CONTINUED ECONOMIC DOL- drums in Asia cast considerable uncertainty over many of the world`s LNG projects in 1998. As recently as 1997, robust forecasts for natural-gas demand in Asia had fueled a flurry of plans for new liquefaction plants, vessel newbuildings, and import terminals.
Asia is the major recipient of LNG as well as the major supplier, along with the Middle East. Plans for LNG projects became ever more tenuous as the economic crisis that started in mid-1997 dragged on.
The clouded future of LNG, as a component of overall natural-gas supply and demand, was reflected in late 1998 in a major study of the world`s LNG industry by the Institute of Gas Technology, Chicago, "An Overview of the Global Baseload LNG Industry."
In the 1990s, said IGT`s study, many forecasts projected natural gas to overtake coal as the second most used fuel and, driven mostly by power-generation projects, to grow by 8%/year through 2015 in Asia alone.
Such countries as China, India, and Thailand, lacking sufficient domestic resources to meet burgeoning domestic demand for natural gas, seemed likely to become important markets for natural gas supplied by tanker and pipeline.
But the economic outlook for the entire region, Korea, Indonesia, and Thailand especially, was very clouded. The IGT study noted three major areas of impact:
- Currency devaluation. Major Asian currencies had been sharply devalued, some by as much as 50%. As LNG contracts are denominated in U.S. dollars, such devaluations make LNG projects that much more expensive and likely therefore to be postponed or canceled.
- Reduced economic growth. Forecasts for the once-robust Asian economies turned sour, with those of the major countries-Thailand, Indonesia, Malaysia, Korea, and Japan-expected to contract short-term from between 3% to more than 13%.
- Lower credit ratings. The economy in the nation which imports the most LNG in the world-Japan-had not been providing the lift needed to show the remaining Asian nations how to reverse their economic tailspins. The result was greater difficulty raising funds for needed projects, which in themselves might otherwise boost an economy out of a spiral.
Yearly summary
IGT`s study reported LNG trading data for 1997, the most recent year for which complete data were available as 1999 began. Because of the long-term planning and commitments necessary in LNG trading, however, current trading patterns are unlikely to be drastically different.
Asia continued to dominate LNG imports and exports.
In 1997, Japan, Korea, and Taiwan received shipments of 75% of the world`s LNG trade (Table 1). Indeed, when combined, their LNG demand rose in 1997 by 23%, to 61.8 million tpy.
Japan, the world`s largest LNG importer, held 58% of the total, but its market grew by only 6.5% in 1997. The IGT study noted this as an indication of its maturity: Korean demand, by contrast, had been growing at 20%/year since 1986.
Europe, the other major world LNG market, witnessed growth of LNG imports in 1997 of almost 19% after little growth in 1996. With the recommissioning of its Panigaglia terminal, Italy resumed LNG imports.
And the U.S., although again nearly doubling its LNG imports, continued to hold a small portion of the world`s market for LNG.
For exports in 1997, Asian countries and Australia produced two thirds of the world`s LNG with Indonesia leading the way: 32% of total sales, down from 35% in 1996. Malaysia`s exports rose in 1997 upon start-up of the Dua plant the previous year.
Elsewhere, Algeria`s exports rose as that country`s plant revamps and expansions continued. And Qatar became the world`s ninth LNG-exporting country.
LNG production and exports were likely from Oman, Trinidad, and Nigeria before 2000, despite overall softening of world energy demand, given the long-term nature of LNG-supply contracts.
Technologies
By far the most important liquefaction trend had been the introduction of floating-liquefaction technology for use in producing from small, remote subsea fields. Oil & Gas Journal reported on two prominent proposals.
Mobil Technology Co., Dallas, put forward a world-scale plant design with capacity of 6 million tpy of LNG and up to 55,000 b/d of condensate produced from 1 bcfd of feed gas. The plant would be located on a large, square, concrete barge with a central moonpool.
