Global LNG capacities and trade moved into unfamiliar and unsettling territory in 2009-10. As recession has driven down global energy demand, not least for natural gas, progress on approving, building, and commissioning yet more LNG plants and terminals has barely paused.
Nowhere was this more evident than for Asia, the world's largest LNG producing and marketing region and historically the center of the LNG world. There, recession seemed to land only glancing blows, depending on which economy you looked at. And the region has seen in the past year approvals of projects whose scale only a few years ago seemed daunting to many planners.
Large production projects for Australia and nearby Papua New Guinea moved from proposed to planned to construction in the past year. More are expected in 2010. Major markets, especially in China, have continued to approve and build terminals, anticipating little if any lag in demand growth and sensing the need at least to begin to reduce energy production from dirtier hydrocarbon sources than natural gas.
This article will set the backdrop for the future of global natural gas demand, production, and reserves. Then, it will review recent events and current status of major projects in the Asia-Pacific region.
Global view
Natural gas demand worldwide will resume its rise in 2010, according to the International Energy Agency's 2009 World Energy Outlook. The pace of that growth, however, depends not only on the strength of economic recovery and growth but also on the strength of global climate policy action, the IEA report said late last year.
IEA's Reference Scenario, which assumes no change in current governmental climate policies, projects global primary gas demand to rise by 41% to 4.3 trillion cu m in 2030 from 3.0 trillion cu m in 2007. That represents an increase of 1.5%/year.
Most of this increase—more than 80%—will take place in countries outside the Organization for Economic Cooperation and Development—in developing countries, in other words, such as most of Asia-Pacific. The largest rise occurs in the Middle East, and power remains the largest driver of gas demand in all regions.
Under IEA's 450 Scenario, which assumes governments take strong action to cut CO2 emissions, 2007-30 global gas demand grows by 17%, at 0.7%/year but 17% lower in 2030, compared with the Reference Scenario.
IEA's analysis of global gas reserves shows remaining resources "easily large enough" to meet any conceivable rate of demand increase through to 2030 and well beyond. Developing new resources will be more costly over the period, however.
IEA estimates the long-term recoverable global gas resource base at more than 850 trillion cu m, of which 45% is unconventional gas (shale gas, tight gas, and coalbed methane). The roles of both shale gas in US LNG demand and of CBM in Australia's supply projects will be dealt with shortly.
Non-OECD countries will account for almost all of the projected increase in global natural gas production 2007-30 in both IEA's scenarios. Under both scenarios, the Middle East, with the largest reserves and the lowest production costs, will see the biggest increase in absolute terms in production and exports.
The share of unconventional gas globally will rise to 15% in 2030, from 12% in 2007. IEA cautions, however, that this particular projection is "subject to considerable uncertainty," especially after 2020. There is potential for "output to increase much more."
IEA said the rapid development of unconventional gas resources in the US and Canada, particularly in the last 3 years, has transformed the gas-market outlook, not only in North America but also in other parts of the world.
The boom in North American unconventional gas production, together with the recession's depression of demand will contribute to an acute gas glut in the next few years. And that scenario has important implications for flows of LNG to newly built LNG terminals and those under construction in all three countries of North America.
Underutilization of pipeline capacity between the main supply-market regions as well as global LNG liquefaction capacity will rise to close to 200 billion cu m over 2012-15 from around 60 billion cu m in 2007, as several new projects come on stream.
Gas suppliers to Europe and Asia-Pacific will come under increasing pressure to modify pricing terms and cut prices to stimulate demand, said IEA.
Against this backdrop, the following section looks at the status of LNG supply and receiving projects in Asia. There, several megaprojects for developing supply have taken decisive steps in the past year or expect to move ahead this year.
Large projects advance
With commissioning of Train 1 completed, Sakhalin 2 sent out the first scheduled Russian LNG cargo aboard the LNG carrier Energy Frontier in February 2009. Delivery was to two of the company's foundation customers, Tokyo Gas and Tokyo Electric (OGJ, Apr. 6, 2009, p. 12).
