CAPITAL: Canberra
MONETARY UNIT: Dollar
REFINING CAPACITY: 807,125 b/cd
OIL PRODUCTION: 591,900 b/d
OIL RESERVES: 2.9 billion bbl
GAS RESERVES: 44.6 tcf
A blast shook the Longford natural gas plant on Sept. 25, 1998, but continued rocking the Australian industry for months.
The explosion and fire caused a 2-week gas supply crisis in Victoria. Later, a royal commission began investigating the incident, and privatization of Victoria`s gas sector was accelerated in response to the incident.
The Longford plant processed oil and gas from Bass Strait fields and supplied 80% of the state`s gas needs. Oil and LPG supplies also were halted.
Bass Strait production of 200,000 b/d was offline for more than 2 months as a result of the Longford accident. Gas production resumed from Gas Plants 2 and 3 via a new pipeline that bypassed the damaged Gas Plant 1.
The Victorian Employers Chamber of Commerce & Industry calculated that businesses lost $1.3 billion (Australian) during the crisis and that the state`s export earnings had been slashed by as much as $200 million.
About 89,000 businesses were affected, a third of all those surveyed.
The Insurance Council of Australia said that claims for losses suffered during the outage period were expected to reach $150 million.
The accident prompted the Victorian government to move quickly to privatize the state`s gas distribution network. Three gas distribution-retail companies (Kinetik-Westar, Ikon-Multinet, and Energy21-Stratus) and the trunk line Transmission Pipelines Australia were expected to be sold by mid-1999 for about $4 billion. All four were formed from the breakup of the former state-owned Gas & Fuel Corp. in 1997.
Victoria Premier Jeff Kennett said the gas shortfall underscored the need for gas competition.
He said privatization would encourage exploration and development of alternative sources of gas supply beyond those from the Esso Australia Ltd.-BHP Petroleum Pty. Ltd. operations in Bass Strait, which had supplied about 98% of the state`s gas since the fields came on stream in the late 1960s.
Decontrol moves
Australia`s government overhauled the country`s gasoline retailing industry to increase competition and cut fuel prices for motorists.
ACCC stopped setting daily maximum wholesale gasoline prices. Gasoline and automotive diesel were also removed from government price surveillance.
The reforms also included a commitment by the four major downstream oil companies in Australia-units of Royal Dutch/Shell, British Petroleum Co. plc, Mobil Corp., and Caltex Petroleum Corp.-to allow open access to their terminals for independent bulk fuel suppliers.
Existing legislation controlling the location of service stations and who can operate fuel retail franchises was repealed in a move allowing the majors to directly control more retail sites.
In addition, the deregulation would permit refiners in Australia to enter into "horizontal arrangements," thus allowing sharing and swapping of production between refineries to achieve greater production efficiency and lower costs.
The government said the number of service stations in Australia would fall from 9,000 to 7,000 within a few years.
Australia passed the Gas Pipeline Access (Commonwealth) Bill to increase gas sector competition.
It ensured third-party access to gas pipelines and promoted an integrated market to enable gas to be traded across state and territory boundaries through an interconnected pipeline grid.
GAS users and retailers would be able to contract for supply of gas from competing sources. It also ensured a seamless access arrangement for offshore pipelines, a crucial point for the proposed Chevron pipeline from Papua New Guinea to Queensland.
Bass Strait
After the Victoria natural gas outage, Esso/BHP was under pressure to develop a new gas field in Bass Strait.
Australian Worldwide Exploration NL (AWE), which held a 10% interest in Kipper field, said its estimate of reserves had increased 22% to 889 bcf.
Esso/BHP (each with 25% of Kipper) had maintained the field was not commercial.
AWE said Kipper could supply up to about 46.5 bcf/year of gas for 15 years, close to 25% of Victoria`s demand. It said a $600 million development would include a pipeline from the field to a new processing plant at Orbost, about 200 km east of the Longford gas plant, plus an onshore link to the Victorian gas trunk line.
Esso Australia Resources Ltd. and BHP Petroleum Pty. Ltd. planned a $220 million development of Blackback oil field in Bass Strait off Victoria state.
The field was in 402 m of water about 18 km southeast of the existing Mackerel platform and 92 km off the coast.
The first stage would involve three subsea wells tapping 18.5 million bbl of reserves and 24 bcf of gas. They would be tied into the Mackerel system for pipeline transport to shore.
First oil was scheduled to come on stream in mid-1999 and peak at 18,000 b/d within a year.
Yolla gas field in the Bass basin off Tasmania was estimated to have reserves of 450-600 bcf and 70 million bbl of oil, according to partner Boral Ltd.
Work was proceeding to develop Yolla with an offshore platform and pipeline costing about $300 million together. Development would require contracts for a baseload of 14.25-19 bcf/year.
Participants were Boral 30.5%, Premier Oil plc 30.5%, CalEnergy Gas 20%, Cue Energy Ltd. 14%, and Santos Ltd. 5%.
