from the Murta Formation on drill stem test.
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. An EPT is planned to commence in August 2005 on Ventura-1 following completion of necessary production infrastructure work such as installation of a beam pump unit, oil storage tanks, oil production facilities and the required statutory approval.
Mirage-1 well is currently producing under the EPT at a conservative rate of 180 barrels of oil per day on free flow with no water, although flow rates of up to 400 barrels of oil per day are indicated as possible from the initial "clean up" production rate of 372 barrels of oil per day over the perforated 16 metre interval from 1,320 metre to 1,336 metres.
Construction of pumping facilities are currently in progress to install a beam pump on Mirage-1 to increase production rates to 250-300 barrels of oil per day.
A review of the Mirage-1 well, geophysical mapping and 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 fill to spill point.
The interpreted recoverable oil reserves for the Mirage Oil Field using this information is a range of recoverable oil reserves from a mean of 1.3 million barrels up to a maximum of 3.6 million barrels.
The potential is present for a further three production wells to be drilled on the Mirage Oil Field to increase oil production and cash flow following joint venture and statutory approvals.
Extended Production Testing of the more modest but commercial Ventura-1 oil well is planned to commence August 2005 with the installation of a surface pumping unit to allow a budgeted production of 200 barrels oil per day.
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 interpreted recoverable oil reserves for the McKinlay/Namur formation of the Ventura Oil Field using this information is a range from a mean recoverable reserve of 150,000 barrels of oil up to a maximum of 1.59 million barrels of oil.
For the Mirage and Ventura oil fields a cumulative maximum potential of up to 5.19 million barrels of recoverable oil has been mapped from the current data with initial cumulative oil production of 450 barrels of oil per day budgeted for these first two wells.
Exploration in the last quarter has focussed on the northern part of PEL 115 in the Nappacoongee High area.
Interpretation of an extensive reprocessed seismic and well control data base has generated the Jurassic Tomcat and Skyhawk oil prospects and the Permian Delta, Hurricane, Harrier gas prospects.
Immediate candidates for drilling are the Jurassic Tomcat and Skyhawk prospects with combined total recoverable reserve potential of up to 57 million barrels of oil, if oil is present.
The Tomcat Prospect is interpreted to have the potential to contain up to a total 20 million barrels of recoverable oil, if oil is present in the Jurassic Namur Sandstone formation in a downthrown fault trap on the southern flanks of the Nappacoongee High.
Confidence in the oil potential of the Tomcat Prospect is 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. 13 million barrels of recoverable oil potential is mapped as present in PEL 115, if oil is present.
The Skyhawk Prospect is mapped as a down thrown fault trap on the northern side of the Nappacoongee High with the potential to contain up to a total of 37 million barrels of recoverable oil, if oil is present. Twenty Seven million barrels of recoverable oil potential is mapped as present in PEL 115, if oil is present.
Tomcat and Skyhawk are planned to commence drilling in October 2005, subject to PEL 115 Joint Venture approval and rig availability.
A 91 square kilometre 3D seismic acquisition program covering the Ventura and Mirage Oil Fields and the next prospects to the east on this highly prospective trend, Lightning and Jindivik has been approved by the PEL 115 Joint Venture to assist in the further delineation and production development drilling of oil reserves in the Mirage and Ventura Oil Fields and further exploration drilling. This 3D seismic survey is to be acquired in mid September 2005 and will assist in the selection of the next three development wells to be drilled on the Mirage Oil Field starting in late 2005.
With Victoria Petroleum's 40% interest in these Mirage and Ventura Oil Fields, Victoria Petroleum's net share of 200 barrels of oil per day will add to Victoria Petroleum's current North Perth Basin average oil production of 96 barrels of oil per day, tripling its net oil production to 300 barrels of oil per day.
In these times of strong oil prices, this increase in oil production will significantly boost cash flow from current oil production
Victoria is also pleased that the Mirage Oil Field appears to a have a recoverable oil reserve potential of up to 3.6 million barrels of oil, 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, Stuart Petroleum Ltd and Beach Petroleum Ltd.
