JOHN KOPCHEFF
MANAGING DIRECTOR
VICTORIA PETROLEUM N.L.
AUSTRALIA
NEW CALEDONIA
USA
EP 413
ONSHORE NORTH PERTH BASIN, WESTERN AUSTRALIA
VICTORIA PETROLEUM N.L. INTEREST - 5%
EP 413 contains Victoria Petroleum's current oil producing asset.
Oil production from the Jingemia Oil Filed increased across the quarter reaching over 4,000 barrels of oil per day on 27 November 2004.
Victoria Petroleum's net production for the quarter totalled 124,242 barrels of oil equivalent to an average of 155 barrels of oil per day generating net production income of $630,000.
The field and permit operator Origin Energy is planning to achieve rates up to 5,000 barrels of oil per day by March 2005.
Recording of a 3D seismic survey commenced in January 2005. With this 3D data, a development well, Jingemia-5 will be drilled as soon as possible thereafter in late March 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 No. 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 3,000 barrels per day in October 2004. It is planned to further build production up to 4,500 barrels of oil per day in late 2004, resulting in a net 225 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, 85-90% of which could be located within the newly issued 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 and 3D seismic to convert to proved reserves. Victoria Petroleum projects an estimated net revenue of over $3 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.
These leads are already the subject of exploration activities with the interpretation of the detailed gravity survey carried out recently assisting in defining the extent of these and other leads in the areas of future 2D and 3D seismic acquisition.
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 75% wildcat exploration success rate 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 cashflow.
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.
A review of the seismic and geological data over the permit is currently in progress by the operator, Apache Energy. The recent exploration success at Hurricane-1 has upgraded several prospects in the permit. It is likely hat a well will be drilled in the permit in the second half of 2005.
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 45 million barrel Stag Oilfield, currently producing approximately 20,000 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 Vesta Prospect.
Further work carried out by the Operator has defined in addition to the Vesta Prospect a large Stag Sand pinch out trap, the Gats Prospect. These 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 Vesta and Gats Prospects are located on a migration pathway within WA-261-P updip to strong oil shows to the west recorded in nearby Ceres-1 and the oil pool at Chamois-1.
The primary target reservoir at Vesta-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. For the Gats Prospect, the target reservoir in the Stag Sand oil productive in the Stag Oil Field, 10 kilometres to the north.
Vesta-1 is planned to be drilled in mid 2005, to be followed by Gats-1.
Success at Vesta-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 Vesta/Gats oil discovery.
Apache Energy is the Operator of the WA-261-P Joint Venture.
WA 312 P
OFFSHORE CARNARVON BASIN, WESTERN AUSTRALIA
VICTORIA PETROLEUM N.L. INTEREST - 18.3%
WA-312-P is located in the Dampier Sub-basin of the offshore Carnarvon Basin, Northwest Shelf, Western Australia and covers an area of 1,850 square kilometres.
Lying approximately 50 kilometres to the north of Karratha, the permit comprises 23 graticular blocks over 1,850 square kilometres, and is situated less than 1 kilometre south of the 80 million barrels recoverable Wandoo Oil Field, currently producing 24,000 barrels of oil per day, the Hampton-1 gas discovery, and 11 kilometres to the east of the 45 million barrels recoverable Stag Oil Field, currently producing 15,000 barrels of oil per day.
The permit has had only three wells drilled in it and is considered lightly explored given the proximity to the prolific oil and gas fields to the north and west.
The permit has been granted for a six-year term and the initial three years exploration will be taken up with a program of seismic re-processing and acquisition to mature a drilling target.
A 3D seismic survey was carried out in the western portion of the permit and has indicated several promising leads and prospects in this area, with the 9 million barrels of oil potential Southeast Wandoo Prospect, 3 kilometres from the Wandoo Platform, considered an immediate future drilling candidate for farmout in 2005.
Interpretation of the seismic data acquired during this survey, combined with the existing extensive 2D seismic database indicates the presence of up to sixteen prospects and leads. Among the sixteen leads and prospects mapped to date within the Permit there are a number of prospects and leads at the Wandoo and Stag oil producing horizons that will be the focus of exploration attention as they are in an area of favourable infrastructure. Eight of the sixteen leads have a cumulative unrisked recoverable oil reserve potential of up to 145 million barrels of oil.
Victoria Petroleum NL is the Operator of the WA-312-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 the December 2004 quarter over the Sherlock (114 million barrels of oil recoverable) and Peawah (45 million barrels of oil recoverable) 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, and west of the Champion Prospect. 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 farmout 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 operatorship 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 farmout.