The Australian government offered tax assistance for construction of Duke Energy Corp.`s Eastern Gas Pipeline, linking the Bass Strait fields to Sydney.
The $400 million project would get a rebate of up to $32.6 million over 5 years.
Construction was due to begin in mid-1999 for completion in mid-2000. BHP and Westcoast Energy of Canada originally promoted the project.
North West Shelf
Australia`s North West Shelf Project (NWSP) partners delayed building a second offshore gas pipeline to shore due to the Asian economic downturn.
The second line, expected to cost as much as $1 billion, had been planned to start up by 2000 to ensure that NWSP did not miss domestic sales due to lack of capacity in the existing 135-km pipeline.
NWSP operator Woodside Petroleum Pty. Ltd. said that timing of the second line would be linked to proposed expansion of the LNG project, scheduled to come on stream in 2003.
The Asian economic crisis also halted plans for a fast-track development of the proposed $8 billion Gorgon liquefied natural gas export (LNG) project on the North West Shelf.
The Gorgon participants had hoped to secure several 20-year contracts in 1998 to supply about 8 million metric tons/year of LNG to Asian markets, particularly South Korea, and had sought to have first shipments ready in 2003.
Sponsors were Western Australian Petroleum Pty. Ltd. (Wapet), a consortium of Chevron Asiatic Ltd., Texaco Oil Development, Mobil Australia Pty., and Shell Development (Australia) Pty. Ltd.
The group hoped to develop Gorgon area gas fields to feed an LNG plant that would consist of two 4 million metric ton/year liquefaction trains.
The development would include Gorgon, North Gorgon, Spar, West Tryal Rocks, Chrysaor, and Dionysus fields.
Mobil had a large gas discovery in the Carnarvon basin bolstering prospects for the Gorgon project. The John Brookes 1/ST-1 well on permit WA-214-P, drilled to 12,270 ft in 230 ft of water, flowed a combined 53.4 MMcfd of gas and 460 b/d of condensate from two zones. It was 5 km southwest of Tryal Rocks.
Apache Corp. brought its Stag platform off Western Australia on stream at 25,000 b/d. The $150 million project was in 150 ft of water, 37 miles northwest of Dampier, W.A.
Interest holders were operator Apache 33.3%, Santos Ltd. 54.2%, and Globex Far East 12.5%.
OIL flowed from a central processing facility on the platform through an 8-in. pipeline to a catenary anchor-leg mooring buoy about 1.2 miles away. The buoy forms a mooring for a 700,000 bbl floating storage and off-loading vessel.
Timor Sea
Phillips Petroleum Co. said plans to start up a Bayu-Undan LNG project by 2003 had been delayed 2-3 years by the Asian economic downturn.
BHP and Phillips also were at odds over whether to build an offshore LNG plant at the field or an onshore plant at Darwin.
Development of the field`s condensate reserves was under way, but gas liquefaction plans were on hold.
Woodside Petroleum group had a significant gas discovery with Sunset West 1. It was west of the Sunrise Troubador, Loxton Shoals, and Evan Shoal gas discoveries outside the Timor Gap.
The find would help support an LNG project with an onshore treatment and liquefaction plant proposed for the Darwin area. Woodside and partners BHP and Shell Development each held a one-third interest.
Shell and Timor Sea Petroleum Pty. confirmed Evans Shoal gas field in the Timor Sea as a substantial find. BHP drilled the discovery in 1988, but exports via LNG were not a viable option then.
Evans Shoal reserves were up to 6.5 tcf of gas, with a further 5.5 tcf from the Sunrise-Troubadour-Sunset-Loxton Shoal fields about 120 km north of Evans Shoal. Shell had 85% and Timor Sea Petroleum 15%.
Operator BHP Petroleum Pty. Ltd. and partner Canadian Occidental Petroleum Ltd. planned to develop Buffalo oil field with an unmanned fixed steel wellhead platform linked to a floating production, storage, and offloading vessel.
The field, 560 km northwest of Darwin, had reserves of 22 million bbl. Production was due to begin late in 1999 and build to 40,000 b/d. Development costs were $88 million.
Development would consist of three wells connected to a five-slot, unmanned wellhead platform in a shallow bank area in 30 m of water. The platform would be controlled from the vessel 2 km away in 250 m of water.
BHP Petroleum Ltd. reported first oil from Elang/Kakatua fields in the Timor Gap Zone of Cooperation between Australia and Indonesia. Four production wells were completed. Production was estimated at 33,000 b/d.
Pipelines
Santos Ltd. commissioned a gas pipeline from the Cooper basin fields to Mount Isa, in northwestern Queensland. Santos and partners would spend $200 million to upgrade the Ballera gas plant and perform field development work.
Broken Hill Petroleum Pty. Ltd sold its Karratha-to-Port Hedland gas pipeline in Northwest Western Australia to Epic Energy for $129 million.