With the Mirage and Ventura Oil Field discoveries, Victoria Petroleum is confident that further oil discoveries will be found with the drilling program to be considered and approved by the PEL 115 Joint Venture in 2005 on this highly prospective Murta oil trend in the southern part of the permit.
This trend extends from west to east, through the Ventura-Mirage-Lightning structures into the Voodoo-Coobowie High area. Seismic reprocessing is planned for this trend to determine possible future exploration drilling targets.
Victoria Petroleum has achieved a 50% oil discovery success rate with the 2004 drilling program in PEL 115. This is a highly satisfactory exploration success rate in keeping with the phenomenal South Australian Cooper Basin "new players" overall exploration success rate of 51%.
With the ongoing minimum two well firm commitment drilling program in this permit, PEL 115 in fourth quarter of 2005, Victoria Petroleum N.L. and its partners look forward to further exploration success in keeping with the current 50% exploration success rate for the permit.
Victoria Petroleum NL is the Operator for PEL 115.
PEL 86, 87, 89
These permits cover a total of 13,500 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.
Victoria Petroleum NL is the Operator for PEL 86, 87, 89.
PEL 88
COOPER/EROMANGA BASIN, SOUTH AUSTRALIA
VICTORIA PETROLEUM N.L. INTEREST - 10%
Victoria Petroleum NL has earned a 10% interest in Petroleum Exploration Licence PEL 88 covering an area of 4,987 square kilometres by contributing to the cost of the drilling of the Eucalyptus-1 well, which commenced drilling in late September 2003.
The Eucalyptus-1 well was drilled to a depth of 2,660 metres and tested the seismically defined Eucalyptus structure.
Target horizons in the Eucalyptus-1 well were Jurassic and Triassic sandstones and some encouragement for the oil bearing potential of the Eucalyptus Prospect had been provided by the combined oil flow rates of 3,210 barrels of oil per day reported from the Triassic sandstone from the Santos James Oil Field discovery well, James-1, 14 kilometres to the west of the proposed Eucalyptus-1 well location.
Although oil shows were observed in the target Jurassic and Triassic sands, the sands were tight with the open hole drill stem test carried out recovering formation water.
The oil shows observed in Eucalyptus-1 along with the James Oil Field oil flows to the west provide encouragement for the potential for commercial reserves of oil to be discovered in the other prospects present in the permit.
Follow up 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 sands.
Exploration focus in the permit has shifted to the south where the Geordie Prospect and the Transit Prospect have been selected as the next drilling targets in the southern part of PEL 88, primarily due to their close proximity to the James Oil Field area. The Geordie Prospect (North and South) is interpreted to have the potential to contain a mean 35 million barrels of oil, if oil is present in Jurassic and Triassic targets. The Transit Prospect is similarly interpreted to have the potential to contain a mean 13 million barrels of oil, if oil is present. Drilling of the Geordie Prospect is planned for early 2006 subject to farm out by Cooper Energy.
Cooper Energy N.L. is the Operator for PEL 88.
PEL 94
COOPER/EROMANGA BASIN, SOUTH AUSTRALIA
VICTORIA PETROLEUM N.L. INTEREST - 15%
Victoria Petroleum N.L. acquired a 15% interest in PEL 94 from Black Rock Oil and Gas PLC. by contributing to the cost of the 2004 seismic survey carried out in the permit.
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.
A 3D seismic survey is current being acquired over the Dunoon Horst to determine any possible drilling targets in PEL 94.
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 NL 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(1) -
35% (Barcoo Block);
24% (Springfield and Regeleigh Block);
15% (Bright Spot Block)
12% (Barcoo Junction Block)
Victoria Petroleum NL has varying interests in ATP 589P, currently pending renewal as ATP 794P, in accordance with the relevant farm outs in ATP 589P which covers an area of 15,301 square kilometres in the southwest Queensland portion of the Cooper / Eromanga Basin.
