Western
Gas’ $3.5 billion Equus project |
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Western Gas’ $3.5 billion
Equus project currently on track for first gas in 2024 following the completion of the Upstream to LNG Development Plan and the start of project financing and partnering activities. The company will develop the field using a 2 mtpa FLNG facility, instead of feeding it into larger existing LNG facilities as was previously the project idea by the field’s previous owner Hess. The Equus gas project comprises 11 gas and condensate fields in the Carnarvon basin, some 200 kilometers north-west of Onslow in Western Australia. Western Gas said on Wednesday that the Upstream to LNG Development Plan comprises three production wells tied back to an FPSO facility, a 160—kilometer dry gas export pipeline to a nearshore 2 mtpa FLNG facility and an onshore pipeline connection. Western Gas executive director Andrew Leibovitch said: “Equus is at the right stage of development where the introduction of an experienced and financially capable partner can help progress the project to first gas and realize the value of the greater Equus area.” Western Gas added that engineering firms McDermott and Baker Hughes designed a globally competitive, mid-scale LNG development plan for Equus. It is worth mentioning that Western Gas spokesman Tony Johnson told Reuters that the company had spoken to yet undisclosed parties about potentially taking a stake in the Equus project. The firm also appointed Goldman Sachs as the company’s financial adviser in connection with its partnering process. Currently, with no joint venture misalignment, Western Gas has full control of project design, delivery, and partnering across the value chain. |
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Total
Takes Stake in Browse Basin Permit Offshore Australia Total 2/2/2007 Browse basin Nexus receives permit 2006 Chevron makes significant natural gas find in Australia 8/18/10 worldoil.com |
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Queensland
southeastern
Cooper basin 2006 Browse basin Royal Dutch Shell PLC 2006 Australia Nexus Accepts Shell's Offer AC/P23 permit Great Artesian Suspends Cadenza-1 Gas Discovery Cooper Basin 11 MMcfd Victoria Petroleum potential 23 mlb oil 2006 |
Casino
gas field on
stream off Victoria 2006 Carnarvon basin northwest Australia 2006 Tap Oil Makes New Oil Discovery with Amulet-1 Exploration Well 2006 Canning Basin Permit Empire O&G 7/06 Ichthys LNG Project Total Takes Stake |
Australia EPA oppose Gorgon-Jansz LNG Gov override | Perth basin in Western Australia OGJ 2005 |
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Average
Price of Natural Gas to Industry, 2002
One thousand cubic feet (1
Mcf) ~ 1.05 GJ 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 1: Data are for 4th quarter 2002 or latest available Source: International Energy Agency, Key World Energy Statistics, 2003 |
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Australia LNG | |
Australia
’s natural gas reserves 90
trillion cubic feet One
Bcf ~ 1.05 petajoules
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Liquefied
Natural Gas (LNG) Pipelines |
Papua
New Guinea to Queensland, Australia
3,600 km gas pipeline |
Australia $420b worth of projects in pipeline |
The
Australian
Pipeline Trust (APT) Australian Gas Light (AGL) operated ty APT |
Australia Eni developing Blacktip gas field |
A
new gas scheme was introduced
in Queensland coalmine methane use has increased substantially |
CBM
exploration
and production CBM drilling activity |
Perth
basin
|
Bonaparte Basin Map |
Carnarvon
Basin
Chevron
wins
block off northwest Australia
Carnarvon basin in the Northwest Shelf contains a number of supergiant and giant gas and gas-condensate fields. Carnarvon Map |
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Australia
coalbed
methane Map |
Northern
Territory
Condensate plant proposed |
Gippsland basin contains one gas field, Patricia/Baleen |
Otway basin Casino gas field on stream off Victoria Otway_basin Map |
Australia's
Reserves 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. The Otway basin farther to the west contains three gas fields that were classified as EDR in “Oil and Gas Resources of Australia 2002.”3 In January 2005, BHP Billiton started production from one of these, Minerva. The field is 10 km offshore in 60 m of water. The Minerva development consists of two subsea wells and a flowline for transport of gas to the onshore gas processing plant, where gas liquids are removed prior to exporting the gas to market. Two other offshore gas fields, Thylacine and Geographe, are under development. Nearby Casino gas field is in advanced planning. Another significant field, Henry, has recently been discovered adjacent to Casino. Due to the proximity of domestic markets, it is probable the remaining EDR field and any future large gas discoveries will be brought into production rapidly. In the same area in April 2004 the Australian government granted production licenses to Woodside Energy Ltd., Perth, over Geographe and Thylacine gas fields (the Otway Gas Project). The fields are 55 and 70 km offshore in 80-100 m of water. The project includes construction of an onshore gas processing plant, construction of the 11.5-km onshore pipeline from the shore crossing to