AustraliaLNG by Kryopak, Inc

	Australian Pipeline Trust Moomba to Sydney Pipeline (NSW) Carpentaria Pipeline (QLD) Roma to Brisbane Pipeline (QLD) The Amadeus Gas Trust (NT) Goldfields Gas Pipeline: 88.2% interest (WA) Midwest (WA)
Australian LNG export Summary June 2006 Australia’s Bureau of Agricultural and Resource Economics projects that the country’s LNG exports will reach 13.1 million tonnes in 2006 fiscal year (Apr. 1), up 24% from the previous year, and 20 million tonnes by 2010-11. Japan will remain Australia’s largest export market, followed by Korea, China, and the west coast of North America. In the longer term, Australian LNG exports could include 4.2 million tpy from North West Shelf’s Train 5, due to come online in late 2008, and 10 million tpy from the proposed Gorgon project, which will include an initial two-train liquefaction facility and a planned domestic gas plant on Barrow Island. The first cargo left the new Darwin LNG project on Feb. 14 and was delivered to Tokyo Electric Co. Ltd.’s following some delays (see cover). The 3.5-million-tpy plant, expected to be fully operational by June, is in Wickam Point in Australia’s Northern Territory. The gas comes from the offshore Bayu Undan field in the Australia-Timor Joint Petroleum Development Area, 500 km northwest of Darwin. Participants in Darwin LNG are ConocoPhillips (operator) 56.72%, Italy’s ENI 12.04%, Australia’s Santos 10.64%, INPEX 10.52%, Tokyo Electric 6.72%, and Tokyo Gas Co. Ltd. 3.36%. The entire output will be sold to Tokyo Electric and Tokyo Gas for 17 years. Gorgon project participants are the operator Chevron Australia 50% and Australian subheadidiaries of Royal Dutch Shell PLC and ExxonMobil Corp., each with 25%. Heads of agreement have been signed with three customers for 25 years: Tokyo Gas, 1.2 million tpy; Chubu Electric Co., 1.5 million tpy; and Osaka Gas Co. Ltd., 1.5 million tpy. Chevron has discussed the sale of an equity interest in the project with these and other companies, including China National Offshore Oil Corp. (CNOOC). A final investment decision will be made later this year. Another Australian project still in the planning stages is Woodside Petroleum’s proposed 5 to 7-million tpy Pluto project off the northwest coast of Western Australia. Woodside has signed preliminary sales agreements with Tokyo Gas for 1.5-1.75 million tpy and Kansai Electric Power Co. for 1.75-2.0 million tpy. A final investment decision will be made in second-quarter 2007. The North West Shelf project expects to deliver its initial cargo into China’s first LNG terminal at Shenzhen, Guangdong, at the end of May, 2 months later than was announced earlier. Full terminal operations are to begin in June. Partners in terminal owner Guandong Dapeng LNG Co. are CNOOC 33%, BP 30%, and eight Chinese and Hong Kong companies 37%. Dapeng LNG has signed contracts with 11 end-users for the sale of at least 3.7 million tpy, of which 2.05 million tpy will be used in power plants, 1.03 million tpy by residential users, and 0.62 million tpy for buyers in Hong Kong
Australia’s oil self-reliance may falter without new discoveries OGJ Mar. 6, 2006 Production of crude oil and condensate from 1975 to 2003 and production forecast of crude oil and condensate from 2004 to 2025. The forecast includes production of crude oil and condensate from accumulations that had been discovered by the end of June 2004 plus production of crude oil and condensate from undiscovered accumulations. The 2004 forecast includes 10% of production from the Joint Petroleum Development Area (JPDA). Condensate production was projected to continue to grow, but the rate of growth was constrained by gas production rates and overall by the development timetable for the major gas fields. Consequently, the rate of discovery of new oil fields was insufficient to replace oil reserve production.
Newmont in Western Australia's Boddington Project	Four operators join Aussie multiwell program Mar. 22 2006
Woodside to supply Pluto's Western Australia LNG to Japan Mar. 22
Plan addresses flagging Aussie oil output double gas use The Australian government and petroleum industry have jointly launched an outline plan to increase Australia's flagging oil production make Australia (1 of 5 world's top LNG exporters): double domestic use of natural gas. In 2003-04 the country imported $1.5 billion (Aus.) more oil and condensate than it exported. In 2004-05 the net import bill was $3.7 billion (Aus.). Based on current oil prices, by 2015 the net import bill could be $20.0 billion (Aus.) if indigenous production decline is not halted. The plan involves a strategic alliance between the upstream oil and gas industry represented by the Australian Petroleum Production and Exploration Association (APPEA) and the federal, state, and Northern Territory governments. Its aim is to increase economic growth and resource security in Australia.
expected crude oil and condensate production rate for 2006 is about 560,000 b/d 2005 recorded 460,000 b/d 2000 over 800,000 b/d self-sufficiency in liquid petroleum could fall to 50% by 2010
Better news is that natural gas discoveries and production are steadily increasing
Total gas production forecast for 2006 is expected to reach 45.5 billion cu m, up from 41.2 billion cu m last year. LNG production of 10.6 million tonnes/year in 2005 (about 40% of Australia's total gas production) is expected to rise to over 13.0 million tonnes/year in 2006 with the ConocoPhillips Darwin plant now on stream. There is also a mini LNG plant nearing completion at Karratha by Kryopak, Inc Australia's gas scene is also enhanced by an increasing supply of coalbed methane (CBM), mostly from projects tapping the Surat and Bowen basin coal measures in southeast Queensland. CBM now supplies 30% of Queensland's gas demand.
Exploration Offshore Onshore	Development On-stream OIL On-stream GAS
Under construction	Imminent projects
Pipelines	Downstream
Natural Gas Unit Equivalent to 1 cubic metre (m3) 35.301 cubic feet @ 14.73 psia and 60oF thousand cubic feet (Mcf) 1.05 GJ million cubic feet (MMcf) 1.05 TJ billion cubic feet (Bcf) 1.05 PJ trillion cubic feet (Tcf) 1.05 EJ
http://www.minerals.nsw.gov.au/prodServices/publications/commodities/petroleum/gas_publications http://www.minerals.nsw.gov.au/geology Natural gas: HHV = 1027 Btu/ft3 = 38.3 MJ/m3 LHV = 930 Btu/ft3 = 34.6 MJ/m3 1,012 Btu/standard cubic foot methane [Ref: Chemical Engineers’ Handbook. John H Perry, ed. McGraw-Hill Book Company: New York, 1963. Pg 9-9.] 19 1,050 Btu/standard cubic foot natural gas Methane 0.941 Million Btu/Thousand Cubic Feet http://www.nrel.gov/vehiclesandfuels/ngvtf/pdfs/lng_fuel_sys_tech_wegrzyn.pdf
The_Otway_basin The_Otway_basin map Otway basin CO2 sequestration trial advances March 13, 2006 Rick Wilkinson OGJ Correspondent MELBOURNE, Australian Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC), Canberra, has been awarded two production licenses in the onshore Otway basin of western Victoria in which to conduct its first carbon dioxide sequestration trial. Subject to environmental approvals, the pilot gas injection, storage, and monitoring program will begin by yearend. CO2CRC is now 100% owner of licenses PPL11 and PPL13, which cover Buttress CO2 field and nearby depleted Naylor natural gas field. The program will involve production of CO2 from Buttress at a rate of 3 MMcfd, piping the gas 1.75 km to Naylor, and injecting it into the Cretaceous Waarre reservoir on the flank of the depleted field via a well to be drilled this year. Injection will continue for about 2 years. Monitoring has begun in the region to establish baseline data and will continue for the next 4-5 years to gauge the movement of CO2 in the reservoir. A number of monitoring points will be established within a 5 sq km area around the injection point. There will also be monitoring equipment in the old Naylor-1 well. Buttress reserves exceed 10 bcf, 90% CO2. The minor amounts of methane will be stripped out and used to power the compressors and other equipment. The Otway Project is believed to be the only one in the world where researchers own the petroleum leases, the CO2 source, and the depleted storage reservoir. The Victorian government has allocated $4 million (Aus.) to the program. Funding also is coming from petroleum companies and overseas research groups. About 30 researchers will be involved in the project. Results will be particularly relevant to the proposed Gorgon gas project off Western Australia, which is to inject that field's 12% CO2 content into reservoirs under Barrow Island when it comes on stream in 2010-11.
Australia's Reserves Part 2 Discoveries, pending developments spell resurgence in Australia offshore production Paul Williamson Steven le Poidevin This is the second part of a two-part article about how Australia is converting substantial hydrocarbon resources into recoverable volumes. In the southeastern part of Australia, the Gippsland basin contains one gas field, Patricia/Baleen, that is now producing but was classified as economic demonstrated resources (EDR) in “Oil and Gas Resources of Australia 2002.”3 Patricia/Baleen gas field is 23 km off eastern Victoria in 50 m of water. The development consists of two subsea well completions connected via a 23-km offshore gas pipeline to an onshore dedicated gas treatment plant for processing and compression. The publicly estimated initial reserves are 77 bcf, while field life is estimated at 7 years. Kipper oil and gas field has development plans under consideration. The field was discovered in 1986 by the Kipper-1 exploration well 45 km off Victoria in 100 m of water. The options under consideration assume a subsea development of the field (which extends between two titles) under unitization agreement with Esso/BHP Billiton. A preliminary development plan for Basker/Manta oil field in the Gippsland basin has been submitted to state and federal governments. These fields are to be developed on a stand alone basis using a turret-moored floating production storage and offloading vessel (FPSO). The Bass basin west of the Gippsland basin contains one gas and oil field, Yolla, that was classified as EDR in “Oil and Gas Resources of Australia 2002.”3 The Yolla development began construction in April 2003 and is expected to achieve full production by the end of 2005. Yolla field is 120 km off Tasmania and 220 km southeast of Melbourne in 80 m of water. The field was discovered in 1985 by Amoco’s Yolla-1 well that intersected gas in the Intra-Eastern View Coal Measures (EVCM) reservoir units at 2,718-3,000 m. The reserves are publicly estimated at 236 bcf of sales gas, 1 million tonnes of LPG, and 14 million bbl of condensate. The Yolla field development consists of a conventional steel platform, two deviated development wells, and a 147-km, 350-mm plain carbon steel subsea pipeline for the shipment of raw gas and condensate to an onshore treatment plant in Victoria.
LNG 160 Ton Per Day West Kimberley Power Project Westport Innovations and ENE Move to Next Step for LNG-Fueled Mine Trucks November 28, 2005 Westport and ENE Enter Next Phase of HPDI Project in Australia November 28, 2005 Westport and EDL of Australia to Study HPDI for Off-Road Engines February 8, 2005 West Kimberley Power Project Westport Innovations, Beijing Tianhai Industry Co to Market LNG Tanks	Australia CBM exploration and production Queensland Petronas, AGL plan 1,200 km pipeline McArthur River Natural Gas Power Plant Project Pine Creek, Northern Territory, Australia Power Generation Energy Developments exceeds 420MW Average Price of Natural Gas to Industry, 2002

Australia's Reserves part 1
Discoveries, pending developments belie 2004 slide in Australia oil, gas reserves
Paul Williamson Steven le Poidevin Oil & Gas Journal, October 17, 2005

Australia can now claim to be shedding its reputation for stranded gas fields with the advent of significant new and proposed liquified natural gas (LNG) projects.