This Cooper / Eromanga Basin Permit is adjacent to the Energy Equity permit containing the 9.4 million cubic feet per day Bunya-1 gas discovery and the Oil Company of Australia four million cubic feet per day Thylungra-1 gas and condensate discovery.
A highlight of the past quarter was the successful signing of a Native Title Agreement for ATP 794P, by Victoria Petroleum, the first such agreement to be negotiated and signed in Queensland.
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. The 36 million barrel potential Moothandella prospect has been interpreted from this data, if oil is present.
Several other prospects and leads identified in ATP 794P (1) adjacent to the Barcoo Junction area and Moothandella are being been evaluated as potential future farm out drilling targets.
Victoria Petroleum N.L. has entered into a farmin agreement with Bow Energy Ltd. whereby Bow Energy will earn a 25% interest in the Barcoo Block of ATP 794P by free carrying Victoria Petroleum N.L. for its 35% interest through a program of 500 kilometres of seismic reprocessing and the drilling and testing of a well within twelve months of the granting of ATP 794P.
The presence of the southwest Queensland to Mt. Isa gas pipeline confirm the strategic exploration value of the acreage position that Victoria Petroleum NL holds in this area of the Cooper/Eromanga Basin.
Following the official renewal of the permit anticipated for August 2005, exploration drilling is planned to recommence on the Barcoo Junction and Moothandella structures within the next 12 months.
This Queensland permit along with the significant interest held by Victoria Petroleum NL in the South Australian portion of the Cooper/Eromanga Basin makes Victoria Petroleum NL a significant player in the newly resurgent Cooper/Eromanga Basin.
Victoria Petroleum NL is the Operator for the Barcoo, Springfield, Regeleigh Blocks and Bright Spot of ATP 794P, Part 1 and ATP 794P, Part 2.
ATP 736P, ATP 737P, ATP 738P
COOPER/EROMANGA BASIN, QUEENSLAND
VICTORIA PETROLEUM N.L. INTEREST - 80%
ATP 752P
COOPER/EROMANGA BASIN, QUEENSLAND
VICTORIA PETROLEUM N.L. INTEREST - 50%
Permits ATP 736P, ATP 737P, ATP 738P, ATP 752P covering an area of 11,600 square kilometres, were successfully applied for by Victoria Petroleum NL 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.
Although exploration cannot take place in these permits until Native Title agreements are executed, expected to take place within the next twelve months, all of the permits are considered to be very prospective for the discovery of oil and gas.
Permit ATP 752P, ex-Santos released acreage, 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 permit, 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, 2 kilometres to the east of ATP 752P.
Initial geophysical mapping of the northern part of ATP 752P, the Barta Block, indicates the presence of the Vancouver Prospect with an interpreted potential to contain up to 29 million barrels of Jurassic oil, if oil is present.
Victoria Petroleum N.L. has entered into a farmin agreement with Bow Energy Ltd. whereby Bow Energy will earn 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.
Victoria Petroleum NL is the Operator for these permits.
ATP 333P BOWEN BASIN, QUEENSLAND VICTORIA PETROLEUM N.L. INTEREST - 40%
ATP 333P covers an area of 388 square kilometres on the western flank of the Bowen Basin in Queensland. The Reids Dome Gas Field is situated within ATP 333P 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.
Victoria Petroleum has resumed as the Operator of ATP 333P Joint Venture, and entered into a Farmin Agreement with White Sands Petroleum (WSP) whereby WSP will carry out a one well deep drilling program in the northern part of the Reids Dome in late 2005/early 2006. Victoria Petroleum will have a 40% free carried interest through the drilling and testing of the well.
Victoria Petroleum NL is the Operator for ATP 333P.
PL 171
BOWEN BASIN, QUEENSLAND
VICTORIA PETROLEUM N.L. INTEREST - 20%
PL 171 replacing the previous ATP 465P covers an area of 539 square kilometres within the central portion of the Bowen and Surat basins in Queensland.