the gas plant, the shore crossing, 70 km of offshore pipeline tied in to the Thylacine offshore platform, construction and installation of the offshore platform over Thylacine field, and drilling of four Thylacine production wells. Initially the Otway Gas Project will produce 55 bcf/year of sales gas. The reserves for the combined Geographe and Thylacine fields are publicly estimated at 800 bcf of gas and 9 million bbl of condensate. Production is to begin in mid-2006. New exploration incentives The number of exploration wells drilled off Australia over the last decade has averaged 56/year with a maximum of 73 in 1998. In 2004, 44 offshore wildcat wells were drilled. The industry in Australia, however, talks of the need to find a new Bass Strait (a new major oil province). This is because estimates of future production of oil and condensate suggest that at the mean expectation production rates would drop by around 50% by 2010 largely due to a drop in oil production. The 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 the oil reserves that are being produced.3 9 The Australian government announced its new initiative largely in response to the demonstrated decline in forecast production of oil in Australia over the next 10 years. The government acknowledges that 90% of all oil exploration success in Australia since the 1940s has been directly underpinned by geoscience information and advice given by Geoscience Australia and its predecessor organizations. Consequently, the government is providing via Geoscience Australia substantial support free of charge to help industry in the search for a new oil province. The new $25 million (Aus.) program for enhanced data access was announced in May 2003 as described by Williamson and Foster7 and has been under way for 2 years. The program aims to further stimulate industry activity in Australia. As part of this program the government has sought to increase the ready access to exploration data. The aim of the initiative is particularly to allow for new data to promote petroleum exploration in areas that could provide the possibility of a major new oil province. Funding is over 4 years to provide vital geological and seismic data to companies considering oil exploration in Australia. Products from the program include commercial seismic and other data that have been collected over the Bremer, Mentelle, and Vlaming subbasins off southwestern Australia that are publicly available at the cost of transfer. The results of studies of these data will be presented in a workshop in Canberra in October 2005. Consultation had been undertaken with the Australian and international petroleum exploration industry to identify areas that show the greatest potential for containing large undiscovered oil provinces. Areas have been defined in the south, west, and east of Australia as possible targets for new data collection. A new geochemical data set was collected as the seeps and signatures study on the North West Shelf and Arafura Sea. This study of natural hydrocarbon seepage and related geology in the Yampi shelf and Arafura Sea emphasized best practice methods through alliances with international groups proficient in the field. Synthetic aperture radar data was also used to investigate the presence of oil seepages. The aim of these precompetitive surveys was to establish that a suitable geological history has occurred for large oil accumulations to have been formed and that oil is actually present in the area. The targeted areas over the next 3 years range from shelfal depths to deep water. The likelihood of this program succeeding is helped by the very low level of total exploration around Australia. The relatively small number of wells drilled in such a large area as Australia leaves considerable opportunity for further exploration, discovery, and development. The data collected by Geoscience Australia for this initiative will be the subject of ongoing regional studies that will be publicly available. Areas for studies by Geoscience Australia have been prioritized. Survey data will continue to be acquired over these areas over the next 2 years. The results of precompetitive studies of these regions will be available for explorers to assess the prospectivity of acreage in the regions made available for bidding under the work program bidding system in Australia.7 10 Funding is also being provided to enable the copying of more than half a million tapes held by Geoscience Australia onto modern storage media. This preservation is necessary to ensure valuable seismic data are not lost because of the deterioration of old technology tapes. The government allocated $25 million (Aus.) to allow remastering of seismic data in the repository and collection of new data to further stimulate exploration. Over 250,000 field tapes from previous exploration have already been remastered to high-density media and can be more conveniently loaned to industry. The tapes of field data and processed surveys are being remastered to 3590 cartridges. The greater data availability of data allowed by the remastering is now seeing more than twice the usual levels of data being loaned for assessment of petroleum exploration acreage released in April 2005. For this part of the initiative, remastering of data began in November 2003 and will continue to mid-2007. The