LNG storage would be provided for 250,000 cu m and condensate storage for 650,000 bbl. Both products would be offloaded from the barge.
Also, BHP Petroleum Pty. Ltd. introduced its Compact LNG technology, jointly developed by BHP and Linde AG, Hollriegelskreuth, Germany. BHP had been marketing the technology and considered using it to develop the Bayu-Undan field in the Timor Sea, economics permitting.
The process is based on the conventional nitrogen cycle that BHP claimed to have optimized and dramatically improved in efficiency.
Specifically for the Bayu-Undan field, BHP designed a topsides with the Compact LNG process and storage tanks on a concrete gravity-base structure installed on the seabed.
The LNG design for Bayu-Undan incorporates a single pretreatment train to remove acid gases, water, and mercury. Two independent liquefaction and refrigeration trains each can produce 1.5 million tpy of LNG.
Relatedly, Mobil Technology Co. and Mobil Shipping & Transportation Co. introduced in 1998 a technology for converting LNG carriers to perform the added duty of offshore regasification, reported Oil & Gas Journal.
Dubbed Mobil Shipboard Regasification Terminal (SRT), it uses a conventional 125,000 cu m LNG carrier that can deliver as much as 300 MMscfd at pressures as high as 70 bar (1,015 psi). It can also deliver to conventional terminals without modification, said Mobil.
The design employs two LNG carriers retrofitted to hold the entire regasification system. When operating, both ships would contain full LNG tanks. Upon arrival at the discharge site, one ship would be moored to a piled single-point mooring (SPM) system.
LNG would be pumped to delivery pressure, regasified onboard, and discharged at ambient temperature via a high-pressure flexible hose. The gas would flow through a high-pressure swivel on the SPM, from which it would be transported ashore via a subsea pipeline.
The dual-carrier system provides nearly continuous delivery of gas, said Mobil.
An SRT can be set up in 24 months, said the company, half the time required to build conventional onshore LNG terminals. Capital costs are much lower, as well.
It was less a matter of whether these or other small-scale technologies will be adopted than of when. Combined with the popularity of gas-to-liquids technologies, these offered hope for developing small, remote natural-gas pockets that do not justify extensive production or transportation infrastructures.
Facilities
As of late 1998, distributed among the nine countries with liquefaction facilities were 59 trains capable of producing 97 million tpy (132 billion cu m; approximately 4.6 bcf). The nine countries were Abu Dhabi, Algeria, Australia, Brunei, Indonesia, Libya, Malaysia, Qatar, and the U.S. (Table 2).
All trains used the liquefaction process licensed by Air Products and Chemicals Inc. with the exception of the GL4Z, GL1K, and GL2K in Algeria and the Kenai, Alas., plant.
Plant size steadily increased since the 1964 inception of the baseload LNG industry at Camel, Algeria, said the IGT study: from 60-300 MMcfd in the 1980s to 450 MMcfd or more built in the 1990s.
For importing LNG, 36 terminals were operating at the end of 1998 in eight countries: 22 in Japan, 3 in Spain, 3 in the U.S. (including the Cove Point, Md., terminal for peak shaving), 2 in Korea, 2 in France, and 1 each in Italy, Belgium, Turkey, and Taiwan.
Consistent with the concentration of LNG trade in Asia, the 10 largest terminals operated there with both the largest and smallest in Japan.
The largest was the Sodegaura built by Tokyo Gas and Tokyo Electric in 1974 with 35 storage tanks capable of holding 2.7 million cu m of LNG. The smallest was at Kagoshima, where a single tank can hold 35,000 cu m of LNG.
The trend in Japan had been toward smaller terminals, reflecting the entry of smaller Japanese gas utilities into the LNG business, said the IGT study: Of the country`s gas sales, 25% was from approximately 240 small companies not linked by a major transmission grid. The big three Japanese utilities-Tokyo Gas Co. Ltd., Osaka Gas Co. Ltd., and Toho Gas Co. Ltd.-accounted for more than 75% of the country`s sales.