Recently petroleum companies in Australia have moved to establish substantial new LNG capacity at the Northwest Shelf Project (North Rankin and associated fields) and Darwin LNG (Bayu/Undan field) on the back of political stability and an enviable record for delivery of over 1,600 LNG cargoes from the Northwest Shelf Project.

As part of the LNG development, it is considered credible that three of the other known supergiant gas fields that occur off Northwest Australia could be producing by 2015. This coincides with development of other oil and gas fields.

Of particular note, this activity coincides with Australia recently having one of the highest rates in the world for discovery of barrels of oil equivalent per year.

The activity in LNG has resulted in an emerging realization of the need to find more gas to meet projected future needs.1 Australian petroleum resources have recently benefited from large new discoveries, and government estimates of proven reserves and economic demonstrated resources (EDR) have sustained their levels over recent years.

In this respect an article that reported the Australian government’s severe downgrading of Australia’s oil and gas reserves simply reflected a different use of estimates of Australian reserve and resource numbers (OGJ, Dec. 20, 2004, p. 18).

About 95% of Australian oil production and 80% of gas production is from offshore.2 In the last ten years the nation has maintained 65-85% self sufficiency in oil. A level of 85% is projected for 2007.3 Australia has also better than 100% sufficiency in gas as a net gas exporter through LNG.

Australia nonetheless remains significantly underexplored, with less than 10,000 wells drilled nationwide in an area of over 12 million sq km. This is in spite of a competitive advantage Australia has established in encouraging petroleum exploration by almost unequalled ready access to data from previous exploration and production.

According to independent assessments, Australia is one of the best worldwide in providing petroleum exploration and production data to potential and current explorers.4 Access to petroleum exploration data has been subject to legislation since the 1950s and requires exploration and production data to be submitted for public release after a relatively brief confidentiality period.

Type, format, form, and media for lodgement of petroleum data are decided by government in consultation with industry and geophysical contractors. To further facilitate the access to data, the Australian Spatial Information and Data Policy announced in 2001 makes data available for the cost of transfer, including access by use of the internet to digital petroleum data bases from Geoscience Australia.

To seek to further increase exploration there was a redoubling of efforts, announced in the Commonwealth Government Budget of May 2003, to make Australian petroleum exploration and production data even more readily available to current and potential explorers. The Australian government has dedicated $25 million to these activities.

Seismic data from previous exploration is being remastered to high-density media for easy access. Over 250,000 seismic field tapes have been remastered to 3590 cartridges. These data are available at the cost of transfer (the cost of copying the high density tapes). To date 2,700 km of new seismic data have been collected over the Bremer, Mentelle, and Vlaming subbasins off Southwest Australia. These data are also publicly available at cost of transfer.

As an additional measure, five of the petroleum exploration areas offered in the release of 2005 attracted 150% uplift for tax purposes as a stimulus for frontier exploration. This program began in 2004 and was continued in 2005.
Recent discoveries

New oil and gas fields have been discovered both in the southeast and northwest of Australia, including supergiant gas fields. Deeper water exploration has also occurred including in areas adjacent to major gas and oil production in the Carnarvon basin on the Northwest Shelf.

The Carnarvon basin is Australia’s premier producing basin for both oil and gas. It has been explored for 40 years and shows no decrease in the rate of oil discovery.5 Significant oil discoveries at Exeter/Mutineer, Laverda, Vincent, and Enfield have been made, and many tens of trillion cubic feet of gas have been discovered at Gorgon and the more westerly Io/Jansz deepwater fields.6

Substantial gas discoveries have also been made recently at Pluto and at Wheatstone. To the north in the Browse basin the Japanese company INPEX has discovered an estimated at 10 tcf of gas and 500 million bbl of condensate in place in Gorgonicthys, Titanicthys, and Dionicthys fields.7

In the Otway basin in southeastern Australia the recent significant gas discovery at Henry has added to the burgeoning gas province there that helps service the southeastern domestic markets.

The recently discovered fields add to those discovered in an early phase of exploration prior to 1974 that defined the current major petroleum producing basins in Australia (Fig. 1). Supergiant fields containing both oil and gas were discovered in the Gippsland basin. These fields are producing to markets in the southeast and east of the country.

Supergiant fields were also discovered in the Carnarvon basin where the Rankin and Perseus fields are producing for domestic markets and for LNG export, mainly to Japan via a four train Woodside facility that may soon expand to five. A major LNG export agreement has been agreed with China.

The onshore Cooper-Eromanga basin was discovered in the early exploration phase and has become the source of gas for a number of major Australia cities. Recently the basin has had numerous commercial oil and gas discoveries made mainly by small operators.
Reserves and resources

Australian government estimates of reserves have remained fairly consistent over recent years, but as described earlier the large new gas discoveries are generating excitement.

Australian government reserve and resource estimates are those reported by Geoscience Australia, the Australian government agency responsible for producing official data on oil and gas resources, in its publication “Oil and Gas Resources of Australia.”

Category 1 proved plus probable reserves are for fields that are in production or have been declared commercial. For this category, the reserves have been sustained (Table 1).
In addition to Category 1 reserves, there are much larger additional resources which are judged to be economically extractable mainly from deepwater fields. These include condensate and gas in some of the recently discovered supergiant gas fields in the Bonaparte, Browse, and Carnarvon basins, for which delineation and planning for development is proceeding.

Using the McKelvey system of resource classification, they are also included in “Oil and Gas Resources of Australia” with producing reserves in the category referred to as economic demonstrated resources or EDR [Category 2 (noncommercial reserves)].

As at Jan. 1, 2003, EDR of oil and gas for Australia were 2,845 million bbl and 89 tcf, respectively. In the year to February 2005 since the reporting on which the OGJ numbers were based, five fields in the EDR category are now producing as will be described below.

Australia’s EDR for oil and gas have decreased slightly in the latest figures. These figures are not proved reserves but appear to be comparable in terms of reporting practices to those shown for other countries with substantial undeveloped gas resources.

In addition, as shown in Table 1, there are substantial resources in the subeconomic demonstrated resources category [also Category 2 (noncommercial reserves)]. Some of these resources may also become economic in the future as technology and infrastructure develop.

The totals in the McKelvey classification and the Traditional Petroleum Industry classification are the same as the McKelvey classification simply reallocates the TPI resources on the basis of their potential for commercialization. In the Traditional Petroleum Industry classification: Category 1 comprises current reserves of those fields that have been declared commercial. It includes both proved and probable reserves; Category 2 comprises estimates of recoverable reserves that have not yet been declared commercially viable. They may be either geologically proved or waiting further appraisal.

In practice, only offshore fields are considered for EDR classification under the McKelvey classification. Typically, due to the presence of infrastructure in most highly prospective onshore areas, commercially attractive discoveries enter production rapidly.

When considering offshore fields for EDR status, a number of factors are reviewed. Foremost is the proximity of infrastructure, followed by access to market and the quality of the resource. As all reserves numbers considered are proved plus probable, the certainty of occurrence is not a factor.

Additionally, drilled, nonproducing extensions to producing fields are included in the category. This typically includes resources in adjacent fault blocks and shallower and deeper pools. EDR are resources for which the quantity and quality are computed partly from specific measurements and partly from extrapolation for a reasonable distance on geological evidence.

Subeconomic demonstrated resources are similar to EDR in terms of certainty of occurrence and, although considered to be potentially economic in the foreseeable future, these resources are judged to be subeconomic at present.3 For comparison with the EDR numbers, BP in its 2004 Statistical Review of World Energy gives reserves for Australia for end 2002 of 3,700 million bbl of oil and 90 tcf of gas.

Further details on reserves in some of the recent gas discoveries can be found on the internet at: http://www.doir.wa.gov.au/documents/mineralsandpetroleum/Reserves_0304(1).pdf, and http://kakadu.nt.gov.au/pls/portal30/docs/FOLDER/DBIRD_ME/PUBLICATIONS/OIL_and Oil and Gas Resources of Australia is online at http://www.ga.gov.au/oceans/projects/ogra.jsp
Recent field developments

Those fields that were classified as having EDR in “Oil and Gas Resources of Australia 2003”2 are operated by companies having advanced plans for development or with existing infrastructure.

Four of those fields including one supergiant gas field are now producing and another is due to begin production.
Carnarvon_Basin Map

The Carnarvon basin in the Northwest Shelf (Fig. 2) contains a number of supergiant and giant gas and gas-condensate fields.

Of Woodside’s gas discoveries classified as EDR in the Northwest Shelf area, one is now producing and a number are being developed or will be developed in the near future. These include Perseus (producing), which was classified in the EDR, Angel (preliminary field development plan submitted), Searipple, Tidepole, Gaea, Dixon, and Dockrell. Perseus is a supergiant gas pool.

Mutineer-Exeter oil field began production in March 2005 but was classified as an EDR only in 2003. Also in March 2005, a preliminary development plan for Enfield oil field containing heavily biodegraded oil of 22° gravity was submitted.

A number of exploration areas in the Carnarvon basin were released for bidding in April 2005 with closing dates of October 2005 and April 2006 depending on the size and exploration maturity of the acreage. Information and data on these areas can be obtained from Geoscience Australia at Marita.Bradshaw@ga.gov.au or www.ga.gov.au/oceans/ss_Acreage.jsp.

The Greater Gorgon area is 130 km off the northwest coast of Western Australia in the Carnarvon basin. The fields in that area contain in excess of 40 tcf of gas.8

The Gorgon field development plan is well advanced. It involves the installation of a subsea gathering system and a 70 km subsea pipeline to Barrow Island.

A gas processing facility located on the Barrow Island would process the gas. Carbon dioxide would be removed and reinjected into deep saline reservoirs below the island, and the liquid hydrocarbon product would be transported by ship to international markets. Natural gas would be delivered via a subsea pipeline to the Western Australian mainland for use in industrial and domestic gas markets.

The initial development is a two-train LNG processing facility on Barrow Island, producing 10 million tonnes/year of LNG and delivering 280 MMcfd of gas to existing mainland domestic gas infrastructure.

This development is also planned to include the Io/Jansz supergiant gas field. The construction would be phased over 3-15 years. Io/Jansz was discovered in the Carnarvon basin in 2000 and has an in place gas resource estimated at 20 tcf.8 Other nearby gas discoveries include Geryon, Orthrus, Maenad, Dionysus, and Chrysaor.

Scarborough gas field is located in the Exmouth plateau west of the Carnarvon basin off Western Australia on acreage held by Esso Australia Resources Ltd. (Esso) and BHP Billiton Petroleum (North West Shelf) Pty. Ltd. Gas in place is estimated at 5 tcf.

BHP Billiton has proposed an onshore site for the Pilbara LNG project to develop the Scarborough resource. A number of concepts are considered technically feasible for development of this resource depending upon the available technologies and markets when the project commences. The primary concepts are subsea, with LNG facilities based onshore or on a remote island, floating LNG processing capability, and pipeline development for third party gas sale.