program is on schedule. The priority is to remaster data on older media most likely to be affected by stiction that threatens loss of data. Industry has greeted the decision as a vital step in enhancing the attraction of Australia as a place to invest in petroleum exploration. This initiative builds on Australia’s already superior access to petroleum exploration data that began with the enactment of the “Petroleum Search Subsidy Act” in 1957, when petroleum exploration data at low to no cost became publicly available from Geoscience Australia after a brief confidentiality period. Petroleum companies have since then used the data to assess the prospectivity of release acreage and help in decisions to take up acreage. Geoscience Australia and state and federal colleagues use the data described above and other data to promote the gazetted exploration release acreage that is announced at the Australian Petroleum Production and Exploration Conference early each year. In addition new tax incentives were introduced in 2004 and continued in the 2005 release to further stimulate offshore frontier exploration. Nominated frontier areas offered in the acreage releases will attract 150% uplift for tax purposes. This is on top of a fiscal regime and political stability that already encourage petroleum exploration and development and have resulted in established oil and gas provinces. References 1. Nelson, R., “Time to turn the key for exploration,” in “Prospect,” June to August 2005, Western Australian Government, 2005. 2. Geoscience Australia, “Oil and Gas Resources of Australia 2003,” Geoscience Australia, Canberra, 2005. 3. Geoscience Australia, “Oil and Gas Resources of Australia 2002,” Geoscience Australia, Canberra, 2004. 4. Quantum Harris, “Offshore Petroleum Information Review Report,” prepared for Department of Primary Industry and Energy, April 1995, 80 p. 5. Powell, T.G., “Australia’s hydrocarbon provinces-Where will the future production come from?,” APPEA Journal, Vol. 44, No. 1, 2004, pp. 729-740. 6. Longley, I.M., Bradshaw, M.T., and Hebberger, J., “Australian Petroleum Provinces of the 21st Century,” in Downey, M., Threet, J., and Morgan, W., eds., “Petroleum Provinces of the 21st Century,” AAPG Memoir 74, 2001. 7. Williamson, P.E., and Foster, C., “New Australian initiatives for greater access to exploration data,” OGJ, Apr. 26, 2004, pp. 37-46. 8. Western Australian Department of Industry and Resources, 2005 (http://www.doir.wa.gov.au). 9. Powell, T.G., “Understanding Australia’s petroleum resources, future production trends and the role of frontiers,” APPEA Journal, Vol. 41, No. 1, 2001, pp. 273-285. 10. Williamson, P.E., and Foster, C., “Access to Australian exploration and production data: a critical factor in attracting investment,” APEA Journal, Vol. 43, No. 1, 2003, pp. 693-704. The authors Paul Williamson (paul.williamson@ga.gov.au) is group leader of the innovation and specialist services group with Geoscience Australia. His interests have been in petroleum prospectivity analysis, the structure of continental margins, petroleum technical advice, identified petroleum resources, and petroleum data management and access. Current responsibilities are for specialist geoscientific and database services for assessing and promoting prospectivity. Steven le Poidevin (steve.lepoidevin@ga.gov.au) is a senior petroleum engineer in the petroleum and greenhouse gas advice group of Geoscience Australia. His interests are in assessing Australian oil and gas reserves and identified resources and providing engineering technical advice to regulators of Australian offshore petroleum exploration and production. |
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OGJ, Oct. 24, 2005, p. 51
Australia's Reserves 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 (Fig. 5). 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. |
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Australia ’s natural gas
reserves 90 trillion cubic feet (Tcf), the largest reserve in the
Asia Pacific region (2004E). The most abundant reserves are located offshore of the northwestern coast in the Carnavoran Basin (40 Tcf of proven natural gas), an area more well-known as the Northwest Shelf. Other important basins, including the Cooper/Eromanga basin in Central Australia and the Bass/Gippsland basin offshore of southern Australian, account for approximately 10 Tcf of reserves. Natural gas presently plays a relatively small role in Australia ’s fuel mix (approximately 17%), but consumption has grown steadily, from 710 Bcf in 1995 to 893 Bcf in 2002. Australia ’s natural gas consumption is projected to grow twice as fast as the consumption of other energy sources in the next two decades, and it is expected to account for 24% of total energy consumption by 2020. Natural gas production in Australia has increased rapidly since 1995, from 690 Bcf to 1.26 Tcf in 2002. Despite declining production capacity in the Cooper/Eromonga Basin, production is expected to grow 3.5% in 2004. An explosion at Santos ’ Moomba gas-processing plant in January 2004 has further affected natural gas production. The status of abundant reserves in the Timor Sea has been partially resolved. In May 2002, East Timor expanded its maritime territory claim and challenged Australia ’s claim to 25 Tcf of reserves in