In May last year, Train 2 facilities came on stream, bringing total export capacity at Sakhalin 2 to 9.6 million tpy.
Media reports early this year cited Sakhalin 2 operator Sakhalin Energy as stating the project sent out 81 cargoes of LNG in 2009. Total LNG volumes shipped from Sakhalin 2 reached 5.3-5.7 million tonnes, Platts LNG Daily reported.
Sakhalin Energy consists of state-owned Gazprom (50% plus one share), Royal Dutch Shell PLC (27.5%), Japan's Mitsui (12.5%), and Japan's Mitsubishi (10%).
By far the most important LNG story of 2009 for Asia, however, was the green light given to the massive Gorgon LNG project.
In September, Gorgon joint-venture partners Chevron Corp., ExxonMobil Corp., and Royal Dutch Shell made the final investment decision to move ahead with the nearly $3.8 billion project.
With a total gas resource estimate of 40 tcf, Gorgon will be the largest resource development project in Australia's history (OGJ Online, Sept. 14, 2009). Construction is under way at the Barrow Island site. First LNG deliveries are set for 2014. Domestic gas is slated to come on stream by yearend 2015.
The site will contain a three-train, 15 million tpy LNG plant, condensate handling, CO2 injection, and associated utilities. Chevron says about three LNG shipments per week will leave the loading jetty.
A unique element of the huge project is the planned CO2 sequestration via injection into storage reservoirs at 2,000 m depths. The partners estimate the economic life of the project at 40 years.
Late last year, Japanese utility Chubu Electric Power Co. acquired 0.417% of Gorgon Chevron. The Japanese utility also agreed to buy 1.44 million tpy of LNG from project operator Chevron for 25 years beginning in 2014. The deal entitles Chubu to an additional 60,000 tpy based on its stake.
Chubu was the third Japanese firm to buy a stake in the project. Tokyo Gas Co. bought 1% and Osaka Gas Co. 1.25%. Chevron originally held 50% of the project, while Royal Dutch Shell PLC and ExxonMobil hold 25% each.
Closely related to the Gorgon project is Wheatstone, which along with nearby Iago field, will underpin a two-train, 8.6 million tpy LNG plant at Ashburton North, 12 km west of Onslow on the Pilbara coast of Western Australia. Adjacent to the LNG plant will also be a domestic gas plant whose capacity has yet to be announced.
Eventually, says the company, the LNG plant may produce up to 25 million tpy.
Chevron has said Wheatstone and Iago fields hold enough gas to support the project's first phase with gas from Julimar and Brunello fields expected to extend the life of the first phase.
In December of last year, Chevron Australia signed a supply agreement with Tokyo Electric Power Co. for 4.1 million tpy of LNG over 20 years. In addition, Tepco was expected to acquire a 15% interest in Wheatstone field licenses along with an 11.25% interest in planned gas processing (OGJ Online, Dec. 7, 2009).
Chevron expects to make an FID on Wheatstone in 2011.
Another major Australian production project moved closer to reality earlier this year when Woodside Petroleum Ltd. and its Browse joint-venture partners agreed to develop an LNG plant at James Price Point in the Kimberley region of northwest Western Australia (OGJ Online, Feb. 9, 2010). The three-train, 12-million-tpy plant will process gas moved via a 218-mile pipeline from Browse basin fields off Western Australia.
Woodside said the partners would be moving ahead with design work ahead of an FID by mid-2012 on the estimated $30 billion (Aus.) plant.
The company awarded dual contracts for the basis of design phase to Bechtel Oil, Gas and Chemical-Bechtel Australia and to Kellogg Brown & Root for the onshore part. Contracts for offshore elements were awarded to a joint venture of WorleyParsons Services and Granherne for facilities scope and to J.P. Kenny for the subsea and pipelines scope.
Last month, Woodside awarded KBR Inc. the 9-month frontend engineering and design contract for Browse. Western Australia's government has estimated the overall cost of Browse at about $30 billion (Aus.). Partners are Chevron Corp., BHP Billiton, BP PLC, and Royal Dutch Shell.