Most of the undeveloped fields in the Carnarvon basin are relatively remote from existing infrastructure and/or in deep water. Additionally, they contain dry gas, usually with moderate to high carbon dioxide content.

In the Browse basin to the north (Fig. 3) INPEX Browse Ltd. drilled three exploration wells in the exploration permit WA-285-P during 2000, Dinichthys 1, Gorgonichthys 1 and Titanichthys 1 (Ichthys complex) and discovered as mentioned earlier a promising gas and condensate structure. Gas in place is estimated at 10 tcf and condensate in place is estimated at 500 million bbl.7

INPEX Browse is looking toward not only LNG development but also new technologies associated with gas to liquids and dimethyl ether.

Brecknock and Brecknock South fields in the western Browse basin are held under retention leases by Woodside (operators of the North West Shelf LNG facility).

Due to the remoteness these fields Woodside is considering a wide range of development concepts and emerging technologies. Concepts include the production and export of LNG as well as sales gas into domestic markets and gas supply to an onshore gas-to-liquids (GTL) facility. Gas in place is estimated at 9 tcf.8

Woodside is embarking on an aggressive appraisal program to assess the feasibility of development. The Browse basin, however, contains no resources classified as EDR as its four giant to supergiant fields contain dry gas (except for Ichthys) and high carbon dioxide and are remote with few onshore facilities to assist early development. Both onshore and offshore development options are being studied.

A number of exploration areas in the Browse basin were released for bidding in April 2005 with a closing date of October 2005. Information and data on these areas can also be obtained from Geoscience Australia at Marita.Bradshaw@ga.gov.au or www.ga.gov.au/oceans/ss_Acreage.jsp.

The Bonaparte basin (Fig. 4)

contained one gas-condensate field Bayu/Undan that has subsequently been developed but was classified as having EDR in “Oil and Gas Resources of Australia 2002.”3 On Feb. 15, 2004, the first condensate production was achieved from the Bayu/Undan gas recycle phase of the project following the successful commissioning and start-up, and the first shipment of 340,000 bbl of condensate was completed on Mar. 30, 2004.

Bayu/Undan field is 500 km northwest of Darwin in the Joint Petroleum Development Area (previously known as Area A of the Zone of Cooperation) in the Timor Sea. The reserves are publicly estimated at 400 million bbl of condensate and LPG and 3.4 tcf of gas.

The field is being developed in two phases. The first phase is a $1.8 billion (US) gas-recycle project, where gas liquids are removed and the dry gas reinjected. The second phase involves an onshore LNG project called Darwin LNG. The LNG project is expected to commence production in the first quarter of 2006.

Greater Sunrise, comprising the Sunrise and Troubadour gas fields, contains around 9 tcf of gas (Woodside estimate) and has the capacity to supply long-term gas contracts for more than 30 years. The field is 500 km northwest of Darwin and 150 km south of East Timor.

The Sunrise joint venture participants-the operator Woodside with 33.44%, ConocoPhillips 30%, Shell 26.56%, and Osaka Gas 10%--have so far spent nearly A$200 million working on a series of scenarios to bring the projects on stream. The project is currently on hold pending agreement with East Timor.

Planning has been under way for development of Blacktip gas field involving a pipeline to sell the gas onshore. Exploration areas in the Bonaparte basin were released for bidding in April 2005 with closing dates of October 2005 and April 2006 depending on the size and exploration maturity of the acreage.

Next: The authors list recent discoveries and developments in southeastern Australia and continued efforts to make exploration data available to the industry and other exploration incentives.

Chevron begins to drill Barrow CO2 study well
Rick Wilkinson OGJ Correspondent MELBOURNE, Oil & Gas Journal Online, March 07, 2006

The Chevron Corp.-led group for the proposed Gorgon-Jansz LNG project in Western Australia has spudded a carbon dioxide data well on Barrow Island to collect additional scientific information to proceed with the injection of CO2 produced with methane from the Gorgon reservoir.

Gorgon has a 12% CO2 content. Part of the development plan is to strip CO2 from the gas stream at the treatment and liquefaction facilities planned for Barrow and to reinject it into deep formations underneath the island.

This plan only applies to Gorgon. The nearby Jansz field has a minimal CO2 content and will be developed through a parallel, but completely separate offshore-onshore pipeline system and its own dedicated LNG train.

The data well project is one of a number of technical studies that have been undertaken since 1998 into the proposal for CO2 geosequestration.

Colin Beckett, general manager of the Gorgon project, said that this single well and the associated studies will cost about $25 million (Aus.).

It is expected to take 2 months and as many as 100 people to drill the 2,500 m deep well and undertake the required scientific and engineering tests.

These tests will involve an extensive wire line formation evaluation program of the bottom 400-500 m section. This section will also be cored and analyzed.

Saline water will also be pumped in to simulate the behaviour of liquid CO2 into a section of the targeted Dupuy formation.

Ultimately, the geosequestration plan may save the emission of more than 120 million tonnes of CO2 over the life of project.

A final decision about whether to proceed with the Gorgon-Jansz development is expected by yearend.

Woodside to supply Pluto's Western Australia LNG to Japan Mar. 22
By OGJ editors HOUSTON

Woodside Energy Ltd. has signed an agreement with Kansai Electric Power Co. Inc. of Japan to supply 1.75 million-2 million tonnes/year of LNG for 15 years from its 100%-owned Pluto gas field off Western Australia.

The agreement, conditional on Woodside's final Pluto investment decision, starts at the end of 2010 and includes an option to extend for 5 years. It allows Kansai Electric to purchase a 5% equity interest in Pluto field, which lies 190 km northwest of Karratha in permit WA-350-P (OGJ, Mar. 6, 2006, p. 20).

Four operators join Aussie multiwell program Mar. 22 2006
By OGJ editors HOUSTON,

Peak Group, Aberdeen, has secured a rig and associated contracts and has begun its first multiwell, multioperator well management program off Australia. The $100 million (Aus.) program covers eight wells and four operators. It developed from a Peak contract for drilling in AED Oil Ltd.'s Puffin oil field on the Ashmore Cartier Permit AC/P22 in the Timor Sea. Other operators in the program are Santos Ltd., Eni SPA, and ConocoPhillips.

The Stena Clyde semisubmersible on Mar. 8 began drilling the first of three wells for AED, the low-angle Puffin 9 exploratory well to be drilled to 3,000 m below the seabed. It will drill two development wells, Puffin 7 with a 460 m horizontal lateral and Puffin 8, still under design. The development wells will be completed subsea and tied back to a floating production, storage, and offloading vessel (OGJ, Mar. 6, 2006, p. 20).

For the AED wells, Peak is providing complete well construction project management and procurement service.
For that and its work for the other operators in the program, Peak will hold the contracts for the drilling rig, supply vessels, third-party service contracts, and logistics and supply base services. Its work for the operators other than AED will vary.
It completed work for a two-well Eni campaign and will work on one Santos well and two ConocoPhillips wells.

Newmont in Western Australia's Boddington Project
Newmont Completes Acquistion of Additional Interest in Western Australia's Boddington Project
DENVER, March 20 /PRNewswire-FirstCall/

Newmont Mining Corporation (NYSE: NEM) announced that it had received all Australian government approvals for the acquisition of Newcrest Mining Limited's 22.22% interest in the Boddington Project in Western Australia, and that the transaction has now closed. Consideration for the purchase was Australian $225 million and gives Newmont a two-thirds interest in the Boddington Project.

The Company has previously announced that it is proceeding with development of Boddington with its partner AngloGold Ashanti Limited for expected initial production in late 2008. At year-end 2005, Newmont reported equity gold proven and probable reserves at Boddington of 5.16 million ounces. The project has a current estimated mine life of more than 15 years, and Newmont's share of annual production is expected to be approximately 700,000 ounces for the first five years and average approximately 600,000 ounces over the life of the project. Costs applicable to sales, net of by-product credits, are expected to be approximately $210 per ounce.

Plan addresses flagging Aussie oil output double gas use
Rick Wilkinson OGJ Correspondent Oil & gas journal Mar. 20,2006

The Australian government and petroleum industry have jointly launched an outline plan to increase Australia's flagging oil production make Australia one of the world's top five LNG exporters, and double the domestic use of natural gas.

The plan involves a strategic alliance between the upstream oil and gas industry represented by the Australian Petroleum Production and Exploration Association (APPEA) and the federal, state, and Northern Territory governments. Its aim is to increase economic growth and resource security in Australia.

The strategic goals are to ensure that by 2015 oil self-sufficiency levels will remain at least at 2006 levels, that LNG production will exceed 50 million tonnes/year, that natural gas as a competitive feedstock for processing will be doubled, and that gas provide primary energy for 70% of all new electric power generation capacity.

Industry and Resources Minister Ian Macfarlane said the strategy required a change in business and community attitudes about energy production and greater acceptance of gas options.

APPEA Chief Executive Officer Belinda Robinson noted impediments to exploration in Australia need to be addressed. The country remains very lightly explored, and regenerating interest in exploration is central to the new initiative, she said.

An issues paper outlining the strategy will be circulated for public comment by the end of this month, and the industry will publish a final strategy document by yearend to build on government initiatives already in existence. These include the federal government's Energy White Paper and the LNG Action Agenda.

A leadership group chaired by Agu Kantsler of Woodside Energy Ltd. has been established.
It comprises representatives from industry, government, and research organizations.

Industry and government have become increasingly concerned about Australia's rapidly falling oil and condensate production. In 2003-04 the country imported $1.5 billion (Aus.) more oil and condensate than it exported. In 2004-05 the net import bill was $3.7 billion (Aus.).

Based on current oil prices, the net import bill could be $20 billion (Aus.) by 2015 if the indigenous production decline is not halted.

Average Price of Natural Gas to Industry, 2002 (1)
Country    US$ per Gigajoule
Australia    3.24
United Kingdom    3.70
United States    4.21
France    4.47
Germany    4.49
New Zealand    4.79
Japan    9.71

Footnotes:
1: Data are for 4th quarter 2002 or latest available
Source: International Energy Agency, Key World Energy Statistics, 2003

Australia’s oil self-reliance may falter without new discoveries
OGJ Mar. 6, 2006

Australia gradually is slipping behind in its attempts to maintain self-sufficiency in oil despite a rally during 2005-06 as a result of new onstream production, principally from Mutineer-Exeter field and the coming Enfield development, both in the Carnarvon basin off Western Australia.
The country's total expected crude oil and condensate production rate for 2006 is about 560,000 b/d, up from 460,000 b/d recorded for 2005. This will be an improvement on the 490,000 b/d recorded for 2004 but still well behind the peak production of over 800,000 b/d in 2000.

Unfortunately, the current holding pattern is unlikely to last, as there have been no significant oil discoveries in the past 18 months. If this lack of exploration success continues, the nation's self-sufficiency in liquid petroleum could fall to about 50% by 2010, a marked contrast to the 95% in 2000.
Downstream, Australia's total refining capacity remains at about 770,000 b/d. All seven of the country's main refineries spent large sums to comply with stringent new federal environmental standards for reducing sulfur and benzene content in fuel.