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 their planned commercial production in March 2005 at a combined production rate of 500 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 six 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 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 pinchout 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 mid 2005, additional seismic data is to be acquired in May 2005.
Following the acquisition, processing and interpretation of this new seismic data into the existing extensive permit seismic data base, the PEL 104 joint Venture will select two drilling locations for drilling in the second half 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 joint venture.
A further indication of the high prospectivity of PEL 104 for oil and gas is provided by the successful farmout 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.
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 Paranta-1, 10 kilometres to the south of PEL 104.
The successful farmout resulting from the industries perceived high prospectivity of the block and adjacent gas discovery by Great Artesian Oil and Gas Ltd will see drilling in PEL 104 well ahead of the permit commitment work program with planning currently underway for a mid 2005 well, subject to rig availability.
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 is being acquired in May 2005 to further define a drilling location on a Jurassic oil prospect in the area of the Charo Oil Field.
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 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 southwestern 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.
Both Ventura-1 and Mirage-1 were completed for commercial oil production in mid January 2005.
Following on from the completion of the Mirage-1 and Ventura-1 oil discoveries for commercial oil production, the PEL 115 Joint Venture plans to carry out an Extended Production Test (EPT) in mid March 2005 on the Mirage-1 and Ventura-1 wells following completion of necessary production infrastructure work such as oil storage tanks, oil production facilities and the required statutory approval.
It is planned to produce the Mirage-1 well under the EPT conservatively at 300 barrels of oil per day on free flow although flow rates of up to 400 barrels of oil per day are indicated as possible from the initial "clean up" production data over the perforated 16 metre interval from 1,320 metre to 1,336 metres.
The Mirage-1 well flowed clean oil at rate of 372 barrels of oil per day on a ½ inch choke during the "clean up" production test phase.
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 2.3 million barrels.
The potential is present for an initial further two 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 will also commence in tandem with that at Mirage-1 in mid March 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 220,000 barrels of oil up to a maximum of 460,000 barrels of oil.
For the Mirage and Ventura oil Fields a cumulative maximum potential of up to 2.8 million barrels of recoverable oil has been mapped from the current data with initial cumulative oil production of 500 barrels of oil per day budgeted for these first two wells.
A 3D seismic acquisition program covering the Ventura and Mirage oil fields and the next prospect to the east on this highly prospective trend, Lightning, is being considered 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.
Victoria Petroleum N.L. is very pleased to have commenced the planning to bring the Mirage-1 and Ventura-1 wells into commercial production at a budgeted flow rate of 500 barrels of oil per day in mid March 2005.
With Victoria Petroleum's 40% interest in these two wells, Victoria's share of 200 barrels of oil per day will add to Victoria Petroleum's current average oil production of 200 barrels of oil per day, doubling it to 400 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 2.3 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, from the Almonta Structure, shared with Beach Petroleum, through to the Ventura-Mirage-Lightning structures. Almonta-1 is planned to be drilled by Beach Petroleum in late February 2005 on the portion of the Almonta Prospect within the adjacent Beach Petroleum operated permit PEL 95.
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 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 at 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 he spares 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.
A 133 kilometre 2D seismic survey was carried out in late July 2004, to define potential drill locations in the Haddon Downs area.
Based on the results of the July 2004 seismic survey, the Kitson Prospect has been approved by the PEL 88 Joint Venture as a drilling target for drilling in April 2005 by Century Rig 3. The Kitson Prospect is interpreted from seismic data to have the potential to contain up to 34 million barrels of recoverable oil in the target Jurassic sands, if oil is present.
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 planned to be acquired over the Dunoon Horst in mid 2005 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 589P
COOPER / EROMANGA BASIN, QUEENSLAND
VICTORIA PETROLEUM N.L. INTERESTS: - 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 in accordance with the relevant farmouts 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.
Significant Jurassic oil potential has been interpreted to be present in ATP 589P 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 589P (1) adjacent to the Barcoo Junction area and Moothandella are being been evaluated as potential future farmout 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 589P by free carrying Victoria Petroleum N.L. through a program of 500 kilometres of seismic reprocessing and the drilling and testing of a well.
The completion 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 completion of the signing of the Native Title agreements, currently in progress, exploration drilling is anticipated 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 589P, Part 1 and ATP 589P, 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.
