China, US West Coast markets to push Pacific Rim LNG growth
Steve Robertson
Adrian John
Adrian John, Steve Robertson, Douglas-Westwood Ltd., Canterbury
Pacific Rim LNG markets will see strong growth 2007-11 in expenditures on new LNG plants and terminals.
The LNG business has grown substantially in recent years with completion of some major high-profile LNG projects. While demand remains strong in traditional Asian markets, much attention is now being directed to opportunities arising from the potentially vast Atlantic Basin LNG market.
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Left to right: Guangdong LNG terminal, China (photo from Guangdong Dapeng LNG Co. Ltd.); Northwest Swan (photo from Woodside); Karratha gas plant, Western Australia (photo from Woodside)
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Meanwhile, the limits of domestic gas production in North America and Western Europe are becoming clear and gas import demand is rising. Increasingly, LNG is a choice in satisfying growing gas demand in these regions. Following the success of the plants recently established in Equatorial Guinea, Nigeria, and Trinidad and Tobago, a wave of new projects has emerged that demonstrate the potential for extensive market growth over the next 5 years.
Despite strong demand fundamentals, however, supply constraints are now affecting the business: EPC costs are rising; final investment decisions (FIDs) are being delayed or postponed as a result; and while major growth is still in prospect, the timing of operators’ planned expenditures is likely to move significantly “to the right.”
This article will focus on the general characteristics and development of the LNG industry in the Pacific Rim and present Douglas-Westwood’s historical (2002-06) and forecast (2007-11) views of capital expenditures (capex) associated with LNG projects in the region. Particular attention will be given to development of the LNG industry in China and the US West Coast and Canada. For the present purposes, however, Southern Asian nations, such as India and Pakistan, are not considered part of the Pacific Rim.
Pacific Rim consumption, production
The historical trend of natural gas production and consumption in the Pacific Rim (excluding the US West Coast and Canada) shows that since 1980 the gap between consumption and production has been growing incrementally (Fig. 1). In 2006, that gap in the Pacific Rim was 7.3 bcfd, representing 17.3% of total consumption.1
LNG already plays a central role in Pacific Rim nations’ meeting their natural gas consumption requirements. Japan, South Korea, and Taiwan, for example, almost entirely depend on LNG imports to fulfill domestic demand for natural gas. In 2006, 67.9% of all LNG imports in the Pacific Rim were from other Pacific Rim nations.2 With exception of small volumes of LNG being exported from the Pacific Rim to India, all LNG produced in the Pacific Rim is consumed there.
These natural gas supply and demand dynamics in the Pacific Rim are driving the growth and development of LNG liquefaction capacity there.
Development of liquefaction
The last 5 years have seen a 23.6% increase in Pacific Rim LNG liquefaction capacity, to 75.9 million tonnes/year (tpy) in 2006 from 61.4 million tpy in 2002.3 Douglas-Westwood expects much larger growth over the forecast period 2007-11, with liquefaction capacity expected to reach 102.2 million tpy by 2011, a growth of 34.7% relative to 2006 capacity (Fig. 2).
Several factors are driving this growth on both demand and supply sides, including:
- Continuing growth in world gas consumption. The US Energy Information Administration has forecast world gas consumption growth at 2.4%/year out to 2030, compared to 1.4%/year for oil and 2.5%/year for coal.4
Gas will account for 26% of global energy use by 2030. In 2006, gas consumption in the Pacific Rim grew by more than 7.6% and has grown by 32% since 2002.1 - Strong import demand. Many of the major gas-consuming nations in the Pacific Rim have either very little gas production of their own (Japan, South Korea, for example) or have developed and drawn down their own reserves to the point where they are now past peak production and will have to rely increasingly on imported gas (US).
- Monetization of stranded gas reserves. Large natural gas reserves are located a long distance from end-user markets or have no nearby access to takeaway pipelines. Without access to markets, produced gas is either flared or reinjected. LNG offers an access mechanism, a method of monetizing these gas reserves, and a way to reduce environmental harm from gas flaring.
- Technological advances. Advances in liquefaction technology had until recently led to a fall in the level of capex required to construct new plants. Nonetheless, development of larger liquefaction trains will create larger economies of scale, thus compensating somewhat for rising capex requirements and sustaining the economic viability of LNG as a solution for bringing gas to market.