The 1990s saw a shift, said the IGT study, as medium-sized companies began converting from manufactured to natural gas and began building their own terminals to receive, store, and regasify imported LNG.
In addition to Korea and Turkey, major import terminals were planned or under way in India, further reflecting the concentration of LNG trade in Asia.
Shipments, shipping
LNG shipments in 1997, the most recent year for which complete statistics were available, set another record, according to LNG Log 23, an annual review of the state of LNG shipping-volumes, vessels, and routes-published by the Society of International Gas Tanker & Terminal Operators Ltd. (Sigtto), London. Its author from inception had been William duBarry Thomas, who retired upon completed of the latest report.
Shipments for 1997 consisted of 1,918 voyages of the world`s LNG fleet, landing 181.7 million cu m.
LNG loading terminals during the year increased by 1 to 12, thanks to the start up at Ras Laffan of Qatar Gas Corp.`s new plant.
Leading in number of shipments (379) was Bethioua (Algeria), followed by Bontang (Indonesia), Bintulu (Malaysia), and Blan Lancang (Indonesia). By quantity, Bontang and Bintulu nearly tied at approximately 33.1 million cu m each; Bethioua was not too far behind.
Blang Lancang, that takes production from the Aran complex, was fourth with more than 24.6 million cu m.
Eight active European terminals received nearly 23% of the total LNG (181.7 million cu m) delivered in the world in 1997, said the Sittgo report.
In Asia, 20 terminals (18 in Japan and 1 each in Korea and Taiwan) received more than 75%. The only two active terminals in the U.S. received 2%.
Shipping, the key link between export plants and import terminals, posed the largest question mark for LNG trade, according to the IGT study.
For 1997, IGT counted 103 tankers operating, up from 97 a year earlier: 14 in the 18-50,000 cu m class; 14 in the 50-100,000 cu m class; and 75 in the class of tankers with 120,000 cu m or greater capacities.
If projections for doubling of the world LNG trade by 2010 held, as many as 18 more tankers would be needed. This scenario called into question whether sufficient vessels could be ready, given the necessary long lead times required for vessels and shore infrastructure.
The IGT report also noted that only 13 shipyards in the world could build LNG tankers: nine in Asia (Japan and Korea), the other four in Europe.
Vessel size could reach 200,000 cu m with available techniques, although there was a trend toward smaller vessels: Earlier in the 1990s, Saibu Gas Co. Ltd., Japan`s fourth largest utility, built a small receiving terminal at Fukuoka to receive up to 360,000 tonnes/year from Malaysia and ordered the 18,000 cu m Aman Bintulu for delivery.
Older tankers, at the same time, were sailing longer, as a result of excellent maintenance, with life expectancy extended to 40 years or longer from the initial 25 years. Still, the report warned, the number of available vessels was limited and would remain so even as demand for them increased with start-up of the Trinidad and Nigerian projects.
The Sittgo study reported nine new vessels in the international LNG trade in 1997, among them the first four spherical-tank Kvaerner ships to serve the Qatargas routes from Ras Laffan-Al Khor, Al Wajbah, Al Rayyhan, and Al Zubarah, all 135,000-cu m sister ships.
The Das Island-based fleet of National Gas Shipping Co. grew by two vessels, said LNG Log 23. Commissioned were the 137,000-cu m Al Hamra and Umm Al Ashtan, both spherical-tank equipped vessels from Kvaerner Masa.
SNAM took delivery of the first of two 65,000-cu m vessels with Technigaz cargo tanks. Originally named the SNAM Portovenere, the vessel was rechristened LNG Portovenere.
The last of five 130,000-cu m Gas Transport vessels for Malaysia`s Petronas Marine Sendirian Berhad, the 18,928-cu m Puteri Firuz, went to Chantiers de l`Atlantique. And a second minicarrier, Aman Sendai, was received from NKK Corp. by Asia LNG Transport Sendirian Berhad for service between Bintulu and Sendai, Japan. It was equipped with three Technigaz membrane tanks.