The Browse project appears to have absorbed a major blow in January when foundation customer PetroChina Co. Ltd. allowed to lapse its agreement to take as much as 3 million tpy from Browse.
Woodside said, however, that key terms of a 2007 agreement with Taiwan's Chinese Petroleum Corp. for Browse LNG remain in place and Woodside continues to negotiate a detailed supply agreement.
Woodside has also reached agreement with Osaka Gas to advance talks on the company's projects, including the potential sale of up to 1.5 million tpy of Browse (OGJ Online, Jan. 8, 2010).
Woodside's Pluto LNG project on the Burrup Peninsula will process gas from Pluto and Xena gas fields in the Carnarvon basin about 190 km northwest of Karratha, WA. Train 1 will be able to produce 4.3 million tpy with first cargo late this year or early 2011.
Pluto's joint-venture participants are Woodside (90%, operator), Tokyo Gas (5%), and Kansai Electric (5%).
Floating liquefaction may also be in store for Shell to develop the Prelude and Concerto gas discoveries in the Browse basin off Australia's northwest coast.
Pending FID in the next 12-18 months, Prelude FLNG is in frontend engineering and design with a consortium of Technip and Samsung Heavy Industries. Prelude production could come by around 2015, according to Shell.
If the plans move ahead, this would represent the world's first floating liquefaction plant. Floating or dockside regasification has been around since Excelerate's Gulf Gateway Energy Bridge installation in the US Gulf of Mexico off Louisiana in 2005.
The planned Prelude plant would measure about 480 m by 75 m and be able to produce 3.5 million tpy of LNG, 400,000 tpy of LPG, and 1.3 million tpy of condensate over the 20 years of the project,
CSG backstops LNG projects
So far, all of Australia's LNG production has been on the western and northwestern coasts. But recent heightened exploration and development in the country's coalseam gas areas of Queensland state promise to support several LNG export projects at the eastern port Gladstone (map).
Australia has led the way in monetizing natural gas reserves embedded in coal seams. CSG exploration and production in Queensland focus primarily on two basins: Bowen and Surat.
Queensland's Department of Mines and Energy cites total CSG proved and probable reserves in Bowen and Surat basins at yearend 2008 as slightly more than 14.7 tcf: about 9.6 tcf for Surat and 5.2 tcf for Bowen.
In 2008, it further states, production increased to about 125 tcf, more than 80% of the domestic Queensland gas market.
Production from the Jurassic Walloon coal measures in the Surat basin has established the basin as an important supply source. Previously production had been based on the Permian coal measures of the Bowen basin.
The Permian-Triassic Bowen first produced commercial quantities of natural gas from the Dawson River CSG area near Moura in 1996 and later from the Fairview CSG area near Injune in 1998. At present, CSG commercial production occurs in the central and southern parts of the basin near Moranbah, Injune, Moura, and Wandoan.
Queensland's Departmentn of Mines and Energy says that in recent years the Jurassic-Cretaceous Surat basin in southern Queensland has grown in importance as a CSG source. Coal is more shallow in this area than in the Bowen and less "thermally mature," states the agency, with generally lower gas content that is compensated for by higher permeability.
The shallower coal also results in lower drilling and completion costs.
Commercial production of CSG from the Surat basin began in January 2006 from the Kogan North CSG area west of Dalby, followed in May 2006 by production from the Berwyndale South CSG area, southwest of Chinchilla.
Certified proved and probable reserves in the Surat basin have increased rapidly in recent years. At yearend 2006, Surat 2P reserves were a bit more than 1.2 tcf; Bowen reserves were nearly 3.1 tcf. By mid-June 2008, certified CSG reserves in Surat had overtaken those in Bowen.
To feed likely LNG plant development in and around Gladstone as well as domestic state markets, nearly 2,500 miles of gas transmission pipelines have been built.