Nevertheless, the refineries are relatively small and finding it increasingly difficult to compete with cheap gasoline imports from Asia.
In addition, ExxonMobil Corp. closed its Port Stanvac plant in Adelaide in 2003, and there is continuing speculation about the possible closure of another refinery before the end of the decade.

Better news is that natural gas discoveries and production are steadily increasing. Three main finds in 2005 - Pluto and Hurricane in Carnarvon basin and Caldita in the Timor Sea - have recorded substantial gas accumulations.
At the same time, most of the development projects brought on stream in the last 12 months and those still under construction are gas fields for both domestic consumption and for export as LNG.
Total gas production forecast for 2006 is expected to reach 45.5 billion cu m, up from 41.2 billion cu m last year. LNG production of 10.6 million tonnes/year in 2005 (about 40% of Australia's total gas production) is expected to rise to over 13 million tonnes in 2006 with the ConocoPhillips Darwin plant now on stream.

Australia's gas scene is also enhanced by an increasing supply of coalbed methane (CBM), mostly from projects tapping the Surat and Bowen basin coal measures in southeast Queensland. CBM now supplies 30% of Queensland's gas demand.

Exploration

The bulk of Australia's exploration activity over the last 12 months has been off western and northern Australia. Elsewhere, lesser contributions have come from the offshore Otway and Gippsland basins off Victoria and onshore provinces of the Perth, Cooper-Eromanga, and Surat basins of Western Australia, South Australia, and Queensland.

Offshore

A significant discovery in 2005 was Woodside Energy Ltd.'s large Pluto gas find in Carnarvon basin Permit WA-350-P some 190 km off Western Australia. Within a few months of this March 2005 discovery, the company had canvassed the possibility of a $5 million (Aus.) two-train LNG development, received "major project facilitation" status from the federal government, and signed a provisional 15-year deal with Tokyo Gas Co. Ltd. to supply 1.5-1.75 million tonnes/year of LNG beginning in 2010. Tokyo Gas also took 5% in the project. Front-end engineering and design work has begun. To meet the proposed on- stream target, a final investment decision will be needed in mid- 2007.

Equal interest came with the discovery of Caldita gas field in Permit NT/P61 in the eastern Timor Sea by partners ConocoPhillips and Santos Ltd. in September 2005.
The find, about 265 km north-northwest of Darwin in 137 m of water, tested gas at 33 MMcfd, including an unspecified amount of carbon dioxide. Knowing it to be a southerly extension of Shell Development (Australia) Pty. Ltd.'s 1960s Lynedock gas find, ConocoPhillips and Santos quickly applied for and won the open Lynedock area and plan a renewed exploration program in the next 12 months. Both companies are members of the BayuUndan gas development and are eager to find sufficient gas supplies to add a second and perhaps a third train to the associated Darwin LNG facilities.

Santos, this time as operator, also figured in the Hurricane gas discovery in Permit WA-208-P in January 2005. The well encountered a 76 m gross gas column, but post-well evaluation has shifted the focus to a potential underlying oil column. Hurricane is near Woodside Energy Ltd.'s producing Legendre oil field, and the Hurricane-2 appraisal is to be drilled in 2006, depending on rig availability.

The quiet achiever of 2005 was the Apache Energy Group (Apache Corp., Houston; Kufpec Australia Pty. Ltd., Perth; and Tap Oil Ltd., Perth), which continued to add small, but significant oil fields to feed into its Varanus Island oil and gas facilities in the Carnarvon basin. Drilling from and near existing platforms, the group made four oil discoveries at regular intervals during the year at Albert- 1, Remus-1, Mohave1, and Artreus-I., All were quickly tied into the Varanus production system and tanker loading facilities.

Exploration activity off southeastern Australia during 2005 was the highest it had been for some years, particularly in the Gippsland basin where a number of small explorers have taken up acreage near the main ExxonMobil-BHP Billiton Ltd. producing area. Drilling results have not matched enthusiasm although groups led by other Melbourne companies Bass Strait Oil Co. and Nexus Energy Ltd. plan to continue drilling in 2006. Nexus, in particular, wants to appraise its Longtom gas field in Permit Vic/P54 with Longtom-3 in midyear. The company is confident of commercial development and has already arranged with Santos to send a potential 350 Pj of gas through Santos' existing Patricia-Baleen gas plant on the coast near Orbost over a 10-year period.

Better exploration success came to the Woodside group (Woodside, Origin Energy Resources Ltd., Sydney; Benares International NV; and CalEnergy (Australia) Ltd.) and the Santos group (Santos, Australian Worldwide Exploration Ltd., (AWE), Sydney; and Japan's Mitsui & Co. Ltd.) in the Otway basin off western Victoria. The former made gas discoveries at Black Watch-1 and nearby Hallidale-1 during 2005. Both wells were drilled from the same location. The Santos group found gas at Henry-1, which is close enough to Casino gas field to make an easy production tie-in. Santos currently is evaluating the potential.

Onshore

The best onshore exploration results still come from the Cooper-Eromanga basins of South Australia, where a number of small companies are working near the Santos-held production hub. Explorers such as Beach Petroleum NL, Adelaide; Cooper Energy Ltd., Perth; Stuart Petroleum Ltd., Adelaide; Victoria Petroleum NL, Perth; Great Artesian Oil & Gas Ltd., Sydney; and Innamincka Petroleum Ltd., Brisbane all made small oil and gas discoveries in the past 12 months. High oil prices and extensive infrastructure in the region have enabled these discoveries to be brought on stream relatively quickly. .

Santos also increased its exploration effort and recently began a 4-year, 1,000-well drilling program in its Cooper-Eromanga acreage in South Australia and Queensland. The target is a potential 75 million bbl of oil, which the company believes remains in existing and undrilled structures.

Elsewhere in the country, the partnership of Arc Energy Ltd., Perth, and Origin Energy continued its successful run with three gas finds (Corybus, Tarantula, and Senecio) in the onshore Perth basin during 2005. In the SuratBowen basin of Queensland, Mosaic Oil NL, Sydney, found Permian oil in its Rockhampton High prospect, and Sunshine Gas Ltd., Brisbane, Queensland, found gas at Champagne Creek. Evaluation work on both discoveries will continue this year.

Onshore exploration activity will move a little more outside the norm in 2006.
Empire Oil & Gas NL, Perth, plans to drill the Dune-1 wildcat near Australia's original 1953 Rough Range oil discovery near Exmouth in Western Australia, while newcomer Central Petroleum Ltd. is tackling new targets in the Pedirka and Amadeus basins in Northern Territory. Melbourne-based Lakes Oil NL is pressing on with exploration of tight gas sands in the extensive Cretaceous-age Strzelecki Group sediments of Victoria's onshore Gippsland basin and, in a real frontier effort, Sydney-based Eastern Star Gas Ltd. is planning several wells in the virtually untouched Darling basin of western New South Wales.

Development

Development activity has been a major Australian petroleum industry focus during the last 12 months, and it will continue in that vein as projects in the planning and construction stages are brought on stream during the next 4 years.

On-stream oil

Bright lights in the oil business have been Santos group's Mutineer and Exeter fields in the Carnarvon basin, which were brought on stream in March 2005 at 72,000 b/d. The $440 million development-by Santos, Kufpec, Nippon Oil Exploration (Dampier) Pty. Ltd., and Woodside consists of four subsea wells tied to a floating production, storage, and offloading (FPSO) vessel in about 150 m of water. The facilities have been designed for a plateau production of
100,000 b/d.

Another key oil development to begin production in 2005 was the BaskerManta complex in the Gippsland basin off Victoria, which Anzon Australia Ltd. and Beach Petroleum are developing. The $260 million project is notable for its rapid development - 12 months from design concept to first oil - and for its use of the first FPSO in Bass Strait. The Basker-2 appraisal-production well brought Basker field on stream in November 2005, producing 8,000 b/d from a subsea wellhead connected to the 40,000 bbl capacity Crystal Ocean FPSO. Basker Spirit, a larger storage offloading tanker, delivers the crude to market.

A well on nearby Manta field was completed in February. It, along with two more production wells at Basker, will be brought on stream in midyear to increase total production to 20,000 - 25,000 b/d. After separation from the oil stream, Manta's associated gas will be stored in Basker field in a purpose-drilled reinjection well.

Anzon and Beach are evaluating the potential for a separate project in the region to commercialize the gas, a development that would include Gummy, a third primarily gas field. All three fields were found by Shell during 1983-90.

Onshore oil development saw a revival of Australia's 1953 oil discovery at Rough Range near Exmouth in Western Australia. Empire Oil & Gas NL, Perth, began producing oil on pump at 125 b/d in July 2005. Oil is trucked to BP PLCs’ refinery at Kwinana, south of Perth. Other small oil fields brought on stream during 2005 included Mosaic Oil's Waggamba in the Surat basin, Great Artesian Oil & Gas's Kiana, and Victoria Petroleum's Ventura in the Cooper-Eromanga basins.

On-stream gas

Two major gas fields coming on line in the last 14 months were Apache Energy-Santos' $300 million John Brookes field on the North West Shelf in September 2005 and ConocoPhillips group's $2 billion LNG development using feedstock from Bayu-Undan field in the Timor Sea in February.

Three wells produce in John Brookes to an unmanned platform and move from there into a two-phase, 55 km pipeline to Apache's production facilities on Varanus Island. Flow rate is around 180 Tj/day of gas plus 850 b/d of condensate. Sales gas is sent to the mainland to connect with the main Dampier-to-Bunbury trunkline.

The larger Bayu-Undan project (ConocoPhillips, Eni SPA, Tokyo Gas, Tokyo Electric Power Co. Inc., Santos, and Inpex Corp., Tokyo) is sending gas southeast via a 500-km pipeline to the new 3.4 million-tonne/year LNG plant at Wickham Point near Darwin.
Condensate is stripped out at the field and delivered to an FPSO and offloading tankers. Tokyo Gas and Tokyo Electric Power have contracts to take 3 million tonnes/year of LNG over 17 years. This leaves room for the ConocoPhillips group to sell occasional cargoes in the spot market. The group has approval to extend the plant capacity to 10 million tonnes/year and is seeking additional gas supplies in the Timor Sea.

Elsewhere, the offshore Otway basin of western Victoria joined the ranks of Australia's gas producing regions in January 2005 when BHP Billiton Santos' $225 million Minerva field development was brought on stream at 150 Tj/day plus 600 b/d of liquids. The Santos group followed in February of this year, bringing its $200 million Casino field at 96 Tj/day plus liquids.

Each field, in about 65 m of water, is producing from two subsea wells connected via subsea pipelines to discrete onshore production facilities near the coast.
The pipelines (10 km long for Minerva and 30 km long for Casino) were directionally drilled under the coastal cliffs to preserve the region's environmental integrity. Gas is sold into trunklines serving the South Australian and Victorian markets.