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. 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 - 100%
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 is planning to work up locations for a one well deep drilling program following farmout, in the northern part of the Reids Dome in mid 2005.
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 Coalbed 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 coalbed 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 Coalbed 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 Coalbed Methane field, which is now producing sales gas into the pipeline linking it to Brisbane markets.
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.
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.
Oilex 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 updip 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)
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
Subsequent to the recovery of oil at Rookwood South-1, Oilex as operator and its JV partners in the ATP 608P ROOKWOOD BLOCK drilled two appraisal wells, Rookwood East-1 and Rookwood West-1, during the quarter. These were followed by Rookwood Central-1 and Rookwood North-1 during January 2005. The drilling of Rookwood East-1 and Rookwood West-1 was based on the mapped interpretation of the field following the drilling of Rookwood South-1. The top of the Boxvale Sandstone in Rookwood East-1 came in 4 metres low to prognosis and in Rookwood West-1, it came in 3 metres low to prognosis.
Subsequent to the end of the quarter, Rookwood Central-1, drilled on the prognosed crest of the structure, proved to be down dip of Rookwood South-1 and encountered a thin sand on basement and no other reservoir development. A Drill Stem Test over the Boxvale Sandstone in this well recovered water. The consequence of the lack of reservoir over the southern flank of the structure appears to restrict the area of the oil pool of the Rookwood field to north of Rookwood Central-1.
Rookwood North-1 was then drilled 32 metres north of the Rookwood-1 well drilled in 1987. The purpose of this well was to generate core data and to determine the oil/water contact for the field. This well cored through the top sand of the Boxvale Sandstone, which is producing oil in Rookwood South-1, 210 metres to the south, and into the top of the second sand. A Drill Stem Test over both intervals flowed water, indicating that the second sand is water bearing. The well was cased for testing of the top sand.
The result of the appraisal drilling of the Rookwood Field is that the field appears now to be limited to the small area north of Rookwood Central-1 and appears to be contained in a 2 metre thick sand at the top of the Boxvale Sandstone.
Rookwood South-1 was put on production testing in November 2004, with the first load out of 398 barrels of oil on 26th November. Production was initially at about 80 BOPD, well below the forecast productivity of the well provided by an independent consultant's analysis of the result of Drill Stem Test 1 in Rookwood South-1. Upon re-entering the well to improve oil flow, it was found that the pump contained a large amount of fines, suggesting that the flow of oil is being restricted by migration of fines towards the well bore. The well was then put back on pump. The current production rate is about 30 BOPD, with a total of 1,174 barrels of oil having been produced to the end of the December 31, 2004 quarter.
Preliminary results from a study and review of the drilling and production results to date indicate that although the pre-development drilling geophysical data and interpretation indicated a commercial oil reserve of some potential size, the Rookwood Oil Field now appears to be of a very limited extent and that commercial oil production may or may not be sustainable. An alternative interpretation for the production below that initially forecast, with the benefit of the subsequent limited production history for the Rookwood South-1 well, is that the oil bearing reservoir has limited pressure support and the reservoir pressure is depleting with production. Studies are in progress to determine the size of the reservoir in the upper Boxvale sand and what action can be taken to improve oil production flow rates and oil recovery for the Rookwood Oil Field.
While the production results and current indicated size of the oil reserves in the Rookwood Oil Field are disappointing, the discovery of oil at Rookwood South-1 is significant as this well opens up a new exploration play and trend in the permit
Two exploration prospects, Nicole-1 and Tailor-1 in the southern part of the Remainder Block of ATP 608P, have been generated from the existing seismic data over the field as potential future drilling targets.
Oilex N.L. is the Operator of the ATP 608P Joint Venture.
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.
APM 1178
NEW CALEDONIA BASIN, NEW CALEDONIA
VICTORIA PETROLEUM N.L. INTEREST - 33%
Following further review of the frontier exploration potential of the permit, Victoria Petroleum NL and Sun Resources N.L plan to withdraw from the permit.
TEXAS
ONSHORE GULF COAST BASIN
VICTORIA PETROLEUM N.L. INTEREST: 12.5%
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 will commence 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 300 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 lands.
The initial Flour Bluff Gas Development Project program from February to July 2005 calls for a minimum of three exploration wells BG Webb-1, EFB E-10 and EFBD-24 targeting multiple sand reservoirs as well as a recompletion/workover on 4 wells.