Following are the major LNG proposals based on Queensland's CSG:
• Queensland Curtis LNG. Last month, BG Group PLC said it will expand the planned two-train, Phase 1 capacity at its Curtis LNG project to 8.5 million tpy from 7.4 million tpy. Coalseam reserves behind the planned plant are 17.3 tcf.
BG has already signed supply contracts for 8.3 million tpy and expects to make an FID later this year. BG's plant on Curtis Island near Gladstone would begin production in 2014 after receiving CSG produced by Queensland Gas Co. in an expansion of its operations in the Surat basin.
Moving the gas to the plant will be a 453-mile pipeline link. That pipeline network includes a 236-mile export pipeline from the Surat basin to Gladstone, a possible 93-mile lateral to connect additional CSG fields to the export pipeline, a 124-mile collection header to collect gas from centralized compression for delivery to the export pipeline, and a pipeline crossing at the narrows connecting the mainland export pipeline with the LNG plant on Curtis island.
The LNG plant will be built and operated in the Curtis Island Industry Precinct of the Gladstone State Development Area. Initially, plant LNG production capacity was envisioned at 12 million tpy, consisting of three, 4-million tpy production trains. As noted, those plans have changed.
On site LNG storage will be in three, 180,000-cu m full-containment storage tanks; space will remain for a fourth tank if needed. There will also be a 100,000-cu m, full-containment propane storage tank.
• Gladstone Liquefied Natural Gas. Australian oil and gas company Santos Ltd. expects to reach an FID this year on its Gladstone LNG project, in joint venture with Malaysia's Petronas. The partners expect first gas production in 2014. Santos will operate and own 60% of the project.
The project is to have production capacity of 3.6 million tpy in its first phase and has been forecast to cost about $7.7 billion (Aus.). News reports earlier this year, however, cited analysts in saying that cost could jump to $8.6 billion.
Last year, GLNG reached agreement with Petronas to sell it 2 million tpy of LNG with an option for an additional 1 million tpy. The agreement underpins the volumes from the planned 3.6-million tpy Train 1 of GLNG. FID on the project is expected by mid-2010.
The project involves exploration and production of CSG in the Surat and Bowen basin gas fields; construction and operation of a 270-mile gas pipeline from the gas fields to Gladstone; and construction and operation of an LNG export plant on Curtis Island.
• Fisherman's Landing. Arrow Energy Ltd. announced agreement last month with Liquefied Natural Gas Ltd. to acquire all of LNG Ltd.'s subsidiary Gladstone LNG Pty. Ltd. (OGJ Online, Feb. 11, 2010) and associated infrastructure in Gladstone.
In October last year, WorleyParsons assumed program management on the FEED study for the Surat-gas based project that is to boost Surat-basin CSG production to supply the Queensland market and to support the proposed 1.5-million tpy liquefaction plant at Fisherman's Landing. That plant will use LNG Ltd.'s proprietary optimized single mixed-refrigerant liquefaction technology (OSMR).
The FEED study is to be completed this quarter with an FID by Apr. 1. At this stage first LNG production is still expected in late 2012.
The Arrow announcement in February said the new agreement supersedes an announcement in January that "contemplated increased equity participation" in the project by Arrow. The agreement is subject to completion of due diligence by Arrow and to LNG Ltd.'s gaining shareholder approval at a meeting to be held by Apr. 1.
• Australia-Pacific LNG. Last month, the Australia Pacific LNG joint venture, consisting of ConocoPhilips and Australia's Origin Energy, filed its draft EIS with the Queensland state government for a planned CSG LNG project.
The EIS covers the project's maximum development case: gas fields in southern central Queensland, a 280-mile gas transmission pipeline, and a four-train, 14-million tpy LNG plant near Laird Point, on Curtis Island in Gladstone. Also included are plans for three, 188,000-cu m LNG storage tanks.
APLNG has said it plans to make an FID by yearend with first production likely in 2014. Forecast cost is about $35 billion (Aus.).
ConocoPhillips paid Origin almost $8 billion in September 2008 for 50% of Origin's CSG LNG project, which was subsequently named Australia-Pacific LNG.