Capex trends, forecasts
Douglas-Westwood forecasts that more than $62.1 billion of capex will be required to complete new LNG plants, vessels, and terminals in the Pacific Rim over 2007-11 (Fig. 3). The capex is accounted for in the year of start-up of the plant or terminal or delivery of the vessel.
In practice, however, contractual payments relating to the projects identified are often made in installments and will most likely be spread over years. For the sake of clarity and transparency, we do not attempt to try to reflect this situation in our forecasts. Instead, we focus on attempting to indicate the value of the new LNG facilities that come into use each year.
The overall trend is of strong market growth, with Pacific Rim capex on LNG developments over 2007-11 to total more than $62.1 billion-more than three times the $19.6 billion spent over the previous 5-year period.
LNG plants
Over 2002-06, Douglas-Westwood data indicate that 14.5 million tpy of liquefaction capacity was brought on stream by new LNG export plants and that the capex for constructing these plants (excluding upstream costs but including all site costs: plant, storage, marine facilities, etc.) totaled some $4.3 billion.
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As of August 2007, the first LNG regasification terminal to operate on the western coasts of North America was more than 80% complete. Energía Costa Azul, under development in Baja California, Mexico, by Sempra Energy unit Sempra LNG, will open later this year or in first-quarter 2008. The terminal will initially be able to send out as much as 1 bcfd of Pacific Rim-produced natural gas to Mexican and US markets. Photograph from Sempra Energy.
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For 2007-11, new liquefaction plants coming on stream in the Pacific Rim will be a part of a massive increase in global LNG liquefaction capacity, requiring capex of more than $11.2 billion-almost 27% of global liquefaction capex for the period.
Key developments will include further development of the North West Shelf (Train 5) and the greenfield Pluto LNG project in Australia, the Tangguh LNG project in Indonesia, Sakhalin Trains 1 and 2 in Russia and Peru LNG in Peru.
Longer term, Australia is set to play a central role in liquefaction capacity additions in the Pacific Rim with more than 10 prospective developments announced. Of these prospects, seven had announced start-up dates during the 2007-11 forecast period. Projects such as Greater Gorgon, Browse LNG, and Pilbara LNG, however, have all experienced delays in project development, leaving NWS Train 5 and Pluto LNG as the only Australian liquefaction projects likely to come on stream during the forecast period.
Importantly, recent escalation of EPC costs has led to many proposed liquefaction projects delaying their FIDs. Until around 2005, technological advances, increased economies of scale, and increased competition between licensors, contractors, and suppliers within the LNG liquefaction industry had been driving the cost of construction down, to less than $200/tonne/year of capacity in several cases.
Escalating costs of labor and raw materials and the tight contractor market, however, have spurred large increases in the cost of new EPC contracts. By 2009 many projects coming on stream will have EPC costs of or greater than $300/tonne/year of capacity. The recent EPC contract award for Sonatrach’s Skikda replacement trains, likely to come on stream in early 2012, exceeds $650/tonne.
In the Pacific Rim, this trend of increasing costs is exemplified by the increase to $1.8 billion from $1.4 billion for the 7.6-million-tpy Tangguh liquefaction project in Indonesia after an 18-month delay in FID. Larger EPC cost increases are likely for projects still awaiting their FIDs. The recent FID for Pluto LNG was the first to be made for a liquefaction plant in 2007.
LNG terminals
Douglas-Westwood also forecasts a large growth in spending for import terminals.
During 2002-06, more than $1.9 billion was spent on new LNG import and regasification terminals. Pacific Rim additions to import capacity over the forecast period will result in construction of around 29 new terminals at a total cost of almost $9.4 billion.
Despite strong energy demand in the US West Coast, none of the 29 terminals forecast to be constructed in the Pacific Rim will be there.
LNG carriers
Shipyards in the Pacific Rim have dominated activity in the newbuild LNG carrier market. In fact, the region has constructed nearly all the LNG carriers that entered service 2002-06. Over the next 5 years, we anticipate that more than 195 new carriers will be built in Pacific Rim nations. Capex associated with these new vessels will exceed $41.5 billion.
Douglas-Westwood data indicate the average price of an LNG vessel delivered over the previous 5 years fell to as low as $162 million in 2002. This decline in price over this period was largely due to intense competition among shipyards in the Far East, Korean ones in particular.