Under construction

Development projects still under construction are mostly concentrated off Western Australia, and Woodside Energy is the dominant participant.
Closest to completion is Woodside and Mitsui's $1.4 billion Enfield oil development in the Carnarvon basin, due on stream this year at 100,000 b/d. Production will be from five subsea wells tied in to an FPSO in 600 m of water. The field is off Western Australia 50 km northwest of Exmouth.

Three additions to the original North West Shelf Gas Project will come on line in stages until yearend 2008. The $700 million Perseus-over-Goodwyn project involves three subsea wells in Perseus field being tied by pipeline to the nearby Goodwyn platform production facilities.
Gas and condensate will be piped to the North Rankin platform and from there to the onshore Burrup Peninsula plant. Perseus production will be added gradually as capacity on the Goodwyn platform allows.

The $1.6 billion Angel field production is due on stream in 2008, finally bringing gas to the Burrup plant from the third original North West Shelf field found in 1972. An unmanned platform will produce from Angel, with deliveries via a 50-km pipeline tying in to one of two trunklines from North Rankin to the coast.

To accommodate increased gas flow and fulfill LNG export and domestic pipeline gas supply contracts, the Woodside-led North West Shelf partnership has begun a $2 billion program to add a fifth LNG train at the Burrup Peninsula liquefaction plant. With a planned capacity of 4.4-million tonnes/ year, the train will increase total plant capacity to 16.3 million tonnes of LNG when it comes on stream at yearend 2008.

Woodside also is a 50:50 partner with BHP Billiton (operator) for the $800 million Stybarrow oil project in the Carnarvon basin 65 km northwest of Exmouth. Stybarrow lies in 800 m of water and will produce 80,000 b/d via subsea wells and an FPSO. Oil production will begin in 2008.

Farther south, oil production from the offshore Perth basin will begin in March-April when the Roc Oil Ltd. consortium's $227 million Cliff Head field development comes on stream. Partners are Roc Oil, Sydney; AWE; Wandoo Petroleum Pty. Ltd.; Arc Energy; and Cieco Exploration & Production (Australia) Pty. Ltd. The unmanned wellhead platform was installed in 18 m of water, 11 km offshore, in December 2005. Oil will be sent via subsea pipeline to a new onshore production facility at Arrowsmith near Geraldton before being trucked 350 km to BP's Kwinana refinery south of Perth. Initial production will be 10,000 b/d.

In the Timor Sea southwest of Jabiru field, AED Oil Ltd., Melbourne, is developing its 100%-owned Puffin oil field in Ashmore Cartier Permit AC/P22. ARCO discovered Puffin in 1972 - the first oil found in the Timor Sea - but it was not then considered commercial. AED plans a $100 million, two-well subsea development hooked into an FPSO and flowing at about 25,000 b/d when it comes on stream in midyear.

Woodside Energy (with Origin Energy, Benaris International, and CalEnergy, also expects its Thylacine-Geographe gas fields in the offshore Otway basin to come on stream by midyear. This $1 billion project includes a remotely operated, unmanned platform on Thylacine and a subsea pipeline to onshore treatment facilities near Port Campbell on Victoria's coast. Geographe field will have subsea wells tied in to the Thylacine system later. The sales gas will be injected into the South Australian-Victorian pipeline system.

Another offshore gas project nearing completion in southeastern Australia is Yolla field in the Tasmanian Bass basin being developed by the Origin Energy consortium (Origin, AWE, CalEnergy, and Wandoo Petroleum). Construction and equipment problems have pushed costs to more than $500 million, and the project is more than 12 months behind schedule. Now expected on stream in March, the development consists of a fixed steel platform and a 147-km subsea pipeline to the Victorian coast plus a 32 km onshore section to a gas treatment plant at Lang Lang about 80 km southeast of Melbourne. Sales gas will be sent by another 30 km pipeline to connect with Victoria's main gas trunkline from Gippsland basin fields.

Preliminary design work also has begun on the $300 million Kipper gas-condensate field development in Gippsland basin. Operated by ExxonMobil, the field straddles retention lease Vic/RL2 and production licenseVic/L9. The consortium includes BHP Billiton, Woodside, and Santos. Plans include subsea wells and associated pipelines to feed into the main ExxonMobil-BHP Billiton Bass Strait production system via West Tuna field's platform. First gas is expected in 2009.

Imminent projects

The most talked-about proposal is the Greater Gorgon Project, the Chevron group's $11 billion Gorgon gas-condensate development 130 km off Western Australia. The plan was restructured in early 2005 to include nearby ExxonMobil-operated Jansz field, and the framework agreement gave Chevron 50% of the project, while ExxonMobil and Shell have 25 % each. The proposal is for separate development of the two fields, with two pipelines feeding into two LNG trains on Barrow Island, each with 5 million tonnes/year of capacity. Gorgon field has a 12% carbon dioxide content, which will be separated on Barrow and sequestered in a reservoir sand deep under the island. Chevron has signed letters of intent to sell 1.5 million tonnes/year of LNG to Osaka Gas Corp. and a total of 2.7 million tonnes/year to Tokyo Gas and Chubu Electric Power Co. Inc. Shell is reported to be negotiating the sale of 14 million tonnes of LNG over 20 years with Indian company Gujarat State Petroleum Corp., but ExxonMobil has yet to make any public statement.

The project moved to the front-end engineering and design stage last July, and a financial decision will be made at the end of 2006. Approval will set 2010 as the target date for first LNG production.

Two other major LNG projects being discussed are Woodside's Pluto field development and the Woodside operated Browse basin field proposal, which includes the original North West Shelf partners BP, BHP Billiton, Chevron, and Shell. Driven by Woodside, the plan revolves around the huge Torosa (formerly called Scott Reef and Brecknock gas-condensate fields, found in the 1970s, and Calliance field (formerly Brecknock South), found in 2000, all 400 km off Western Australia's northwestern coast.

Two successful appraisal wells were drilled in 2005, and four more will be drilled in 2006. Total gas reserves are estimated at 20 Tcf with 300 million bbl of condensate. Preliminary development calls for a pipeline to a liquefaction plant at Broome on the Western Australia coast, with first production during 2011-14.

A number of other offshore projects are under study. These include the BHP Billiton-ExxonMobil 1979 Scarborough gas discovery on the Exmouth Plateau in which BHP is the driving force. The company hopes to bring gas ashore to a proposed LNG plant at Onslow, Western Australia. It would sell the LNG to the US, delivering to its proposed Cabrillo Port regasification plant off California.

Eni wants to develop its 100% owned Blacktip gas field in the Bonaparte Gulf via a pipeline across Northern Territory to Darwin, where it has made an in-principle 25-year gas supply agreement with Northern Territory Power & Water Corp.

Nexus Energy bought 100% of Crux gas-condensate field in the western Timor Sea in September 2005 and is evaluating plans for a liquids-stripping operation and FPSO development.

An intriguing concept is the Tassie Shoals artificial island LNG and methanol proposal in the Timor Sea planned by Methanol Australia Ltd., Melbourne. The methanol plant is a 50:50 partnership with Air Products & Chemicals Inc., Allentown, Pa., while the LNG project is 100% Methanol Australia's at this stage.
Initial plans revolve around gas supply from the Santos' large Evans Shoal gas field 12 km away to feed the plants, which will be built on concrete islands set on the seafloor in about 70 m of water. Methanol Australia has exploration prospects of its own in adjoining acreage and hopes that a drilling campaign this year will be successful enough to supply both plants.

The most questionable Australian project at present is Woodside group's Greater Sunrise gas fields straddling the joint development zone between Australia and Timor-Leste in the eastern Timor Sea. Some $250 million has been spent on appraisal drilling and feasibility studies that include piping gas to the new Wickham Point LNG plant near Darwin. However, the project has been put on hold until partners Woodside, ConocoPhillips, Shell, and Osaka Gas receive legal, regulatory, and fiscal certainty from Timor-Leste and Australia. Both governments signed an accord over 5O:50 division of royalties from the field in January, but this has yet to be ratified by the parliaments of either country.

Pipelines

All of Australia's development projects and concepts involve long-distance pipelines or shorter gathering lines to FPSO production facilities. However, the major independent pipeline project under discussion is the ExxonMobil-operated PNG-Australia trunkline proposal to bring gas from Papua New Guinea highland fields across Torres Strait to Australia with landfall in Queensland.

The 3,000-km pipeline will be built and owned by Australian Gas light (AGL) and Malaysia's Petronas. It will have possible offshoots to an alumina plant in northeastern Northern Territory and a link from Townsville on Queensland's east coast to Ballera in southwestern Queensland. The latter link would enable gas to flow from Papua New Guinea to southeastern Australia through existing interstate networks.

The ExxonMobil group has conditional sales agreements totaling 230 Pj/ year with CS Energy Ltd., Brisbane; AGL; Queensland energy distributor Energex; and Alcan. Feed studies for the project's pipeline and upstream sectors are nearing completion, and a final investment decision is expected in the second half of this year. If approval is given, first gas is expected in Australia during 2009.

In other trunkline activity, work has begun on a $430 million project to expand carrying capacity of the Dampier-Bunbury natural gas line in Western Australia by 100 Tj/day. The project involves installation of eight compressor units and looping of 200 km of pipeline.

Downstream

Main downstream projects over the last 2 years have involved Australia's four oil refiners - Caltex, Shell, BP, and ExxonMobil - in clean fuel developments. The companies have spent an average $400 million each in upgrading plants and equipment at the country's seven refineries to comply with federal fuel specifications. This means manufacture of diesel fuel with a maximum of 50 ppm sulfur content (down from 500 ppm) and gasoline with a benzene content of no more than 1% (down from 3%).

Elsewhere, downstream proposals have not fared well. This is typified by the withdrawal in January of Plenty River Corp., Melbourne, from a $900 million ammonium plant project on Burrup Peninsula in Western Australia. The company cited a failure to secure gas feedstock supplies because of the priority being given to LNG projects. Several other ammonium and gas-to liquids (GTL) proposals have failed to advance in Western Australia for similar reasons. The exception is a $630 million ammonium plant for Indian-owned Burrup Fertilizers, which is now nearing completion.

There is also a mini LNG plant nearing completion at Karratha in western Australia for Energy Developments Ltd. by Kryopak, Inc. It will liquefy gas from offshore North West Shelf fields and truck the LNG northward to four gas-fired power stations in the state's remote Kimberley district.

More-recent proposals include the possibility of a GTL plant in central Australia based on Amadeus basin gas discoveries and a $450 million condensate processing plant for Port Darwin, using feedstock from condensate associated with gas production in the Timor Sea. If approvals come through in 2006, construction of the latter plant could begin in 2007 for an on-stream date of 2009.

Westport Innovations, Beijing Tianhai Industry Co to Market LNG Tanks
Via Joint Venture Source: NGV Global Thursday, 01 September 2005

Westport Innovations Inc. of Canada and Beijing Tianhai Industry Co. Ltd. (BTIC) of China have signed a Letter of Intent to form a joint venture company to market and sell natural gas fuel tanks for the transportation market.

The 50:50 joint venture company, to be located in Beijing, will market and sell on-board liquefied natural gas (LNG) tanks for transportation applications. The fuel storage tanks will be produced in BTIC’s new Beijing cryogenic facility, currently under construction, with product expected to be available in 2006.