• Shell's Curtis Island. In early 2009, Shell Australia announced an agreement with Gladstone Ports Corp. to investigate a site on Curtis Island for an LNG plant. The plan was for Arrow Energy to supply the feed gas from its CSG acreage jointly owned with Shell in the Surat and Bowen basins.
Shell bought 30% of Arrow's CSG acreage in Queensland and a 10% stake in Arrow International, a wholly owned subsidiary of Arrow that holds Arrow's international interests in CSG.
At yearend 2009, Shell CSG (Australia) Pty. Ltd., a wholly owned subsidiary of Royal Dutch Shell, signed an agreement with the Gladstone Ports Corp. to buy land on Curtis Island for development of the LNG project. The envisioned plant will have liquefaction capacity of up to 16 million tpy in four LNG trains.
East Timor; PNG; Indonesia
Early this year, Woodside is likely to announce a decision on a development mode for Sunrise fields in the Timor Sea. Woodside is operator (33%) with ConocoPhillips (30%), Shell (27%), and Osaka Gas (10%).
Options under active consideration for developing Sunrise fields include a pipeline to a proposed second train at Conoco's Wickham Point LNG at Darwin or a floating LNG plant. Once a concept has been settled on, Woodside wants to move to an FID next year and first production in 2016.
Opposition from the East Timor government, however, could still snarl Sunrise. It wants a land-based LNG plant on its territory and has threatened to withhold approvals if that option is not pursued. Sunrise field lies in the Timor Sea's joint petroleum development area, where Australia and East Timor split royalties.
In December last year, after much anticipation, project partners led by ExxonMobil unit Esso Highlands Ltd., announced the $15 billion LNG project set for Port Moresby, Papua New Guinea, would move ahead.
The decision is conditioned on successful negotiation of sales and purchase agreements with LNG buyers and completion of financing, both of which are expected to be concluded early this year.
ExxonMobil has finalized a 20-year deal with Japan's largest power utility, Tokyo Electric Power for 1.8 million tpy. An early deal was signed between ExxonMobil and China's state-owned Sinopec for 2 million tpy of LNG from the project.
The PNG LNG project includes gas production and processing, onshore and offshore pipelines, and planned liquefaction of 6.6 million tpy capacity.
Participating interests include Esso Highlands as operator (33.2%), Oil Search Ltd. (29%), Independent Public Business Corp. (PNG government, 16.6%), Santos (13.5%), Nippon Oil (4.7%), Mineral Resources Development Co. (PNG landowners, 2.8%), and Petromin PNG Holdings Ltd. (0.2%).
PNG LNG is to start up in late 2013 or early 2014, supplied from Hides, Angore, Juha, Kutubu, Agogo, Moran, and Gobe fields in PNG's Southern Highlands and western provinces. The gas will move via pipeline to liquefaction on the Gulf of Papua, about 12 miles northwest of Port Moresby.
Within 24 hr of announcing the FID for the project, ExxonMobil and partners awarded engineering, procurement, and construction contracts.
Receiving the EPC contract for the two-train, 3.3-million tpy liquefaction plant were Chiyoda and JGC. Plans encompassed construction of facilities for processing and treating natural gas, liquefaction, storage, and loading.
A joint venture of Houston-based CB&I (65%) and Clough (35%) received another contract, this for gas conditioning at Hides field. CB&I has placed the contract value at more than $1 billion (US).
French company Spiecapag received a contract to build onshore pipelines and infrastructure. Italy's Saipem will build an offshore pipeline and support infrastructure.
Also, project partner and associated-gas field operator Oil Search, let an EPC contract to Aker Solutions to build all facilities to deliver gas to the planned LNG plant.
Within days of ExxonMobil's announcement, a second LNG project for Papua New Guinea advanced.
The Papua New Guinea government approved the second LNG project planned by InterOil of Australia based on gas reserves in its Elk and Antelope fields in PNG's Gulf province (OGJ Online, Dec. 11, 2009).