Although the market will remain competitive, however-with the entrance of Chinese yards into the market being a point of particular interest-demand in the shipping sector is at an all-time high with lead times for new orders stretching out 4-5 years. Prices for newbuilds now exceed $200 million/vessel again, with the trend towards increasingly larger vessels to continue.
The main types of vessel design that have evolved are distinguished by type of containment system employed and are the Kvaerner-Moss Spherical System, the Gaz Transport Technigaz (GTT) membrane type, and IHI’s Structural Prismatic design.
The membrane system is the most widely adopted, being used in more than half of LNG vessels in service as of 2007. It will be used in around 85% of vessels scheduled for delivery 2007-10. The Moss system is used in 45% of LNG vessels in service as of 2006 and will be used in more than 10% of vessels scheduled for delivery during 2007-10.
It is worth noting that in April 2007 Kogas signed a memorandum of understanding with the Korea Shipbuilder’s Association to develop a membrane-type cargo containment system (called KC-1) to rival the GTT system. The successful development KC-1 would improve the competitiveness of the Korean shipyards in light of China’s entrance into the LNG vessel construction market.
(Editor’s note: See LNG Observer, July-September 2007, p. 12, for a fuller discussion of China’s entry into the LNG carrier market. In addition, a complete listing of LNG carriers under construction, owners, commissioning dates, and trades, among other information can be found on p. 29 of this issue.)
Development in China
Although coal is China’s main energy source, the country’s gas consumption 2004-05 grew by 21% and a further 21.6% 2005-06. The Chinese government wants to increase the gas share of total energy production to 8% by 2010-more than doubling present volumes-to reduce reliance on coal, which is a much dirtier energy source than LNG.
A key reason for this policy is China’s preparations for the 2008 Olympic games in Beijing. In years leading up to the games, Beijing is spending nearly $7 billion on environmental projects.5
This includes $800 million on preventing coal-burning pollution, with additional monies going to construction of natural gas pipelines and storage tanks, improving electricity distribution, and re-engineering the power supply structure.
Increased levels of domestic natural gas production and imports-the latter via pipeline or LNG-will meet the increase in gas demand in China. Most of the imported LNG will be used in southeast China, where six gas-fired power stations are being constructed in the Guangdong province.
Despite ambitious plans that originally proposed to construct 10 LNG import terminals (new and expansion projects) by 2008, only Guangdong Dapeng LNG Phases I and II have been completed thus far. China’s second LNG import terminal at Putian, in the Fujian province, will be ready to receive its first cargo from Indonesia by yearend 2008.
Several reasons lie behind this failure of many projects to materialize. Chief among them has been China’s insistence upon signing long-term LNG supply contracts at prices far below market value. Consequently, China has only signed two long-term contracts since a deal with North West Shelf Venture in 2002, owing to its insistence on a similarly low price (of $3.15/btu).
Recently, however, there have been indications that China may be moving away from this policy. In May 2007 the Guangdong Dapeng terminal received its first spot cargo from Oman (OGJ Online, May 10, 2007). The significance of this transaction lies in the willingness of local companies in China to pay market value for LNG, $8.30/MMbtu.
As a single cargo it did very little to overcome shortfalls in gas supply that many large cities in China were experiencing at the time, but this could be a sign that market forces are beginning to assert themselves in LNG and that China is going to be willing to pay a higher price for long-term contracts in future. Guangdong Dapeng has subsequently received more spot cargoes and has the spare capacity to receive one spot cargo per month.
Company officials recently suggested that Guangdong Dapeng might import close to 2.6 million tpy in 2007-more than trebling the 0.7 million tpy imported in 2006. In light of spot-cargo purchases, the Chinese government changed its LNG import permit system in order to reduce competition between local importers for cargoes and to avoid driving spot prices higher than they currently are.
These recent developments have created renewed optimism surrounding development of LNG as an industry in China. Douglas-Westwood estimates that some $4.4 billion will be spent on developing import terminals during 2007-11. Additionally (and as noted previously), China has entered the LNG vessel construction market through the Hudong-Zhonghua Shipbuilding Co., which has already secured contracts of more than $1 billion to build five vessels for China Shipping LNG and is likely to receive an order for an additional vessel by the end of this year.
LNG in US West Coast, Canada
Since 1991, EIA data show that there have only been 3 years when North America has produced more gas than it has consumed. The US currently depends on Canada for the vast majority of its gas imports, but since Canada’s main producing areas are now mature and Canadian gas demand is increasing, both the US and Canada are now looking to LNG imports as an important source of gas.