Queensland Gas Company Limited (QGC), has drilled two Coal bed Methane (CBM) 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 No. 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 produce significant gas flow rates. Trafalgar No. 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 bed methane production.
Lawton-1 had similar results, in which a flow test of interval 129-378 metres produced gas at rates up to 19,400 cubic feet / day.
Current results indicate the Walloon Coal Measures of PL 171 have the potential to contain 350 billion cubic feet of recoverable Coal bed Methane gas reserves.
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 bed Methane 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 White Sands Petroleum. Under this farm out, WSP will re-enter the well and horizontally drill the target Triassic gas sands to earn a 60% interest in any Production Licence granted.
Victoria Petroleum will have an 8% free carried interest through the drilling of this well a test of the ability of horizontal drilling to increase gas flow rates in the known gas bearing Triassic sands.
Roma Petroleum NL 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 NL is the Operator of the Weribone Block.
ATP 574P
BOWEN BASIN, QUEENSLAND
VICTORIA PETROLEUM N.L. INTEREST - 18.75% (Walloon Coals); 30% (Base Walloons to Base Jurassic); 75% (Triassic-Permian)
ATP 574P covers an area of 616 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 states that the Walloon Coal Measures of ATP 574P have the potential to contain 650 billion cubic feet of recoverable coal bed methane gas reserves.
Victoria Petroleum NL has an 18.75% 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 the quarter 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.
Victoria Petroleum NL 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.
Victoria Petroleum N.L. is the Operator of the ATP 574P Joint Venture, with the CBM drilling program being managed by Queensland Gas Company Limited.
ATP 593P
SURAT / BOWEN BASIN, QUEENSLAND
VICTORIA PETROLEUM N.L. INTEREST - 24%
ATP 593P situated on the western margin of the Surat / Bowen Basin covers an area of 3,930 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.
Interpretation of the existing seismic data in ATP 593P identified the up dip Don Juan Prospect as a Hutton/Precipice sandstone four way dip closed structure, up dip to the immediately adjacent strong residual oil shows in the Hutton / Precipice sandstones of Don Juan-1 and Flaneur-1.
Victoria Petroleum N.L entered into a farmin with Oilex N.L. whereby Victoria Petroleum N.L received a 24% free carried interest through the drilling of North Don Juan-1 drilled by Oilex N.L. in September 2004. North Don Juan-1 after testing residual oil shows was plugged and abandoned.
Oilex N.L. is the Operator of the ATP 593P Joint Venture.
ATP 608P
SURAT BASIN, QUEENSLAND
VICTORIA PETROLEUM N.L. INTEREST, 29.688% (Rookwood Block); 24% (Remainder)
ROOKWOOD BLOCK
The permit covering an area of 6,400 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.
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 indicates is 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.
Oilex as Operator commissioned a reservoir and production engineering work to determine the potential sustainable production of the Rookwood 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 Field.
The reports on Rookwood Field by the independent consulting group have been completed and the results are summarised below:
Rookwood South - 1 Drill Stem Test Analysis
The DST interpretation indicates that the sand has good productivity characteristics. The decline in performance is due to the lack of reservoir energy. There is no aquifer support and the oil has little or no associated gas. The only energy is from the expansion of low compressibility oil.
Rookwood Development- Future plans
Over the past few months Rookwood field data have been reviewed by an independent consulting group. Re-interpretation of the original DST and analysis data from echometer build-up surveys have been carried out. The results of these interpretations and a material balance analysis provided insight into:
The only way to improve the recovery factor and hence the reserve volume is to provide additional energy to the reservoir. Oilex is preparing a recommendation for the Joint Venture to agree to a proposal which may accelerate production (potentially up to 80 bpd, the initial rate) and significantly increase reserves (25% recovery would represent an increase of 90,000 STB) by means of a dump flood using one of the other Rookwood wells. Any acceleration in production should lead to an increase in cash flow and a decreased unit operating costs.