The agreement with the government established terms for commercializing and monetizing the reserves through an LNG plant to be built near InterOil's 36,000-b/d Napa Napa oil refinery in Port Moresby.
InterOil plans first to build a $7 billion, two-train plant capable of 8 million tpy of LNG to start up in late 2014 or early 2015. The company will then install a liquids stripping plant at the field that could return revenues as early as late 2011 or early 2012.
InterOil said an FID would take place late this year.
Finally, last year, Indonesia sent its first shipment from the two-train, 7.6-million tpy Tangguh LNG plant to South Korea after repeated delays due to technical problems at the plant.
The cargo was to have gone to CNOOC's Fujian terminal, but Indonesia said the terminal was not ready. Chinese officials disputed that, saying the terminal received a cargo in May from Indonesia's Bontang LNG project because of delays in the start-up of Tangguh (OGJ Online, May 29, 2009).
BP Indonesia (37.16%) operates the plant as a contractor to Indonesian oil and gas regulator BPMIGAS. Other partners are MI Berau BV (16.3%), CNOOC Ltd. (13.9%), Nippon Oil Exploration (Berau) Ltd. (12.23%), KG Berau/KG Wiriagar (10%), LNG Japan Corp (7.35%) and Talisman (3.06%; OGJ Online. July 15, 2009).
Also in Indonesia, press reports last year stated that Japan-based oil and gas company Inpex Corp. will build floating liquefaction for the gas processing project in the Abadi gas field, Masela block, Arafura Sea, about 150 km southwest of Saumlaki, Maluku.
No time line for construction, commissioning, or operation was given.
Terminals: China et al.
Showing both its need for energy and its need to clean up its production of energy, China last year signed two large LNG supply deals with Australia.
PetroChina Co. Ltd. will buy 2.25 million tpy of LNG over 20 years from Chevron's Gorgon project.
In another deal, not involving LNG, China signed a $5.6 billion, 30-year contract with a consortium of energy companies operating off Myanmar. The consortium, led by South Korea's Daewoo International Corp., will supply natural gas to China National United Oil Corp. via pipeline starting in 2013 from Myanmar's A-1 and A-3 offshore blocks.
The consortium includes India's Oil and Natural Gas Corp., Myanmar Oil & Gas Enterprise, India's GAIL Ltd., and Korea Gas Corp.
Land transportation will be jointly managed with CNUOC. The two parties also plan to build oil and gas pipelines through Myanmar and into China's southwestern Yunnan province, Reuters reported.
Natural gas in 2009 accounted for only 3% of China's total energy needs, about 7.3 bcfd but, according to Bernstein Research, London, natural gas use is expected to grow at 10%/year to 18 bcfd by 2020.
In July last year, as stated, CNOOC's Fujian terminal received its first cargo from Indonesia's BP PLC-led Tangguh LNG project. Under a 25-year contract, CNOOC expected to see 14 more shipments of LNG from Tangguh in 2009 for a total supply of 2.6 million tonnes.
Last month, Qatargas delivered its first LNG cargo to Fujian aboard a conventional 140,000-cu m vessel. Chinese media reported that CNOOC plans to double receiving capacity at Fujian to 5.2 million tonnes by 2011.
In October last year, CNOOC's Shanghai LNG terminal received its first LNG cargo of 45,000 cu m aboard the 88,000-cu m Arctic Spirit LNG carrier from Bintulu, Malaysia. CNOOC owns 45% of the 3-million tpy terminal with Shenergy Group (55%), the Shanghai government's power investment group.
In 2008, CNOOC signed a 25-year agreement to buy 2 million tpy from Qatargas Operating Co. Ltd. with supplies to start in late 2009 from one of two 7.8-million tpy trains in Qatargas 2. The terminal also has another 25-year supply contract with Malaysia for 3.03 million tpy.
Capacity at Shanghai is to be expanded to 6 million tpy at some unannounced future date.
Also in October, CNOOC began construction on its fourth regasification terminal, at Ningbo in Zhejiang Province.