The first well to be drilled, BG Webb-1, will start drilling in early February 2005 with a contracted drilling rig to a planned total depth of 3,810 metres over a period of 26 days. Success in this well would provide significant encouragement that the concept of some 160 billion cubic feet of the operator's interpreted "additional potential" of 204 billion cubic feet of gas additional to the current proved, probable and possible reserves of 92 billion cubic feet of gas, was present in the deeper target Frio sands of the Flour Bluff Field
The results of this initial program will determine the pace of further field development and exploration. In the event of exploration and development success, it is envisaged the future drilling program will be funded from cash flow and US project financing.
This gas production and development acquisition represents an unusual and significant opportunity for Victoria Petroleum to participate in a relatively low risk, large, gas development and deeper exploration program on a major gas field with extensive established gas production facilites and pipeline infrastructure.
Almost all other South Texas giant fields have long ago been redeveloped, extended and deepened. The Flour Bluff Gas Field is an exception. It was discovered in 1936 and was developed and produced for many years by Humble Oil, an Exxon predecessor, until 1995, and then languished until 1999.
No records of gas production are available before 1964 but since then, the field has produced 639 BCF of gas and 31 million barrels of oil as mainly condensate at rates of up to 110 million cubic feet per day from more than 40 separate reservoirs in the Frio Formation, mostly at shallow depths less than 1,980 metres
From its discovery in 1936, the Flour Bluff field is estimated to have produced between 1.2 to 1.3 trillion cubic feet of gas and 60million barrels of oil, mainly as condensate,
Texas Crude Energy Inc, the Operator and major working interest partner, has carried out extensive studies of the considerable data base and from the limited deeper drilling carried out in the past has demonstrated that there is significant gas potential from multiple Frio Formation sands in the depth range 1,980 to 3,500 metres.
More importantly Texas Crude Energy Inc carried out a successful fracture stimulation of three old wells two years ago, increasing the gas production rate from 1.3 MMCFD to 7 MMCFD (million cubic feet per day), thereby demonstrating the effectiveness of modern stimulation methods to be applied in the redevelopment of the field.
Current field production rate is a stable 3.2 million cubic feet per day, which is targeted to rise at least tenfold in the next few years as exploration and development proceeds.
Gas production is an attractive business in the USA as prices are high (November Henry Hub price averaged US$ 7.62 per thousand cubic feet (mcf) (A$9.70/mcf - fourfold Australian prices) and are forecast to continue to be high as natural gas demand is ever increasing.
Energy pricing in the US is also related to an increasing need to import energy. In year 2003 some 3.8 TCF (trillion cubic feet) of natural gas was imported into the US in excess of 19.1 TCF of domestic production.
Victoria Petroleum has acquired this 12.5% WI in the Flour Bluff Gas Project through joining an Australian based buying consortium of three companies to acquire a collective 37.5% Working Interest "WI" (26.25% Net Revenue Interest "NRI") from Houston based Texas Crude Energy Inc for a consideration of US$7.5 million.
Victoria Petroleum contributed US$2.5 million to the purchase price, and in accordance with its acquired 12.5% WI (effective 1 January 2005) will contribute at a 12.5% WI level on a non-promoted basis to the Operator's aggressive exploration and development programs over a two and a half year period commencing in early February 2005.
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 Flour Bluff 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: 3.75-100%
Eagle Oil Pool Development Project
Victoria Petroleum N.L. Interest - 56.1%
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 updip extent of the Eagle Oil Pool and the Eagle-2 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.
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-2, drilling of this step out development well after farmout is planned for the second quarter of 2004 as the farmout 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-2.
With the current price of oil around US$40 per barrel (Australia $50 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%
During the year your company 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 during this year and resulted in the San Antonio-1 well being placed on pump production on 1 August 2003 with the well producing an average 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 suspended during the quarter while the Operator carries out a stimulation program over the oil bearing Monterey Shale horizons with the aim of increasing oil production.
Further 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.
Further development drilling by the Operator Trio Petroleum including the drilling and fracture stimulation of a horizontal well bore in the oil producing reservoir horizon is being considered for the first half of 2005.
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%
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.
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. Currently producing 20 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 2005. 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.
The Wyoming State Geological Survey suggests coal resources of greater than 1,277 billion short tons exist in the Greater Green River Basin and recent preliminary CBM potential resource studies of these greater basin coals indicates a 314 trillion cubic feet in place CBM resource awaiting exploration and future development.
The main thrust of Sun and Victoria is exploration and development of indicated large (up to 1,207 billion cubic feet), in place CBM resources from CBM potential studies of the Upper Cretaceous and Early Tertiary age multi seam coals on the present leases.