the Browse/Bonaparte Basin. In March 2003, the Timor Gap Agreement was established, creating a Joint Development Area (JDA) between the countries and setting the division of royalties from hydrocarbon production at 90:10 in favor of East Timor . Only the Bayu Undan natural gas field (3.4 Tcf), which began operation in February 2004, lies wholly within the JDA. Eighty percent of the Greater Sunrise field (9.3 Tcf) is located outside of the JDA. The Timor Sea also contains natural gas in the Evans Shoal, Petrel, and Tern gas fields, estimated to contain 4 Tcf of natural gas combined. ConocoPhillips, Woodside, and Shell are the main operators in the Timor Sea . Recent natural gas exploration in Australia has resulted in several important discoveries including ExxonMobil’s June 2002 discovery of 20 Tcf of natural gas in the Jansz field of the Northwest Shelf. In 2001, natural gas discoveries were made in Southern Australia 's Otway Basin , raising estimates of that basin’s reserves to 1.6 Tcf. Furthermore, Apache Corporation recently announced that 800 Bcf of reserves had been identified at its John Brookes site. In September 2004, Woodside Petroleum announced a find in the Polkadot-1 exploration well off the northern coast. It is expected to begin production in 2005. Additional natural gas discoveries will likely be made inadvertently as a byproduct of Australia ’s recent surge in petroleum exploration, as past exploration in the deep waters off Southern Australia has primarily resulted in the discovery of natural gas. Coal Bed Methane Map Pipelines Australia ’s existing pipeline infrastructure is fragmented and was built to carry gas from centrally located fields to coastal urban hubs including Sydney and Melbourne. With centrally located fields in decline, however, and offshore projects on the rise, a large investment in the country’s pipeline network will be necessary to bring additional natural gas into the grid. Australia estimates that it will require US$5.5 billion of new investment over ten years to efficiently use natural gas to generate power. In May 2004, Woodside and Origin Energy announced their commitment to the development of offshore Otway Basin gas reserves. Construction of the Thylacine gas field will begin this month, while development of the Geographe field will be connected at a later date. Recent announcements of two other projects rely on discoveries from the 1970s. Woodside indicated that Browse, another proposed Australian LNG station, will begin exports by 2011. BHP is considering a floating LNG facility to process the estimated 8 Tcf in its Scarborough reserves, and it announced in September 2004 that Onslow was the preferred site for another facility. The Australian Pipeline Trust (APT) operates over 4,350 miles of pipelines (oil and gas combined), while Epic Energy operates around 2,485 miles of pipelines (oil and gas combined). Although Australian Gas Light (AGL) is the leading owner of gas pipelines, they are operated by APT. Ongoing tensions between pipeline companies and regulators may discourage the entry of new investors. For example, Australian Epic Energy put its pipeline assets up for sale in September 2003 after determining that regulated pipeline tariffs were too low for profitable operation. Other companies, including the Australian Pipeline Trust, have halted construction on proposed pipelines due to regulatory environmental concerns. In August 2004, the Australian Pipeline Trust began negotiations with US-based CMS to sell US$158 million of gas pipelines in Western Australia . Many Australian and international investors, as well as the Australian Pipeline Industry Association (APIA), are calling for regulatory reforms to improve the situation. Australia $420b worth of projects in pipeline February 7, 2006 - 8:09AM Australian mining and transport companies and governments have $420 billion worth of projects in the pipeline, a new survey shows. The Delta Electricity/Access Economics investment monitor report released Tuesday showed the total value of projects planned or under way at the end of December 2005 was $420 billion, up $21 billion or 5.4 per cent on the September quarter. The figure was up 27.5 per cent on a year ago. The value of mining and metals projects under construction was up 131 per cent on a year ago, with high energy prices putting a focus on liquid natural gas. The report showed significant investment in iron ore, coal, gold, nickel, alumina and aluminium. The value of projects under construction and committed to, known as definite projects, fell $7.9 billion to $121.9 billion over the September quarter, reflecting completion of some significant projects such as Sydney's M7 Motorway and the Port of Dampier upgrade. But the figure was up $7.1 billion from 12 months ago. |