A decade ago, an LNG export plant was proposed to export Canadian gas to markets in Asia. With gas supply in North America struggling to keep up with demand, however, all proposals are now for LNG import terminals.
Excluding Alaska, all US West Coast states import most if not all the gas they consume. California has the most in-state gas resources available but consumes almost 10 times as much natural gas each year as either Oregon or Washington. California produces about 15% of the 6.1 bcfd (2005 value) of natural gas that it consumes and imports the rest from Canada (about 24%), the Rocky Mountains (about 25%), and Southwest (about 36%).
This situation highlights the potential for LNG to be a substitute or complementary source of natural gas for West Coast states with easy access to Pacific Rim liquefaction capacity.
LNG import terminals have been proposed in all three US West Coast states, but thus far none has received regulatory approval, owing as much to public opposition as to failure to meet regulatory requirements. The LNG industry is renowned for its diligent standards and has an excellent safety record, albeit not entirely without incident.
Public perception about the risks of LNG, however, often appears to be misconceived. Consequently local opposition to new facilities is common and perhaps now more vigorous given continuing worries over terrorism. This seems to be a particular problem in California.
In recent years, three prospects for Californian LNG import terminals have been abandoned due to local opposition: Humbolt Bay (Calpine Corp.), Mare Island (Shell Corp. and Bechtel); and Cabrillo Port LNG (BHP Billiton). In the case of Mare Island, shipping scheduling was also a concern. The LNG tankers would have required escorting by the US Coast Guard under several major bridges including the Golden Gate Bridge and through San Francisco Bay.
Cabrillo Port LNG was the latest victim of strong local opposition to LNG projects in California. In May 2007, California Governor Arnold Schwarzenegger turned down BHP’s applications for a floating storage and regasification unit (FSRU) some 35 km off Ventura County (OGJ Online, May 29, 2007; LNGO, July-September 2007, p. 23). The project reflects the difficulties involved in obtaining regulatory approvals and overcoming local opposition faced by all LNG terminal proposals located in California-offshore as well as onshore.
Although no import terminals are likely to be constructed on the US West Coast 2007-11, the Kitimat LNG (Galveston Energy) project on Canada’s West Coast should be completed by yearend 2010. Also, commercial operations at the Sempra Energy’s Energia Costa Azul LNG terminal in Baja California, on the Pacific Coast of Mexico, will begin by yearend 2008.
Baja California has seen a lot of interest for proposed LNG import terminals mainly due to the proximity of US markets and the region’s isolation from the rest of Mexico’s energy supply. Should proposed import terminals on the West Coast fail to gain approval, Kitimat and Energía Costa Azul may provide an alternate source for LNG supply if they are able to source sufficient volumes of LNG beyond the requirements of local markets.
References
1. BP Statistical Review of World Energy 2007, www.bp.com.
2. 2006 Natural Gas Year in Review, Cedigaz (www.cedigaz.org), Apr. 26, 2007.
3. The World LNG & GTL Report 2005-2009, Douglas-Westwood Ltd., Canterbury, UK; www.dw-1.com.
4. Annual International Energy Outlook 2007, US Energy Information Administration, http://www.eia.doe.gov/oiaf/ieo/index.html.
5. “Country Update: Practicality is the New Watchword as Beijing Olympics Projects Move Forward,” US Department of Commerce, November 2004; http://www.export.gov/china/country_information/countryupdateolympics.asp.
The authors
Adrian John is an analyst with Douglas-Westwood Ltd. and lead author of DWL’s World LNG & GTL Report 2007. He has conducted market analysis for a variety of DWL’s oil and gas clients as part of commissioned research, commercial due-diligence, and published market studies. Adrian’s background is in engineering and construction; he holds an honors degree in engineering from Cambridge University. He is a member of the Energy Institute and the Society for Underwater Technology.
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Steve Robertson is assistant director and manager of oil and gas at DWL. He has previously written a number of The World series of market reports including The World LNG & GTL Report and is editor of the latest edition. Within the LNG sector, he has led DWL’s work for a variety of commissioned engagements ranging from small technology players to major oil companies. In the wider oil and gas sector, his analysis has included all facets of LNG, oil and gas field development, subsea production, floating production, and other areas. He is a member of the Energy Institute and the Society for Underwater Technology.
Volume 4 Issue 4
Oct 01, 2007
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