In addition to moving in new vessels, world LNG trade also moved over some seven new routes, three of which resulted from the commissioning of the Qatargas liquefaction plant at Ras Laffan.
From there, new routes extended to Barcelona and the Japanese terminals at Chita (Chubu Electric) and Kawagoe.
A terminal opened in 1997 at Shin Minato to serve the City of Sendai`s municipal gas utility from Bintulu. And a new route to Japan connected Lumut (Brunei) with Higashi-Ohgishima in Tokyo Bay.
The other new routes were to the U.S.: LNG loaded at Whitnell Bay, Australia, delivered to Everett, Mass., and Lake Charles.
LNG Log 23 pointed out, from the vantange point of late 1998, that the continued economic weakness and uncertainties in Asia made for a conundrum: Currency fluctuations created some apparently remarkable bargains in shipbuilding in the Far East, while the same uncertainties upset some trade patterns by casting doubt over LNG-demand forecasts as well as the financing of several construction projects.
Nonetheless, several new vessels would likely see service in 1999 and 2000: Two additional Qatar ships were due for delivery in 1998 along with the LNG Lerici and the Aman Niri. And in 1999, shipments were to commence between Algeria and the Revithoussa terminal in Greece and Port Fortin, Trinidad, and Cabot LNG`s Everett, Mass., terminal.
U.S. situation
Despite a slight increase in exports, 1997 saw the U.S. become a net importer of LNG for the first time, Oil & Gas Journal reported in early 1999.
LNG imports nearly doubled, to 77.78 bcf from 40.27 bcf in 1996, an increase of 93.1%. These data were based on the most recently available from the U.S. Energy Information Administration (EIA).
Algeria supplied 65.67 bcf, Australia 9.69 bcf, and Abu Dhabi 2.42 bcf. About 60.7% of the imported LNG was received at Distrigas Corp.`s Everett, Mass., terminal just north of Boston. The remaining LNG landed at the Global Asset Development terminal in Lake Charles, La.
Total value of LNG imported by the U.S. in 1997 was $213 million at a yearly average price of $2.74/Mcf, a 2.1% decrease from the 1996 yearly average price of $2.80/Mcf.
Terminals, suppliers
In 1988, Distrigas`s terminal was restarted to receive LNG after being shut down in 1987. The terminal received 47.18 bcf (19 shipments) during 1997; 27.62 bcf (11 shipments) during first half 1998; and was projected to receive 55.2 bcf for all of 1998.
By early 1999, the company was to have completed a 150-MMcfd expansion of its vaporization capacity along with an expansion of the marine terminal and an upgrading of the terminal berthing.
Pan National`s LNG terminal at Lake Charles, La., reopened during 1989 and received one shipment of LNG from Algeria in December 1989. It received 30.60 bcf (12 shipments) during 1997; 15.17 bcf (7 shipments) during the first half of 1998; and was projected to receive 30.7 bcf for all of 1998.
The merger of Duke Power Co. and Pan Energy Corp. to create Duke Energy Corp. was completed in June 1997. Assets of the Pan National LNG receiving terminal at Lake Charles were transferred to Global Asset Development (Duke Energy Services).
Duke Energy LNG Marketing and Management Co. imported LNG from Australia under its short-term contract with Northwest Shelf LNG sellers. Also, it signed an agreement with Qatargas for supply of 57,000 metric tons of Qatari LNG in late 1998.
The Cove Point, Md., LNG facility continued to be used to liquefy indigenous natural gas and store the LNG for later regasification during the peak demand in the Central Atlantic and New England states. In the long term, the facility would likely be a receiving terminal for importing offshore LNG.
Southern Natural Gas`s LNG terminal at Elba Island, Ga., was likely to remain idle through 2003.