Rookwood South-1 was put on production test in November 2004. The current production rate from Rookwood South -1 is still approximately 50 barrels of oil based on 15 hours of pumping every 2-3 days. 1,477 barrels of oil were produced to the end of the June quarter, with total cumulative oil production of 4,619 barrels to 30 June 2005. All oil produced is currently being sold to Inland Oil Refinery.
REMAINDER BLOCK
An independent geophysical and geologic review of ATP 608P commissioned by Oilex has identified structural prospects on ATP 608P to the southeast of the Rookwood Block. The Pinnacle Prospect complex has been identified as a mapped structure with a closure of about 8.4 km2. A smaller prospect named Pinnacle on the broader Pinnacle structure is a clear follow up target to any success at West Pinnacle-1.
It is estimated that the unrisked recoverable reserves for the West Pinnacle Prospect is approximately 8 million barrels and 4 million barrels for the Pinnacle Prospect.
A drilling rig is presently being contracted by the Operator for the drilling of a well on the Pinnacle Prospect in late August 2005.
Bow Energy N.L. has recently entered into the permit with a 20% interest obtained from Oilex N.L. and will participate in the drilling of a well on the Pinnacle Prospect.
Oilex N.L. is the Operator for ATP 608P.
PEL 57
OTWAY BASIN, SOUTH AUSTRALIA
VICTORIA PETROLEUM N.L. INTEREST - 10%
Victoria Petroleum NL has a 10% interest in PEL 57, which covers an area of 794 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.
Lakes Oil N.L. is the Operator of the PEL 57 Joint Venture.
TEXAS
FLOUR BLUFF GAS FIELD DEVELOPMENT PROJECT
ONSHORE GULF COAST BASIN
VICTORIA PETROLEUM N.L. INTEREST: 12.5 - 16.67%
Victoria Petroleum NL 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 10,200 gross acres in extent encompassing both adjacent onshore and offshore production units within a larger Area of Mutual Interest.
An exploration and development program commenced in early February 2005 to significantly increase production and to enlarge the current Flour Bluff Gas Field 92.5 BCF (billion cubic feet) Proved, Probable and Possible (3P) reserve base to an estimated potential 200 BCF 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 June 2005 quarter, 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 the Flour Bluff on the southern outskirts o 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 Flour Bluff Gas Project development program from February 2005 to now early August 2005 calls for a minimum 3 well exploration drilling program targeting multiple sand reservoirs (BG Webb-1 on the West Flour Bluff Gas Field; EFB E-10 and EFB D-24 on the East Flour Bluff Gas Field) as well as a re completion/work over program on 3 wells (E 17-D, D-19 and D-19F).
At the end of this program a re-classification of 3P (proved, probable and possible) reserves will be made and a firm path to a new production profile for the fields should be established by the Operator, i.e. production of around 15 million cubic feet per day and be on target to push this to at least 40 million cubic feet per day the end of the 2006 financial year.
The program in financial year 2006 will flow at a pace to be determined on the results of this initial program and will be discussed at Joint Venture Meeting in Houston in early September. It is envisaged the future programs will be funded from cash flow and project financing.
West Flour Bluff Gas Field Development Program (12.5% WI) - BG Webb 1 Testing/Production
The BG Webb-1 well was a very successful test of the "overview concept" of the West Flour Bluff Gas Field. It showed the existence of 3P reserves of 104 billion cubic feet of recoverable gas in multiple J and K Frio sands as against original 3P reserves estimate of 67 billion cubic feet of recoverable gas in the deep portion of the regional structure of the field itself, a large upthrow, 3 way dipping fault closure.
The well also discovered four new multiple deep Frio sands designated as the K-20 sand series that were logged as potential pay zones (gross 113 metres, net 27 metres) and are the deepest ever drilled in the field. These sands in closure had the potential to add 100-200 billion cubic feet of gas in reserves. Regrettably a series of tests on the K-20 zones returned gas cut water at this location on the structure.