Acquisition of further offset Township sections to the immediate 47 Township sections and 7 part Township sections in the 376,320 acre (1,505 square kilometres) AMI by further leasing and farmins will grow resource potential if target and gas producibility are confirmed.
An important facet to a successful exploration outcome is access to market and transport of product. The pipeline in the AMI has compression and links into a local market, but more particularly an interstate pipeline terminal near Rock Springs, 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 AMI pipeline is currently utilised at less than 10% of capacity and is only being fed by conventional deep gas production (which is excluded from the farmin) on the underlying lease land at Greens Canyon and Dynes.
Wyoming State is the biggest producer of sub-bituminous, low-ash, low-sulphur coal in the USA at some 373 million short tons per annum and is the second largest gas producer after Texas at 1.75 trillion cubic feet per annum. CBM production at 384 BCF per annum is some 22% of the produced gas. The majority of coal production (95%) and CBM production (85%) presently comes from the shallow, thick sub bituminous coals in the Powder River Basin ("PRB") in the northeast of the state, which overlaps into south-eastern Montana.
Unlike the PRB, the Green River Basin which straddles southwest Wyoming State, northeast Utah State and northwest Colorado State is immature and frontier in CBM exploration and development.
The reasons being are the seams are deeper at 1,000 to 1,600 metres (PRB in comparison 50 to 700 meters); and thinner, the main seam, the Big Red Coal Seam is 10 to 12 metres thick (PRB's Woydak, Anderson, Big George seams in comparison are 10 to 40 metres thick).
However, multiple coal seams are present and gas content of the coals is far higher as a consequence of the rank of coal increasing with depth in the Green River Basin (now sub-bituminous to bituminous in rank). Indicated gas content is 250 to 450 scf gas / short ton of coal with gas chemical composition 98.5 to 99% methane and 1 to 1.5% carbon dioxide. PRB in comparison is 30 to 90 scf gas / short ton of coal with similar gas chemical composition.
Several major PRB CBM producers, encouraged by the above data inclusive of the flagged 314 trillion cubic feet in place CBM potential of the basin, and importantly their own operating experience in the deeper eastern PRB, have recently commenced exploration and development of their own projects in the eastern portion of the basin.
Sun Resources as Operator for the Rock Springs Coal Bed Methane Joint Venture plans to drill the first well on a permitted location near the pipeline in mid February 2005. This well, an offset to the
Dines#2 gas well, will be drilled to below the Big Red Coal Seam to test the 24 metres of Fort Union and Lance age coal sequence seen on the adjacent Dines#2 gas well logs.
The main seam will be continuously cored and after wire line logging of the well any coals of interest greater than 6 metres (20 feet) thick above the Big Red Coal will be sidewall cored. All cores of coals of interest (inclusive of the Big Red Coal Seam) will be analysed for their gas content and other properties deemed necessary for ascertaining CBM potential, and if the well technical data supports a completion and testing program, the well will be completed and tested for deliverability and commerciality of CBM production.
Depending on the favourable results of the coals sampled and analysed from the well, a further well is proposed on the leases to allow Victoria to earn an initial 20% working interest in the project. A testing and completion Program would ensue at a later date and if successful, the wells can be tied into the pipelines for immediate delivery of gas to the interstate pipeline and local markets.
Subsequent production wells will be drilled on permitted drill locations with access roads in place near the pipeline.
KESTREL ENERGY INC
VICTORIA PETROLEUM N.L. INTEREST - 20.48%
Victoria Petroleum N.L. has a 20.48% interest in Kestrel Energy Inc, a US NASDAQ Listed Company. As at 30 June 2004, Kestrel Energy Inc had SEC 10K Total Proved net oil and gas recoverable reserves of 367,700 barrels of oil and 4.74 billion cubic feet of gas, with a 10% Net Present Value of US$14.06 million (A$19.3) million. The value of these reserves is based on a constant oil price of US$37/bbl and US$6/mcf.
With the increase in oil and gas prices since 30 June 2004, the value of Victoria Petroleum NL's indirect interest in Kestrel Energy Inc proved reserves Net Present Value has appreciated.
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
[ Corporate ] [ Drilling Report ] [ ASX ] [ Quarterly Report ] [ Annual Report ]
[ Permit Inventory ] [ Prospect Drilling Schedule ] [ Farmin Opportunities ]
[ Internet Links ] [ Feedback ] [ Contact ]
[ Home ]