LNG baseload plants in Algeria had provided most of the LNG to the U.S. Spot purchases of LNG began entering the U.S. during 1996 from sources other than Algeria. About 4.95 bcf (two shipments) of LNG was imported from Abu Dhabi through Distrigas`s terminal in 1996.
Also, five spot purchases were made during 1997: one shipment (2.42 bcf) from Abu Dhabi and four shipments (9.69 bcf) from Australia.
The LNG baseload plant in Trinidad was to have been operating by mid-1999. The output was being marketed in New England and such West European countries as Portugal and Spain.
The proposed LNG baseload plant on the coast of Nigeria was to have its first train operating by 2000. Of the first train`s output, 3% was contracted to Distrigas. The remainder was slated for various West European customers.
Another potential LNG supply source to the U.S. market, Venezuela`s Cristobal Colon LNG project, continued to be on hold.
Exports
The Phillips Petroleum Co.-Marathon Oil Co. joint-venture operation in 1997 exported 62.19 bcf from the Port Nikiski baseload LNG plant on the Cook Inlet of southern Alaska for delivery to Tokyo Gas Ltd. and Tokyo Electric Power Co. Inc., Yokohama.
The 1997 LNG shipments represented a decrease of 8.1% from the 1996 export volume of 67.65 bcf. Total LNG sales revenue to Phillips and Marathon was $238.4 million in 1997, a decrease of 3.3% from the $246.6 million received during 1996. The average selling price increased 4.9% from $3.65/Mcf in 1996 to $3.83/Mcf in 1997.
The 5-year (1993-1997) shipping-price history of LNG leaving Port Nikiski was as follows: 1997, $3.83/MMBTU; 1996, $3.65/MMBTU; 1995, $3.41/MMBTU; 1994, $3.18/MMBTU; and 1993, $3.34/MMBTU.
In 1997, the U.S. was among seven countries supplying LNG to Japan: the others were Australia, Brunei, Indonesia, Malaysia, Qatar, and Abu Dhabi.
Indonesia was the major supplier at 37.6%; whereas the U.S. supplied only 2.6%. LNG exported to Japan from the U.S. was 62.2 bcf. Deliveries for the first 6 months of 1998 projected LNG for the full year would reach more than 63 bcf.
The slowdown in the Japanese economy had led to fewer power-generation requirements. Once the economy recovered, so would power requirements and in turn the LNG needs.
Phillips operated the LNG plant and Marathon the LNG carriers. Sales and facilities` interests were split Phillips 70%, Marathon 30%. Phillips and Marathon provided the feed gas to the LNG unit from gas fields in the upper Cook Inlet.
The Yukon Pacific LNG project was unlikely to affect the export of LNG from Alaska to Japan through 2003.
Developments
As 1999 began, prospects for several LNG deals among producers and markets in Asia, the Middle East, and Africa appeared to be improving (Table 3).
Oil & Gas Journal reported that three LNG producers in the Middle East signed deals to supply India. That country had several LNG import-terminal projects in dire need of supplies to meet local demand.
Elsewhere, Australian firms Woodside Petroleum Ltd. and Energy Equity Corp. agreed to build a $70 million (Australian) liquefaction plant at Port Hedland, Western Australia. The LNG was to be used for electricity generation in remote areas of the state.
Nigeria LNG Ltd. was considering a 45% expansion of its $3.7 billion Bonny Island LNG plant over 4 years. If consortium members agreed, the capacity of the plant would be increased to 8.7 million tpy from 5.9 million tpy. The first phase of the project neared completion in 1999.
India action
Oman LNG LLC, with Royal Dutch/Shell as lead partner, agreed to deliver LNG to India. The company was building the LNG plant and export terminal at Qalhat in northeastern Oman and anticipated first deliveries in April 2000.
The plant was to consist of two 3.3 million tpy liquefaction trains and process gas from a 360-km pipeline from fields in central Oman.