Notwithstanding this, further upside potential of possibly 20 to 30 billion cubic feet of gas could be present, up dip from the current well location and elsewhere in this large closure at depth in the field structure. This remains to be proved by detailed seismic mapping and further drilling of the K-20 sands in the future.
On completion of the evaluation of the K-20 sand series, the testing program on the BG Webb-1 well moved to the new K-15 sand discovery from which 27 standard cubic feet of gas was collected in wire line formation testing. On perforation of casing and the ensuing cased hole test this sand flowed up to 2 million cubic feet of gas per day with 34 barrels of condensate. The well has now been brought on the sales line to the gas gathering plant at 1.7 million cubic feet of gas per day with 28 barrels of condensate.
It is planned to take the well off line and fracture stimulate the sand in late August 2005 to increase production and then put it back on line. From similar fracture stimulations conducted by the Operator on other West Flour Bluff wells, flows of 2 to 4 times pre-stimulation flows are expected
A reserve potential of 30 billion cubic feet of gas recoverable has been estimated for this K15 sand.
East Flour Bluff Gas Field Development Program (16.67% WI) - EFB D-24 & EFB E-10 + 3 well work overs
During the quarter Victoria Petroleum N.L. increased its interest in the the East Flour Bluff Gas Field from 12.5% to 16.67%.
The East Flour Bluff Gas Field is a down faulted, four way dipping closure, lying adjacent and to the east of the West Flour Bluff Gas Field under a shallow sea lagoon (Laguna Madre). It has a present 3P reserve of 23 billion cubic feet of recoverable gas with further upside potential of 44 billion cubic feet of recoverable gas, for a total of 67 billion cubic feet of recoverable gas in Frio Massive, J and K sands.
The two wells in the program, the now completed East Flour Bluff (EFB) D-24 which targeted deep Frio J and K sand reservoirs and the next well EFB E-10, targeting the shallow Frio Massive Sands reservoir, are being drilled from the same pad on an existing production and drilling peninsular built out into the lagoon. Both are directional wells into the structure. They both start vertically and from 305 meters depth will be drilled directionally to reach a maximum angle of 32 or 26 degrees where they will be brought back to vertical to drill through the target reservoirs. The reason for drilling the target reservoirs vertically is to ensure subsequent fracture stimulation of gas pay has maximum effect on gas flow.
The EFB D-24 well was completed in mid June 2005 and has met and exceeded reserve expectations. The EFB D-24 well targeted 3P reserves of 17 billion cubic feet of recoverable gas and additional potential of 14 billion cubic feet of recoverable gas in the lower Frio J and K sands between 10,400 feet (3,170 metres) and 11,000 feet (3,353 metres) measured depth, i.e. a total 31 billion cubic feet of recoverable gas, in the deeper part of the four way dipping closure.
The EFB D-24 well successfully evaluated multiple sand targets principally Frio J (55, 64, 77, 90 and 99) and K 9 series sands. Two of the Frio J sands (90 and 99) are being brought into immediate production. The EFB D-24 well has also indicated untapped potential in the upper Frio 2,450' 8,000', 8100', 8375', 8,400' and 8,500' series sands that require follow up in another phase of drilling. The overall 8,000' series sands are significant. For example, two of the sands having total gas responses on logs of 21% and 8.4% respectively sit above a gas sands that has produced 86 billion cubic feet of gas in the field and now has a 2.4% total gas response on logs.
A multiple completion on the J90 and J99 sands and possibly the J55 sand commenced in the second week of July using a lower cost work over rig. Based on the production history of sands in the field the Operator has suggested initial production from tubing and annulus from the J55, J90 and J99 sands could be in the range of 3 to 6 million cubic feet of gas per day and will not require stimulation by fraccing.
East Flour Bluff (EFB) E-10, is a 7,327 feet (2,234 metres) deep well in measured depth terms, 6,700 feet (2,042 meters) in true vertical depth terms, that will test the remaining potential of 36 billion cubic feet of recoverable gas in the shallow Frio Massives sands in the structure.