Liquefied Natural Gas (LNG) Liquefied natural gas (LNG) exports have greatly increased Australia ’s natural gas production since it began exporting the commodity in 1989. In 2002, Australia was the world’s sixth largest LNG exporter, accounting for 7% of global LNG exports. Japan is the primary destination of Australia ’s LNG supplies, with smaller shipments to South Korea and Spain . Australia secured contracts to supply LNG to China in 2002 and South Korea in 2003. Initial negotiations began with Mexico in September 2004 in an effort to tap the LNG market on the US West Coast. Australia ’s natural gas reserves are found in three areas: the Bass Strait , the Cooper/Eromanga Basin, and on its west and northwest coasts. The Northwest Shelf Venture (NSV), a consortium of six energy companies led by Woodside Petroleum, operates three offshore LNG trains. It relies on natural gas supplies from North Rankin (19.3 Tcf) and nearby fields of the Northwest Shelf (NWS). NWS produces 8% of world LNG supplies, mostly for export to Japan . Construction on a fourth train was completed in July 2004. A fifth train has been proposed, but has only received support from Woodside and BHP Billiton. Further support for another train may be influenced by NSV’s winning a bid to supply China ’s Guandong LNG terminal beginning in 2005. The development of pipelines across the western half of the country may allow NWS to supply domestically to Australia ’s southeastern states in the future as well. Although NSV dominates Australia ’s LNG market, other LNG projects are being developed as well. NSV members ChevronTexaco (57% ownership), Shell (29%) and ExxonMobil (14%) are developing a proposal for the Northwest Shelf's 12.9-Tcf Gorgon field. The project entails the construction of a pipeline to transport natural gas from the Gorgon field to Australia ’s Barrow Island , where a liquefaction plant with an annual capacity of 238 Bcf per year is to be constructed. ChevronTexaco has secured an agreement with an affiliate for the delivery of 95 Bcf per year from the Gorgon Venture to North America over a 20-year period beginning in 2008. In April 2004, Australia began talks with China ’s largest oil firm, CNOOC, to purchase a 12.5% share of Gorgon’s proven reserves. An estimated US$21 billion in sales over 25 years would make such a deal the largest export commitment in Australian history. ConocoPhillips has proceeded with plans to construct a liquefaction plant on Australia ’s northern coast (at Darwin ) to be supplied by natural gas from the developing Bayu/Undan field (3.4 Tcf) by 2005. ConocoPhillips has a majority interest (64.4%) in the project, which it is developing with Santos (11.83%), Italy 's ENI (12%), and Japan 's Inpex (11.71%). In March 2002, ConocoPhillips arranged to sell 3.6 million tons (convert) of LNG per year from the Darwin plant to Tokyo Electric Power Company and Tokyo Gas Company for 17 years beginning in 2006. Another LNG project, led by Woodside Petroleum (33%) in a consortium with ConocoPhillips (30%), Royal Dutch/Shell (27%) and Osaka (10%), has been proposed for the Greater Sunrise natural gas field (9 Tcf) in the Timor Sea . The consortium has announced its plans to develop the project by constructing a floating LNG plant with a proposed capacity of 238 Bcf per year. Production is scheduled to begin in 2008. Australia is also a significant exporter of LPG. Because the majority of reserves are located in the Northwest Shelf, however, the country is a net importer of LPG in its southeastern region. LPG consumption has fallen in the last several years, as energy efficiency measures have taken hold; production, however, continues to rise. Duke Energy completed sub sea gas pipelines to link the mainland with Tasmania in both 2002 and 2003. Proposals for more pipelines have been delayed, as both Duke Energy and Epic Energy are in the process of selling pipeline assets. In March 2004, Duke announced the sale of three Australian gas pipelines and three gas-fired power stations to Alinta. Current proposed natural gas pipeline projects reflect Australia ’s changing supply base, including offshore projects to support the LNG ventures described above. The 423-mile Sea Gas pipeline, which brings natural gas from the Otway Basin to Southern Australia ’s Quarintine power station in Adelaide , was recently completed. A 1,300-mile proposed pipeline from Papua New Guinea (PNG) to Australia will deliver gas from the Kutubu/Moran natural gas fields in PNG Queensland. Progress on the pipeline has been paralyzed by a lack of commitment from its potential buyers. In February 2004, Oil Search Ltd, the main developer of the pipeline, committed to beginning its design without the requisite funding, noting that gas could flow by 2008 with investment of US$70 million from minority partners. Australia $420b worth of projects in pipeline In January 2004, the Australian government also commissioned a feasibility study on a possible 1,800 mile transcontinental pipeline to ship gas from the Carnarvon and Browse Basins to southeastern domestic markets. The report said the fall in definite projects over the quarter was not of significant concern yet, but all eyes would be on the mining sector in the coming year. "The pull back in the value of definite projects is not a major concern as yet, with ABS data showing that for those projects which are under way, there is still a high level of investment spending yet to be done," the report said. "The value of projects in planning is very healthy. "What may be more concerning is that resources is becoming the key driver of investment and resources is the most volatile component of investment." The value of projects in planning was $154.9 billion "under consideration" and $143.2 billion which are "possible", the study said. |
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