The sales agreement, with the Dabhol Power Co. in India`s Maharashtra state, called for delivery of 1.6 million tpy over 20 years beginning late in 2001. Oman LNG said the deal was unique in involving the first import of LNG by India and also because it was the first LNG contract in Asia signed with an independent power project.
The independent power producer planned to build an LNG tanker to ship its gas from Qalhat to the planned Indian terminal. Dabhol`s project was a 2,450-MW power plant being built 240 km south of Mumbai. Including a port, an LNG-import terminal, and a regasification plant, it was expected to cost nearly $1.8 billion.
Also in late 1998, Qatar`s Ras Laffan Liquefied Natural Gas Co. (Rasgas), with Mobil Corp. as lead partner, signed a heads of agreement with India`s Petronet LNG Ltd. detailing terms under which Rasgas would supply 7.5 million tpy of LNG.
Petronet LNG is a consortium of Gas Authority of India Ltd. (GAIL), Indian Oil Corp., Oil & Natural Gas Corp. (ONGC), Bharat Petroleum Corp., and Hindustan Petroleum Corp., which collectively held about 50%.
The remainder was to have been acquired by Japan`s Overseas Economic Cooperation Fund and U.S. insurance major American International Group. AIG also was picking up a 10% equity stake in Petronet India, the trunkline pipeline company affiliated with the LNG joint venture.
Petronet was formed to meet LNG demand mainly from the power sector in India.
In September, Petronet awarded Rasgas the tender to supply 5 million tpy of LNG to a terminal at Dahej, Gujarat, and an additional 2.5 million tpy to Cochin, Kerala. Deliveries were scheduled to begin in 2003.
The signing of the contract was expected to spur construction of three more LNG trains at Rasgas, increasing capacity to 15 million tpy.
In other Indian action, Yemen LNG Co. expected in 1999 to sign a 25-year supply agreement with BG plc to supply 2.65 million tpy of LNG.
The agreement would follow a memorandum of understanding signed by the firms in 1998 enabling the Yemen LNG partners to launch a call for tenders for construction of a planned LNG plant at Balhaf, Yemen, on the Gulf of Aden.
BG would import the LNG at a 5-million tpy terminal planned at Pipavav in India`s Gujarat state. Shipments were expected to begin in 2002-03 at start-up of the Yemeni plant.
BG may boost its imports from Yemen to 5.3 million tpy, all of the output from the $2.2 billion, two-train liquefaction plant. But Yemen LNG partner Total said the consortium was also looking for markets in Japan, South Korea, Taiwan, Turkey, and Lebanon.
And GAIL planned to pick up a 25% equity stake in a proposed LNG project being promoted by the Tata industrial group in collaboration with Total of France. The venture would supply 3 million tpy of LNG to bulk customers in and around the Trombay area in Mumbai city.
Australia
Melbourne`s Woodside Petroleum Ltd. formed an alliance in late 1998 with Perth-based Energy Equity Corp. (EEC) to build a $70 million LNG plant at Port Hedland, Western Australia.
The two companies were to submit a proposal to the Western Australian government to produce 50,000 tpy of LNG to be used for electricity generation to supply communities in the state`s remote Kimberley region, such as Broome, Derby, and Halls Creek.
The proposal was in response to Western Australia`s call for formal expressions of interest from the private sector to develop energy-generation capacity in the Kimberley region.
LNG would be delivered via specially built road LNG tankers. The plan called for Woodside and EEC each to own 50% of the project. EEC already operated a similar small LNG plant at Alice Springs, Australia, and trucked LNG to the Ularu (Ayers Rock) settlement for power generation.
Natural gas for the Port Hedland plant would come via pipeline from North West Shelf fields and the Burrup Peninsula gas-processing facilities to Port Hedland.
Discovery of more gas in the Carnarvon basin off Western Austrialia near year-end 1998 bolstered faltering prospects for the Gorgon LNG project.