The joint venture will leverage both parents’ resources for sales, engineering, and operational personnel.
The joint venture is not restricted to Westport related engines and will make the tanks available to vehicles, regardless of engine manufacturer. In a press release, Mr. Wang Pingsheng, BTIC’s Chairman, said, “Customers are increasingly asking for complete solutions integrated with their existing vehicles.”

Westport President and COO, Michael Gallagher, says the joint venture will allow the commercialization of over four years of cryogenic technology development and is expected to result in an improvement in LNG vehicle economics. Information supplied by Westport Innovations – www.westport.com

Westport and EDL of Australia to Study HPDI for Off-Road Engines
For immediate release - February 8, 2005

Vancouver, British Columbia, Canada—Westport Innovations Inc. (TSX:WPT) today announced that it has signed a Memorandum of Understanding with Energy Developments Limited (EDL) of Queensland, Australia, to co-operatively explore business opportunities for Westport’s proprietary high pressure direct injection (HPDI) natural gas technology in off-road engine applications in Australia.

Based in Australia, EDL is a leading independent power producer, owning and operating over 60 power generation, renewable energy and waste fuel-to-energy facilities across Australia, the United States, Europe, and Asia with a total power generation capacity of 420 megawatts. EDL currently provides distributed electric power for remote communities and mining sites, and has signed a power purchase agreement, subject to conditions precedent, which will include the construction of its first liquefied natural gas (LNG) production facility in Western Australia.

Western Australia has extensive reserves of natural gas and supplies about 10 per cent of the world’s LNG. Natural gas in Australia is one-third to one-half of the cost in North America, and a number of mine sites also have access to coal-seam methane (CSM) that could be converted to LNG. This price advantage over diesel fuel offers strong economic incentive for fuel consumers to consider ways to use LNG in their operations.

Australian mines operate a significant portion of the world’s mine trucks that typically haul over 200 tonnes per truckload. These vehicles utilize high horsepower diesel engines that generate upwards of 2,000 horsepower and consume large quantities of fuel as they operate around the clock, every day of the year.

“Using natural gas in mining operations and other off-road applications in Australia offers significant benefits in terms of fuel cost savings and emission reductions. We believe that HPDI is ideally suited to the demanding industrial environments such as mine trucks”, said Bruce Hodgins, Westport’s Vice-President for Market Development. “With EDL’s customer base in the mining sector in Australia, and their interest to provide LNG fuel to these remote sites, we are encouraged that we will be able to build a strong business case for this initiative”.

HPDI delivers the high performance and high efficiency requirements of off-road applications such as mine trucks and railway locomotives. With HPDI engines, approximately 95% of the diesel fuel consumed in a diesel engine is displaced with natural gas. A typical mine truck with a HPDI natural gas engines could achieve emission reductions of approximately 14 tonnes of nitrogen oxides, 650 kilograms of particulate matter, and 950 tonnes of greenhouse gases per year.

Westport Innovations Inc. is the leading developer of technologies that allow engines to operate on clean-burning fuels such as natural gas, hydrogen, and hydrogen-enriched natural gas (HCNG). Westport has technology development alliances in place with Ford, MAN, BMW and Isuzu, and an ownership interest in Clean Energy, the largest provider of vehicular natural gas in North America. Cummins Westport Inc., Westport’s joint venture with Cummins Inc., manufactures and sells the world's widest range of low-emissions alternative fuel engines for commercial transportation applications such as trucks and buses.

EDL is a public company listed on the Australian Stock Exchange (ENE:ASX). It undertakes all aspects of power project development, including initial feasibility studies, design, site construction, financing and long-term operations and maintenance.

Energy Developments exceeds 420MW
Energy Developments operates an international portfolio of projects which continue to grow in size and diversity. These projects are focused on the provision of renewable and innovative energy and environmental solutions.

The Company's integrated project capabilities include development, finance, design, construction, operation and maintenance.

Generating capacity owned by Energy Developments exceeds 420MW. The Company has a portfolio of projects under development, which will further increase its generating capacity over the next few years.

Pine Creek, Northern Territory, Australia Power Generation
Solar Mars units Project Location: Pine Creek, Northern Territory, Australia Power Generation Capacity: 34.8MW Primary Fuel: Natural Gas Secondary Fuel: N/A Plant Type: Combined Cycle & Open Cycle Gas Turbine Power Purchaser: Power and Water Corporation Start of Operation: 1989
The Pine Creek power plant is a natural gas fuelled combined cycle power plant which supplies power to the utility transmission network in the Northern Territory.

The power plant includes a 27MW gas turbine combined cycle block and 8MW of open cycle gas turbine capacity. The combined cycle block comprises two gas turbine generator sets, two heat recovery steam generators, a steam turbine and ancillary equipment. The gas turbines are Solar Mars units, each with a nominal rating of 9.5MW. The heat recovery steam generators are dual pressure “once through” units. The steam turbine has a nominal rating of 8MW. Generation voltage is 11,000 volts. The open cycle gas turbines comprise three Solar Centaur units, each with a nominal rating of 2.4MW. Substations are installed to increase voltage to 132,000 volts, 66,000 volts or 22,000 volts for supply to the transmission network. Natural gas fuel for the power plant is supplied by a high pressure gas pipeline.

McArthur River Natural Gas Power Plant Project
Solar Taurus units and Solar Centaur units McArthur River Natural Gas Power Plant Project Location: McArthur River Mine, Northern Territory, Australia Power Generation Capacity: 20.9MW Primary Fuel: Natural Gas Secondary Fuel: Distillate Plant Type: Open Cycle Gas Turbine & Reciprocating Engine Power Purchaser: Power and Water Corporation Start of Operation: 1995 The McArthur River power plant is a natural gas fuelled plant which supplies power to the McArthur River base metal mine in the Northern Territory. The plant can also operate on distillate fuel if gas supply is interrupted. The power plant comprises six gas turbine generator sets and one gas engine generator set with a total generation capacity of 23.4MW. The gas turbines are Solar Taurus units and Solar Centaur units. Supply voltage to the customer is 11,000 volts. Natural gas fuel for the power plant is supplied by a high pressure gas pipeline.

Westport and ENE Enter Next Phase of HPDI Project in Australia
November 28, 2005 VANCOUVER, BRITISH COLUMBIA--(CCNMatthews - Nov. 28, 2005)

Westport Innovations Inc. (TSX:WPT) and Energy Developments Limited (ENE) (ASX:ENE) of Queensland, Australia, today announced they have signed a new exclusive agreement for the next phase of programme and business planning for liquefied natural gas (LNG) powered mine trucks.

The programme involves the application of Westport's proprietary High Pressure Direct Injection (HPDI) technology to allow large mine trucks to operate on liquefied natural gas (LNG). The two companies have completed the initial feasibility study commenced in February of this year. ENE will now provide A$150,000 (approximately C$130,000) to Westport for the completion of a detailed programme plan and budget, and a joint business plan for the commercialization of the LNG mine truck retrofit product. ENE intends to present these plans to its Board of Directors by the end of the first quarter of 2006.

The proposed programme forms part of ENE's plans for expanding LNG production and distribution in Australia. The abundance of stable, competitively-priced natural gas resources in Australia provides a significant economic incentive for LNG relative to the expected continuation of relatively high diesel fuel prices.

Australian mines operate a significant portion of the world's mine trucks that typically haul over 200 tonnes per truckload. These vehicles utilize high horsepower diesel engines that generate upwards of 2,000 horsepower and each truck can consume over one million litres of diesel fuel per year.

"We are encouraged by the customer interest in LNG for mine trucks and the feasibility study shows a win-win business opportunity where the mine operator, the environment, ENE, and Westport all prosper," said Bruce Hodgins, Westport's Vice-President for Market Development. "We are looking forward to working with ENE to develop a detailed programme plan and exploring how we can best work together to exploit this opportunity."

"With Energy Developments' market advantages and assets, and Westport Innovations' technologies and track record, our alliance fits with strategic opportunities opening up to Energy Developments in the use of LNG and CNG as a primary energy source in remote regions and for broader utilization in trucking applications, including for mine sites," said Jim Snow, ENE's Executive General Manager - Development.

HPDI delivers the high performance and high efficiency requirements of off-road applications such as mine trucks and railway locomotives. With HPDI engines, approximately 95% of the diesel fuel consumed in a diesel engine is displaced with natural gas. A 150-truck fleet of mine trucks with HPDI natural gas engines could achieve emissions reductions of approximately 21,000 tonnes of nitrogen oxides, 1,000 tonnes of particulate matter, and one million tonnes of greenhouse gases over the life of the fleet.

About Energy Developments Limited

Energy Developments Limited is a public company listed on the Australian Stock Exchange (ASX:ENE). It undertakes and integrates all aspects of power project development, including initial feasibility studies, design, site construction, financing and long-term operations and maintenance. Based in Australia, ENE is a leading independent power producer, owning and operating over 60 power generation facilities across Australia, the United States, Europe, and Asia with a total power generation capacity of over 430 megawatts. ENE currently provides distributed electric power for remote communities and mining sites, and has commenced the construction of its first liquefied natural gas (LNG) production facility in Western Australia as part of its West Kimberley Power Project.

About Westport Innovations Inc.

Westport Innovations Inc. is the leading developer of environmental technologies that allow engines to operate on clean-burning fuels such as natural gas, hydrogen, and hydrogen-enriched natural gas (HCNG). Westport has technology development alliances in place with Cummins, Ford, MAN, BMW, and Isuzu, as well as an ownership interest in Clean Energy, the largest provider of natural gas for vehicles in North America. Cummins Westport Inc., Westport's joint venture with Cummins Inc., manufactures and sells the world's widest range of low-emissions alternative fuel engines for commercial transportation applications such as trucks and buses. www.westport.com.

Note: This document contains forward-looking statements about Westport's business, operations, technology development, or the environment in which it operates, which are based on Westport's estimates, forecasts, and projections. These statements are not guarantees of future performance and involve risks and uncertainties that are difficult to predict, or are beyond Westport's control. Consequently, readers should not place any undue reliance on such forward-looking statements. In addition, these forward-looking statements relate to the date on which they are made. Westport disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

West Kimberley Power Project
http://www.energydevelopments.com/mainpage.asp

After extensive negotiations, Energy Developments and Western Power Corporation signed a 20-year power purchase agreement on 2 July 2004 to supply electricity to the West Kimberley towns of Broome, Derby, Camballin/Looma, Fitzroy Crossing and Halls Creek in Western Australia. The agreement is subject to important conditions precedent, including arranging finance for the project, obtaining appropriate approvals and the Company entering into agreements for the supply and delivery of natural gas.

Under the agreement, Energy Developments will construct four liquefied natural gas-fuelled power stations and one diesel-fuelled power station in the West Kimberley region. These power stations will have an initial generating capacity of 52 MW, potentially growing to 76 MW by the end of the 20-year agreement.