If successful it will be brought on production to replace the nearby EFB E-9 well that was junked and abandoned before coming onto full production. The primary sands targeted are the Frio Massive O-1, U and L below 7,000 feet (2,134 metres) measured depth. Drilling commenced in the second week of July.
On completion of drilling and subject to well data, including wire line logs and sampling, a well service rig will move in for well completion, possible fracture stimulations and testing operations which may run for a further 30-60 days.
The re-completion/work over program on 3 wells (EFB D-17, D-19 and D-19 F) is currently scheduled to be carried out after the drilling and o completion of the EFB E-10 well.
Gas Production/Cash Flow
Gas production has fallen recently to 2 million cubic feet a day equivalent which is to be remedied by further work overs on wells with the on site availability of a work over rig for the current program.
A production target of around 15 million cubic feet per day by the end of August from current wells, new production from the present 3 well program and the as yet completed work over program is prognosticated. The Joint Venture's median case of raising production to 40 million cubic feet of gas per day in the next year for a 7-8 year period appears to be realistic. The possible production upside of greater than 40 million cubic feet of gas per day remains a target and depends on the outcome of the development program in financial year 2006. Net monthly revenue cheques to Victoria Petroleum N.L. presently range from US$35-40,000 approximating US$440,000 per annum.
When the Flour Bluff Gas Field joint venture attains production of 40 million cubic feet of gas per day, net production revenue of US$5.5 million net per annum outcome (on a before income tax basis) to Victoria Petroleum N.L. is expected with the proviso of the continuance of the high prevailing USA gas price regime.
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 NL in the U.S.
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 U.S.A. oil and gas market.
As part of this strategy the Flour Bluff Gas Field Development Project joins the Eagle Oil Development Project in California as a potentially very significant US project for Victoria Petroleum NL.
CALIFORNIA
SAN JOAQUIN BASIN
VICTORIA PETROLEUM N.L. INTEREST: 3.75-56.1%
Eagle Oil Pool Development Project
Victoria Petroleum N.L. Interest - 56.1%
Within the prolific oil and gas producing San Joaquin Basin of California, centred on Bakersfield, Victoria Petroleum holds a significant 56.1% interest in 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.
A 14 kilometre seismic strike line was shot over the Eagle Oil Pool in May 2004 and has further defined the up dip extent of the Eagle Oil Pool and the Eagle North-1 drilling location.
The Eagle drilling results to date and the new strike line 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 reserve 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 development target.
With the new seismic data and the completion of the drilling engineering program for Eagle North-1, drilling of this step out development well is planned for mid October 2005 as the farm out efforts made during the last quarter have attracted local industry participants to investigate the opportunity to participate in the Eagle Oil Pool Development Project by the drilling of Eagle North-1.
Victoria Petroleum N.L. plans to have a 20-30% free carried interest through the drilling of and testing of the Eagle North-1 horizontal well.
With the current price of oil around US$50 per barrel (Australia $65 per barrel) and the price of gas in Southern California in excess of US$6.00 per thousand cubic feet (Australian $8.22 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.
San Antonio Prospect Development Project, Salinas Basin
Victoria Petroleum NL Interest - 9.77% BPO, 7.3275% APO
West San Antonio Project
Victoria Petroleum NL 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 the quarter after a decline in oil flow to a non-commercial rate while the Operator considers the suitability of carrying out a stimulation program over the oil bearing Monterey Shale horizons with the aim of increasing oil production.
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.
Victoria Petroleum N.L. is now awaiting advice from the Operator Trio Petroleum on possible future development drilling including the drilling and fracture stimulation of a horizontal well bore in the oil producing reservoir horizon.
Any additional 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.
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 half of 2006 following a 3D seismic survey in the second half of 2005. In the event of the discovery of the oil and gas reserves considered to be present in the Vallecitos development area, production from the new development wells can be tied very quickly in to the existing oil production facilities of the Vallecitos Oil Field.