Tests conducted by a Mobil Exploration & Producing Australia Pty. Ltd. group on two wells flowed 53.4 MMcfd of gas and 460 b/d of condensate from one and 37.4 MMscfd and 200 b/d of condensate from the other.
The wells are located among other fields targeted for development in support of the Gorgon LNG project.
Earlier in 1998, the Asian economic crisis appeared to have halted plans for the $8 billion (Australia) export project.
Participants Royal Dutch/Shell, Chevron Corp., Mobil Corp., and Texaco Inc. said they could not secure sales agreements before year-end. They had hoped for several 20-year contracts to supply about 8 million tpy to Asian markets, especially South Korea, and had sought first shipments for 2003.
Also, in late 1998, Woodside Energy Ltd., operator of the North West Shelf joint venture, awarded front-end engineering design for the proposed expansion of the North West Shelf LNG project to the Kellogg Joint Venture, consisting of M.W. Kellogg Co., JGC Corp., Kaiser Engineers Pty. Ltd., and Clough Engineering Ltd.
Construction was to commence by year-end 1999; total cost of design would be about $73 million (Australia). Expansion plans were to provide first LNG from the new plant in 2003.
Africa
Nigeria LNG Ltd. consortium members were meeting early in 1999 to discuss the 45% expansion of their $3.7 billion Bonny Island LNG plant over 4 years. The group included Nigeria, Shell Gas BV, Elf Aquitaine, and Agip International.
The two-train LNG plant was under construction and slated to begin deliveries in October 1999, but a third train may be warranted.
The two-train plant would require about 26.6 million cu m/day of feed gas, supplied by Shell, Agip, and Elf. The expansion would require the three participants to increase their upstream investments to expand gas production at various supply points.
Shell and Elf were already spending more than $318.4 million on gas supply projects.
The expansion would be the first stage of a $7.2 billion plan to boost the plant`s output to 8.7 million tpy from 5.9 million tpy. It was also expected to increase annual revenues from the project to $2.5 billion from $1 billion and reduce the volume of associated gas being flared in the Niger Delta by 75%.
Nigeria LNG had signed long-term contracts for 90% of the plant`s initial output. The buyers were Italy`s ENEL, Spain`s Enagas, Turkey`s Botas, and Gaz de France.
Western Hemisphere
In the Americas, Brazilian state petroleum company Petroleo Brasileiro SA and Royal Dutch/Shell unit Shell Brasil embarked on plans to build an LNG receiving and regasification terminal along Brazil`s northeastern coast.
The terminal would be located at the port of Suape, 30 km south of Recife, capital of the state of Pernambuco, and would be linked with one or more proposed thermoelectric power plants in the state fed by regasified LNG.
LNG-receipt capacity would be 75-210 MMcfd of gas, or about 1.5 million tpy. First deliveries were targeted for early 2003. Shell and Petrobras estimated total investment at about $200 million, netting each company a 50% stake in the jont venture.
Possible LNG source was the Trinidad and Tobago-based Atlantic LNG export project at Point Fortin, Trinidad.
Amoco Corp. and Repsol SA, Spain, proposed a second train to the plant, which was nearing completion by Atlantic LNG Co. Repsol would commit to almost 5 million tpy for 20 years, primarily for Spanish markets.
This would be in addition to gas already contracted for Repsol whose Enagas unit was to take 40% of Train 1`s 3 million tpy. Scheduled start-up of Train 1 was mid-1999. Cabot Trinidad Ltd. (10% shareholder) was to take 60% for sale in Puerto Rico.
Elsewhere in North America, the proposed $1.5 billion LNG project at Kitimat, B.C., was another casualty of Asia`s economic crisis. The project, to produce 4 million tpy for export to South Korea, was delayed until at least mid-2001.
Earlier plans had called for production to begin in 2000, but Calgary-based Pac-Rim LNG Inc. had difficulty securing a 20-year gas supply deal with Canadian producers.
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