The Company will also build a liquefied natural gas plant near Karratha in the Pilbara region. This plant will be supplied by North West Shelf gas, delivered via the Dampier-Bunbury natural gas pipeline and then transported to the West Kimberley region by road.

Energy Developments expects to complete construction of the liquefied natural gas plant and commence electricity generation at the power stations during 2006. The capital cost of the project is approximately $150 million.

The project offers a range of economic, social and environmental benefits in the region. This includes: · introduction of a clean, reliable power source to the region that will reduce local greenhouse gas emissions by 25%; · installation of ultra-low noise generators to minimise operational impacts on local residents; · direct employment of at least 30 local people and creation of many other service and support industry positions; and · purchase of local services and materials during the construction phase of the project.

In addition, the Company will establish a $1 million community trust fund to be jointly administered by Energy Developments and the Western Australia Office of Energy. The trust fund will be used to fund community development projects in the West Kimberley region.

Westport Innovations and ENE Move to Next Step for LNG-Fueled Mine Trucks
November 28, 2005 Mine_truck http://www.greencarcongress.com/lng/

Westport Innovations and Energy Developments Limited (ENE) of Queensland, Australia, have completed the initial feasibility study (earlier post) and are now moving into the next phase of program and business planning for liquefied natural gas (LNG) powered mine trucks. The program involves the application of Westport’s proprietary High Pressure Direct Injection (HPDI) technology to allow large mine trucks to operate on liquefied natural gas (LNG). The two will now draw up a plan for the commercialization of the LNG mine truck retrofit product. ENE intends to present these plans to its Board of Directors by the end of the first quarter of 2006.

Australian mines operate a significant portion of the world’s mine trucks that typically haul more than 200 tonnes per truckload. These vehicles utilize high horsepower diesel engines that generate upwards of 2,000 horsepower. A single truck can consume more than one million liters (264,200 gallons US) of diesel fuel per year.

Hpdi HPDI:
The diesel fuel is delivered just prior to top-dead-center, followed by the main fuel quantity of natural gas.
High Pressure Direct Injection relies on late-cycle high-pressure injection of a gaseous fuel, such as natural gas, into the combustion chamber of a diesel engine.

Natural gas has a higher ignition temperature than diesel (1,000° C vs. 500° C) and will not easily ignite at the temperatures and pressures in the combustion chamber of a normal diesel engine. To assist with the ignition of natural gas, a small amount of diesel fuel is injected into the engine cylinder using a dual-concentric needle injector the same injector followed by the main natural gas fuel injection. The diesel fuel is delivered just prior to top-dead-center, followed by the main fuel quantity of natural gas.

The diesel fuel acts as a pilot or “liquid spark plug” which ignites rapidly the hot combustion products then igniting the natural gas. This gives the engine the efficiency and low-speed torque advantages of compression ignition while using natural gas as the primary fuel.

With HPDI engines, approximately 95% of the diesel fuel consumed in a diesel engine is displaced with natural gas. A 150-truck fleet of mine trucks with HPDI natural gas engines could achieve emissions reductions of approximately 21,000 tonnes of oxides of nitrogen oxides, 1,000 tonnes of particulate matter, and one million tonnes of greenhouse gases over the life of the fleet.

Australia CBM exploration and production
CBM is the naturally occurring, methane-rich gas in coal seams and commonly known in Australia as coal seam gas or coal seam methane. Bowen basin in Queensland and the Sydney basin in New South Wales

CBM exploration and production were of little significance in Australia until the late 1990s but are becoming an integral part of the Australian gas industry. The successful development of CBM fields has contributed to the diversification of gas supply sources, particularly in Queensland. CBM is poised to continue as an important energy source in Australia.
CBM and coalmine methane

The CBM that is associated with coal mining is traditionally called coalmine methane. A total of 300,000 m of directional in-seam drilling is carried out every year for degasification purposes to enhance minesite safety at underground and highwall open-cut collieries in the Bowen basin in Queensland and the Sydney basin in New South Wales. In comparison, about 184,000 m were drilled for stand-alone CBM exploration or production in 2004 in Australia.

About 51 PJ of coalmine methane were emitted to the atmosphere in Australia in 2004. This is 111% of the commercial production of CBM in Australia or about 5% of Australia’s total primary domestic gas consumption in the same year. Drained coalmine methane is used at several collieries as either pipeline gas or fuel for on site electric power generation.

The coalmine methane that is emitted through mine ventilation systems is called ventilation air methane, which is the largest source (about 58% in Australia) of coalmine methane emissions. Ventilation air methane is also an untapped potential energy resource. The potential use of mine ventilation air is largely restricted to on site power generation, because its methane content is very low (generally less than 1%). Specialized combustion reactors that can burn ventilation air methane are being installed at the Westcliff colliery in the Sydney basin.

Coalmine methane drainage and CBM resources are separately administered in both Queensland and New South Wales: the former by mineral resources legislation and the latter by petroleum resources legislation. In Victoria, however, CBM resources are administered under the legislation for mineral resources development.

As CBM is contained within the coal, conflicts between a developer of coal and coalmine methane and a developer of CBM can occur in an area where the CBM resource is located within a potentially economically minable coal deposit.

A new gas scheme was introduced in Queensland in January 2005. Designed to encourage the development of new gas supply sources such as CBM, the scheme requires electricity retailers to source at least 13% of their electricity from gas-fired generation or renewable resources. The 13% gas scheme has already acted as a catalyst for active exploration and development programs for CBM in Queensland.
Exploration and production

CBM exploration is based on hydrocarbon play concepts. However, traditional petroleum exploration theories and drilling practices are not necessarily applicable to CBM exploration and drilling. Permeability and gas content are the most important properties for CBM exploration and development.

CBM accumulations are not necessarily related to the presence of anticlines. However, many CBM project areas are located on anticlinal trends, although not all of these anticlines may form valid structural closures. In addition, CBM project areas are often located near conventional gas fields.

Anticlinal trends are attractive targets for CBM exploration because the depth to a coal seam is often less on an anticline than on its flanks and also because fracture development is often more intensive along the anticlinal axis.

The capital cost of drilling a CBM well has decreased greatly in the last decade, with fit-for-purpose drilling technologies tried and developed on site in Australia. Some new production wells comprise pairs of a horizontal drainage well and a directly connecting vertical production well or trios of two horizontal wells and a vertical well.

http://www.minerals.nsw.gov.au/geology
http://www.minerals.nsw.gov.au/prodServices/publications/commodities/petroleum/gas_publications

Petronas, AGL plan 1,200 km pipeline in Queensland
Rick Wilkinson OGJ Correspondent MELBOURNE, Jan. 30 2006

The Queensland government has announced plans to build a $1 billion (Aust.) gas pipeline from Townsville on the northeast coast to Ballera in the southwest corner of the state as an extension of the proposed PNG (Papua New Guinea-to-Australia) pipeline project (see map, OGJ, Sept. 11, 2000, p. 76).

The 1,200 km link is being proposed by the joint venture of Australian Gas Light Co. and Petronas, which are building and will own the PNG-Townsville section. The system will bring Papua New Guinea gas to markets in south eastern Australia, as Ballera is linked to Moomba, and Moomba has lines to Sydney and Adelaide.

Ballera also has pipelines extending north to the Gulf of Carpentaria and east to Brisbane.

An environmental impact assessment is being prepared for the Townsville-Ballera line. AGL-Petronas is endeavouring to get all development approvals before yearend so construction can begin by mid-2007.

LNG 160 Ton Per Day For West Kimberley Power Project
Energy Developments & Western Power Execute Ppa For West Kimberley Power Project
January 5th, 2005 Richlands, Queensland Australia

An Order Was Issued Today By Energy Developments To Kryopak Company (D.B.A. Salof Refrigeration Co., Inc.) For The Design And Manufacture Of A 160 Ton Per Day Liquid Natural Gas (Lng) Liquefaction Plant. The Lng Plant Will Be Located Near Karratha, Western Australia In The New Maitland Estate Development. The Lng Will Be Produced From Natural Gas Supplied From The North West Shelf Via The Dampier To Bunbury Natural Gas Pipeline. The Lng Will Be Used To Fuel Clean Burning Natural Gas Power Plants.

The Plant Will Be Based Upon Kryopak’S Pcmr Cycle And Will Ship In The End Of 2005.
Kryopak Has Also Been Retained For Onsite Engineering And Project Management.
The Plant Is Scheduled To Be Fully Operational 3rd Quarter Of 2006.

Energy Developments Limited (Ene) Friday 2 July 2004 For Immediate Release Asx Release

Energy Developments Announces That The Company Has Executed A 20 Year Power Purchase Agreement (Ppa) With Western Power Corporation (Western Power) In Respect Of The West Kimberley Power Project (Wkpp) At A Signing Ceremony Hosted By The West Australian Minister For Energy, The Hon. Eric Ripper Mla In Perth Today.

Energy Developments Was Selected By Western Power As The Single Preferred Bidder For The Wkpp In October 2003.

Ene’S Managing Director, Mr. Chris Laurie Said Today That The Signing Of The Ppa Was A Critical Milestone In The Delivery Of The West Kimberley Power Project, Culminating Extensive Negotiations With Western Power. “We Will Now Work Towards Financial Close And The Construction Of The Project Over The Next Eighteen Months”.

Mr. Laurie Said: “The Wkpp Will Be A Major Project For The Company, Reflecting Our Capability To Deliver Innovative And Cost Effective Power Solutions In Remote Regions Of Australia. We Look Forward To Working With Western Power And The Local Communities To Address Current And Future Power Requirements In The Region.”

Mr. Laurie Noted That The Project Will Also Underwrite The Company’S Capability To Develop The Market For Lng In The Pilbara And Kimberley Regions As An Alternative Fuel Source To Diesel, Especially For Road And Rail Transport. “We Expect This To Be Of Particular Interest To Mining Companies With Large Operations In The Region”, Mr. Laurie Added.

The Ppa Is Subject To Conditions Precedent Including Arranging Finance For The Project, Obtaining Appropriate Approvals And The Company Entering Into Agreements For The Supply And Delivery Of Natural Gas. This Process Is Expected To Take Several Months To Complete.

Further Details Of The Wkpp, The Ppa And The Likely Financing Arrangements For The Project Are Set Out In The Attachment To This Release.

Copies Of Western Power’S Media Release And West Kimberley Power Project - June 2004 Newsletter Also Released Today, Are Attached To This Release.

Ene Presently Owns Generation Capacity Of 420mw In Australia, United Kingdom, United States, France, Greece And Taiwan Fuelled By Landfill Gas, Coal Mine Waste Methane, Distillate And Natural Gas.

Attachment To Asx Release
The West Kimberley Power Project
Project Description

Under The Ppa And Associated Agreements, The Company Will Supply Lng And Diesel Fuel And Generate Power For The West Kimberley Towns Of Broome, Derby, Camballin/Looma, Fitzroy Crossing And Halls Creek.

The Initial Installed Generating Capacity For All Five Power Stations Will Be 52mw Including 10mw Of Diesel Plant Backup At Certain Of The Sites Growing To A Forecast 76mw By At The End Of The 20 Year Ppa Term. The Electricity For All But The Looma Power Station Will Be Generated By Caterpillar Reciprocating Natural Gas Engines Supplemented By A Mix Of Cummins And Caterpillar Diesel Engines. The Looma Power Station Will Be Based On Cummins Diesel Engines.