NON-CALIFORNIA AREAS
Wyoming, Hal Oil Field
Victoria Petroleum N.L. Interest - 100% BPO, 75% APO
Victoria Petroleum NL 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 producing 15 barrels of oil per day. A development well to drain an additional possible 500,000 barrels of recoverable updip oil reserves is being considerd for mid 2006. Further low risk development opportunities of this type are being pursued in the area.
Wyoming, Rock Springs Coal Bed Methane Project
Victoria Petroleum N.L. Interest - 45% BPO, 40% APO
Victoria Petroleum with Sun Resources N.L. through their respective 100% owned USA subsidiaries completed a farmin at the end of the December quarter 2003 with Kestrel Energy Inc to earn a collective 90% interest in 33,000 acres of BLM lease land and other assets (principally an under utilised 27.4 kilometre long, 8 million cubic feet per day capacity pipeline and a 3D seismic data base over half of the farm in area) all of which are located in a 376,320 acre (1,505 square kilometre) Area of Mutual Interest ("AMI") in the western area of the Rock Springs Uplift of the Green River Basin, southwest Wyoming state, USA.
An important facet to a successful exploration outcome is access to market and transport of product. The pipelines in the AMI links into a local market, but more particularly an interstate pipeline through which 1.1 trillion cubic feet of gas per annum passes to western states customers and 0.7 trillion cubic feet of gas per annum passes to eastern states customers.
The pipelines are currently utilised at less than 5% of capacity and are only being fed by conventional deep gas production (which is excluded from the farmin) on the underlying lease land at Green Canyon and Dines.
The main thrust of Sun Resources and Victoria is exploration and development of an indicated 250 billion cubic feet recoverable CBM resources from CBM potential studies of the Upper Cretaceous and Early Tertiary age multi seam coals on the present leases.
During the March 2005 quarter, Sun Resources as Operator, advanced the proposed test of the CBM potential in the project area by drilling first ever CBM test of coals in the project area i.e. the 5,100 foot (1,554 meters) deep Dines CBM #1 well in the Dines area. The well targeted net 73 feet (24 meters) of Fort Union A, B, D and E and Lower Lance age coals keyed off the adjacent Dines #2 gas well logs.
The Lower Lance Coal C appeared to be the best coal with some visible gas bubbles and a gas kick of 45 units, whilst the main Fort Union B coal kicked at 15 units. After reaching total depth, the hole was successfully wire lined logged and left cased for a future testing program.
In the second week of June all results were finally received from the laboratory in Salt Lake City, Utah. The gas contents results, especially those of the deeper Lance coals, were disappointing being sub economic for development of CBM at well depths of 1,225 to 1,550 metres. As a testing program on the Dines CBM#1 well can not be justified on these results a decision will be made on the plugging and abandonment of the well at a Joint Venture meeting in the September quarter along with the validity of carrying out further CBM drilling and well tests on the lease area.
Vallecitos Oil Field Development Project
Victoria Petroleum N.L. Interest - 22.5%
Your company 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 half of 2005 following a seismic survey in the first half of 2005. In the event of the discovery of the oil and gas reserves considered to be present in the Vallecitos development area, production from the new development wells can be tied very quickly in to the existing oil production facilities of the Vallecitos Oil Field.
SAMSON OIL & GAS N.L. /KESTREL ENERGY INC
VICTORIA PETROLEUM N.L. INTEREST - 11%
Victoria Petroleum N.L. has an 11% interest in Samson Oil & Gas N.L which has a 78% interest in Kestrel Energy Inc, a US NASDAQ Listed Company. As reported by Samson Oil & Gas N.L., Kestrel Energy Inc has proved net oil and gas recoverable reserves estimated at 26.1 billion cubic feet of gas equivalent with a Net Present Value of A$60.6 million. The value of these reserves attributable to Samson is A$47.3 million based on 20.4 billion cubic feet of gas equivalent.
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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