Epic planned to extend the 215-km line 24 km from the North West Shelf joint venture facilities on Burrup Peninsula to the main pipeline inlet.
Epic revived a proposed $874 million expansion of its Dampier-to-Bunbury gas pipeline in Western Australia. It would add 84 MMcfd, in addition to 158 MMcfd previously planned.
Epic planned to eventually loop the system, which moves gas from North West Shelf fields to southwestern Western Australia. Epic bought it in March 1998 for $2.4 billion.
Australian Gas Light Co. and Western Power planned a $72 million, 530-km gas pipeline from the main Dampier-Bunbury trunk line to supply mining projects and townships in Western Australia`s Murchison region.
East Australian Pipeline Ltd. and Transmission Pipelines Australia commissioned the $50 million, 151-km InterConnect gas pipeline from Wagga Wagga, N.S.W., to Barnawatha, Vict.
The line linked South Australia`s Cooper basin fields with Victoria`s Bass Strait fields via the Moomba-Sydney pipeline and Victorian distribution network.
Transfield Energy Pty. Ltd., Sydney, and Tri-Star Petroleum Co., Midland, Tex., planned a $750 million, 700-km Queensland pipeline to link coal bed methane fields near Roma to a $70 million, 160-MW power plant under construction near Townsville.
The Southern Cross consortium acquired Western Mining Corp.`s 62.7% stake in Western Australia`s Goldfields gas pipeline for $402 million. The consortium (AGL Pipelines Ltd. 45%, CMS Gas Transmission & Storage 45%, and TransAlta Energy 10%) was expected to buy Normandy Mining`s 25.5% and BHP`s 12%.
The 1,400-km system extends from Karratha, near the Burrup Peninsula North West Shelf gas plant, to Kalgoorlie and Kambalda, 500 km east of Perth.
Duke Energy International LLC acquired the Queensland state gas transmission pipeline from PG&E Corp. for $200 million.
REFining ventures
Competition from large Asian export refineries forced Australian refiners to seek consolidations.
Shell Australia Ltd. and Mobil Oil Australia Ltd. considered combining their refining operations into a 50-50 joint venture, a $2 billion firm with 400,000 b/d of refining capacity.
Shell had refineries at Geelong, near Melbourne, and at Clyde, near Sydney; Mobil had refineries at Altona, near Melbourne, and at Port Stanvac, near Adelaide. Associated pipelines and ships were included, but marketing operations were not.
Mobil later withdrew from the talks. It explained that the government approval process would be "protracted and uncertain," especially in light of Mobil Corp.`s subsequent plans to merge with Exxon Corp.
BP Australia Ltd. and Caltex Australia Ltd. were discussing a joint venture (JV) to operate their refineries, plus the downstream supply and shipping functions.
The BP-Caltex venture would operate BP`s 73,000 b/d Bulwer Island refinery at Brisbane, Caltex`s 104,000 b/d Lytton refinery at Brisbane, Caltex`s 116,700 b/d Kurnell refinery at Sydney, and BP`s 138,000 b/d Kwinana refinery at Perth as an integrated system.
Each facility would specialize on certain products, achieving economies of scale. BP and Caltex would continue to operate their terminal and marketing operations independently.
ACCC said the BP/Caltex deal would raise substantial competition issues if the Shell-Mobil project had gone through, since the industry would be reduced to two entities.
BP and partners planned a $500 million expansion of their Bulwer Island refinery near Brisbane in southeastern Queensland. The project would increase capacity from 80,000 b/d to about 100,000 b/d.
The product emphasis would be switched to low-sulfur gasoline and diesel fuels. The expanded facilities were scheduled to come on stream in 2001.
Petrochemicals
Australia was working to attract petrochemical investments.
The government planned to offer $4 billion in incentives to attract petrochemical facilities in the Pilbara region of northwest Western Australia.
A combine of Dow Chemical Co. and Shell Chemicals Ltd. was selected as the leading contender. The combine planned a feasibility study in 1999 for a jointly owned 450,000 metric ton/year ethylene plant and a Shell-owned 400,000 ton/year monoethylene glycol plant.
A government task force said the country`s petrochemical industry was in rapid decline and was contributing to the growing trade deficit in plastics and petrochemicals, which was $5.4 billion in 1998.
Orica Ltd., Melbourne, agreed to a $1 billion merger with Kemcor, an Australian petrochemicals joint venture of Mobil Corp. and Exxon Corp. The entity would become the eighth largest polyethylene producer in the Asia-Pacific region with sales of $700 million/year. Orica would have 47% stake and Mobil and Exxon 26.5% each.
Broken Hill Pty. Ltd. and Incitec Ltd. planned a feasibility study for a fertilizer plant near Geelong, Vict. It would be supplied by the undeveloped Minerva gas field in the offshore Otway basin.
The plant would produce 455,000 metric tons/year of ammonia, which could be converted to 735,000 tons/year of urea. If approved, it could be in production in 2002.