A Lng Plant Will Be Built Near Karratha And Natural Gas Will Be Supplied From The North West Shelf Via The Dampier To Bunbury Natural Gas Pipeline. Lng Will Be Transported By Road To Four West Kimberley Towns And The Road Transport Fleet Will Be Powered By Clean Burning Natural Gas.

Construction Of The Lng Plant Is Expected To Be Completed In Late 2005 With The Broome Power Station Scheduled To Commence Operations In December 2005. The Other Four Power Stations Will Be Brought On Line Over The Following Few Months.

Approximately $150 Million Will Be Spent In The Initial Construction Of The Power Stations, Lng Plant And Road Transport Fleet (Including Contingencies).

The Ppa
The Ppa Sets Out The Terms, Conditions And Specifications Pursuant To Which The Company Will Construct And Operate The Various Facilities And Supply Electricity To Western Power In Each Town. Under The Ppa The Company Will Receive Both Capacity Based Payments For The Provision Of The Power Generation And Related Facilities, And Variable Payments For Energy Supplied From Those Facilities.

The Company Is Responsible For The Total Construction Cost Of The Project, The Provision Of Reliable Electricity Supply To Each Of The Towns Under Specified Start Up And Ongoing Parameters And Fuel Supply And Costs For The Electricity Quantities Contracted By Western Power.

The Ppa Clearly Delineates The Rights And Obligations Of Both The Company As The Generator And Of Western Power As Distributor Of Electricity Respectively In The Region. It Reflects The Nature Of The Electricity Supply, The Remote Geographic Location And Western Power’S Statutory Obligations To Provide Reliable Power To The Region. The Ppa Covers Such Areas As The Reliability And Quality Of Supply, Satisfying The Expected Growth In Electricity Demand As Well As Force Majeure, Default, Step In And Suspension Rights.

Appropriate Project And Risk Management Systems And Supporting Commercial Arrangements Are Either In Place Or Will Be Implemented Prior To Financial Close.

Wkpp Financing
A Banking Consortium Has Been Mandated To Provide Finance For The Project And A Detailed Term Sheet Has Been Agreed.
It Is Intended That The Funding Will Be Structured As Follows:
.. During The Construction Phase – 100% Of Total Project Costs, Including Interest During Construction;
.. During The Operating Phase – Up To 80% Of Total Project Costs, Subject To Debt Sizing Parameters. This Finance Is Expected To Be Non-Recourse In Nature.
The Company Will Now Proceed To Document The Facility With The Banks And Their Advisers.
Media Release Western Power West Kimberley Power Project 2 July 2004

New Power Stations Will Be Built In Five West Kimberley Towns, Replacing Stations Up To 30 Years Old Under Agreements Signed Today. Western Power Chief Executive Officer Harvey Collins Said This Was An Excellent Outcome Of The West Kimberley Power Project. Mr Collins Signed A Power Purchase Agreement With Energy Developments Ltd Managing Director Mr Chris Laurie In Perth Today.

Energy Developments Ltd (Edl), A Listed Queensland Company With Solid Credentials In Electricity Generation, Was Selected From A Comprehensive, Competitive And Open Tender Process To Supply Western Power'S Electricity Requirements In The Five Towns.
"Although The Contract Negotiations Took Longer Than Expected, It Was Important That The Many And Complex Issues Were Resolved For The Benefit Of All Parties Including The Communities", He Said.

Four Of The Five New Power Stations – Broome, Derby, Fitzroy Crossing And Halls Creek – Will Be Gas-Fired. The New Power Station At Looma Which Will Supply The Looma And Camballin Communities, Will Operate On Diesel.
Broome Power Station Will Be The First To Be Completed, Targeted For December 2005. The Other Power Stations Will Be Commissioned Over The Following Six Months.
Mr Collins Reassured The Five Communities That Until The New Facilities Were Operating, Extra Generating Units Would Continue To Be Added To Local Power Stations As Needed To Meet Increased Demand.
"Eventually The Existing Stations Will Be Closed. Western Power Is Helping Displaced Employees And Their Families Secure Their Futures By Helping Them Identify And Develop Career Options Through Its Career Development Program."
"One Of The Community Benefits Of The West Kimberley Power Project Was The Creation Of Employment Opportunities," Mr Collins Said.

Edl Will Build An Lng Plant In The Maitland Industrial Estate About 20kms From Karratha And Transport The Gas By Road To The West Kimberley Communities Where It Will Be Stored Close To The Power Stations. At Broome, The Gas Will Be Piped 11km From A Storage Facility On The Outskirts Of Town To The Power Station.

There Will Also Be Significant Environmental Benefits Through Lower Greenhouse Emissions And All Five New Power Stations Will Be Much Quieter Than The Existing Ones.

Mr Collins Said The Agreements Were The Result Of Protracted And Complex Negotiations. He Congratulated Everyone Involved Especially Officers Of Western Power And Department Of Treasury And Finance And The Minister'S Representative.

Ends
Peter Winner Senior Media Relations Officer
Ph: (08) 9326 4597 Fax: (08) 9326 4984 Mob: 0429 041 840
E-Mail: Peter.Winner@Westernpower.Com.Au

Western Power
West Kimberley Power Project
Newsletter 19 – July 2004

The West Kimberley Power Project’S Main Objective Is To Replace Western Power’S Ageing Power Stations In Broome, Derby, Fitzroy Crossing, Halls Creek And Camballin With The Best Value For Money Solution Using A Competitive Tender Process.

Contract Signed!
It’S Official! Western Power Has Signed An Agreement With Energy Developments Limited (Edl) To Construct 5 New Power Stations And Supply Western Power’S Electricity Needs In The West Kimberley For 20 Years. The Minister For Energy, Mr Eric Ripper Mla, Gave Approval For Western Power To Enter Into The Agreement At A Signing Ceremony On 2 July. Ceo Harvey Collins Signed The Contract On Behalf Of Western Power And Managing Director Chris Laurie Signed On Behalf Of Edl.

Community Benefits
The Communities Will Be Big Winners With This New Agreement. Edl Has Signed An Agreement With The Office Of Energy (On Behalf Of The Minister For Energy And The Communities) That Confirms The Commitments Edl Made In Its Tender That Directly Benefit The Communities. A Copy Of This Agreement Will Be Given To The Three Shires, The Chambers Of Commerce And Industry And The Development Commission. It Will Be The Blueprint For Edl’S Involvement In The Region.

Apart From The More Efficient And Reliable Power Supplies To All The Communities, Significant Investment Will Flow To The Region During Construction And From Other Activities Associated With The New Power Supplies.

Economic, Social And Environmental Benefits From The Edl – Western Power Agreement Include:
.. Training And Employment Opportunities, Especially During The Construction Phase;
.. A $1 Million Trust Fund Set Up By Edl, The Proceeds Of Which Will Be Disbursed To The Five Communities;
.. Development Opportunities From Bringing A New Fuel Into The Region;
.. Reduced Noise And Other Environmental Emissions, And
.. A Boost To The Local Economy From The Investment.

Diesel For Looma
Edl’S Tender Was Based On Supplying Lng To All Five Towns. During The Negotiation Phase Western Power And Edl Agreed That Installing Diesel-Fired Generating Plant In The New Looma Power Station Would Be The Best Overall Solution. As The Combined Looma And Camballin Electricity Demand Was Relatively Small, The Technical Experts From Both Companies Agreed That Diesel Engines Would Provide Better Quality Of Supply To The Town.

The New Power Station Will Be 1.5 Km From The Looma Community And 4 Km From Camballin. The New Diesel Engines Will Be State-Of-The Art, Very Efficient, Quiet And Reliable With Relatively Low Greenhouse Gas Emissions. Even If The Road To The Power Station Is Cut-Off For Weeks, The Looma Power Station Will Have Ample Reserves Of Fuel.

Maitland Estate Development
As Part Of This Project, Edl Will Build A Liquefied Natural Gas (Lng) Production Plant And Loading Facility At The Maitland Estate, About 20 Kms West Of Karratha. Edl Will Be The First Occupant At The Estate, Helping With Its Establishment.

The Lng Will Be Transported In Specially Constructed Trailers To Broome, Derby, Fitzroy Crossing And Halls Creek. It Will Be Stored Close To The New Power Stations, Except At Broome Where The Gas Will Be Piped About 11 Kms From A Storage Facility To The New Power Station.

Edl Plans To Develop The Market For Lng In The Pilbara And The Kimberley By Focusing On The Road And Rail Transport Markets. This Exciting Development Will Be Kicked-Off By Using Gas Engines In The Prime Movers Carting Lng To The Power Stations.

What Happens Next?
Edl Has Committed To Ordering The Components Of The Lng Plant Immediately To Speed Up The Construction Phase. However, Before The Construction Work Can Begin In Earnest, Edl Must Satisfy A Number Of Conditions. Edl’S Main Task Is To Secure Finance For The Project. To Meet Their Banks’ Requirements, Edl Must Secure Access To Land For All Aspects Of The Project And The Necessary Permits And Approvals.

The Timetable In The Contract Calls For Edl To Have The Broome Power Station Operational In December 2005. The Other Four Power Stations Will Become Operational Over The Following Months.

Western Power Employees Futures
Recognising That Its Existing Power Station Employees Will Be Affected As The Old Power Stations Are Decommissioned And Edl Takes Over Generating Electricity In These Towns, Western Power Commenced A Comprehensive Career Development Program To Assist Power Station Staff Identify And Develop Career Options.

The Career Development Program Is The Most Comprehensive Program Of This Nature Undertaken By Western Power. Working With Experienced Consultants, Management Has Assisted Employees And Their Families To Develop Realistic Career Options Whilst At The Same Time Operating The Existing Power Stations Until The New Power Stations Are Established.

Positions Lost Within Western Power Will Be Offset By The Creation Of Employment Opportunities By Edl In These Towns.

Site Visits
Representatives From Western Power And Edl Will Visit Each Of The Towns In July To Discuss The Impact Of The Project In More Detail. At This Stage, Meetings With The Three Shires, The Kimberley Development Commission And The Chambers Of Commerce Are Planned As Well As Meetings With Community Representatives In Fitzroy Crossing And Looma.

Please Visit All The Salof Companies.
Salof Refrigeration Co., Inc. / Kryopak, Inc. / Acid Recovery Systems, Inc.
River City Industrial Refrigeration, Inc.

Australian LNG export Summary June 2006 Significant new and proposed liquified natural gas (LNG) projects. Oil & Gas Journal, October 17, 2005
	Australian Pipeline Trust
Australia's Reserves Part 1 Australia's Reserves Part 2	Gippsland basin contains one gas field, Patricia/Baleen	Carnarvon basin NWest Shelf contains a number of supergiant and giant gas and gas-condensate fields.
Chevron begins to drill Barrow CO2 study well	The_Otway_basin map Otway Basin Article	Otway basin CO2 sequestration trial advances March 13, 2006