Terminal capacity will be 3 million tpy upon start-up in 2012, doubling in a second phase. First-phase cost has been estimated at slightly more than $1 billion.
The project includes a berth for docking 80,000-266,000 cu m tankers and three, 160,000-cu m storage tanks. CNOOC is teamed with two local companies: Zhejiang Energy Group and Ningbo Power Development.
As early as 2013, PetroChina Co. plans to bring on line a 2.5-tpy terminal in Shenzhen city, southern China, with supplies contracted from ExxonMobil's interest in Gorgon LNG. A Chinese official was quoted last year as saying the terminal will serve as a back-up source for the second West-East gas pipeline that will start moving gas to Guangdong Province in 2011.
This year, PetroChina expects to complete its Dalian LNG terminal in the Xingang district of China's northeastern Liaoning province and begin commercial operations in April 2011. The first phase of Dalian will have capacity to import 3 million tpy; a second phase will double that capacity.
The 50-year joint venture is called China Dalian LNG and is owned by PetroChina (75%), Dalian Port (20%), and Dalian Construction Investment, a local government investment arm (5%). The terminal would primarily be supplied with LNG from Australia and Qatar.
Another PetroChina terminal, the Rudong terminal at China's Yankou port, will be completed in July next year. It will have three storage tanks and import capacity of 3.5 million tpy. The terminal will be able to accommodate Q-Max LNG carriers.
Initial supplies may come from spot cargoes but eventually LNG will flow from Australia's Gorgon development in 2014 and Qatar. PetroChina has a 20-year agreement with ExxonMobil for 2.25 million tpy.
In April 2009, PetroChina signed a long-term contract for 3 million tpy from Qatargas 4, which is scheduled to come on line late this year or 2011.
PetroChina is majority owner of the Rudong project with 55%. Pacific Oil and Gas holds a 35% stake, while the remaining 10% is held by Jiangsu Guoxin Investment, the investment arm of the local government.
A planned second-phase expansion would increase the terminal's capacity to 6.5 million tpy.
South Korea started up two expansions in 2009, raising capacity at Inchon to 32.8 million tpy and at Tong Yeong to 15 million tpy. The expansions bring South Korea's LNG import capacity to more than 80 million tpy.
Start-up at India's third LNG terminal, at Dabhol in Maharashtra on India's western coast, was delayed in late 2009 to early this year. The announcement cited difficulties in dredging silt at the Ratnagiri port.
The terminal was to be commissioned by December, with start-up before yearend. The terminal will, however, become fully operational only after completion of the breakwater facilities in 2011. Ratnagiri Gas and Power Pvt. Ltd. had planned to commission the 5-million tpy terminal in March 2009.
An expansion at India's first LNG terminal, at Dahej did start up in 2009, bringing its import capacity to 11.65 million tpy. Petronet operates both terminals and plans a third at Kochi to start up in 2012.
State-owned GSPC plans floating LNG regasification at Mundra, targeting commissioning around 2014. The company has been procuring natural gas from Petronet LNG and Shell's Hazira terminals.
Earlier this year, India's Swan Energy, Mumbai, announced plans to set up another floating storage and regasification to import LNG at the port of Pipavav on the west coast of Gujarat state. Planned capacity is 6.5 million tpy. Press speculation has been that it would reach start-up by 2014, earlier than GSPC's Mundra FRSU vessel.
Swan Energy's terminal is to connect to the Gujarat state gas grid, operated by Gujarat State Petronet Ltd., the gas transmission arm of GSPC, near Vallabhipur, according to Platts LNG Daily.
Japan's Mitsui and the UK's BG earlier this year expressed interest in taking stakes in the Mundra terminal. GSPC will own 50% of the project, sell 25% to a outside investor to secure supplies, and reserve 25% for India's Adani Group, which owns the Mundra port.
Press reports also said state-owned Indian Oil Corp. had submitted a proposal for a stake in Mundra.
Front end engineering and design were to be completed by the end of March. The terminal would have three storage tanks in its first stage. GSPC plans to increase capacity to 20 million tpy.
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