Liquefied Natural Gas: Global Challenges |
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U.S. imports of LNG in 2007 were more than triple the 2000 total, and they are expected to grow in the long term as North America’s conventional natural gas production declines. With U.S. dependence on LNG imports increasing, competitive forces in the international markets for natural gas in general and LNG in particular will play a larger role in shaping the U.S. market for LNG. Key factors currently shaping the future of the global LNG market include the evolution of project economics, worldwide demand for natural gas, government policies that affect the development and use of natural resources in countries with LNG facilities, and changes in seasonal patterns of LNG trade. Changing Project Economics From the mid-1990s through 2002, a major factor underlying the growth of global LNG markets was declining costs throughout the LNG supply chain. Since 2003, however, costs have escalated, especially in the area of liquefaction. The result has been a delay in commitments to the construction of new liquefaction capacity, which in turn creates uncertainty about the future availability of LNG supplies. The cost of liquefaction capacity can vary widely, depending on location, quality of natural gas supplies, and plant design (including whether the planned capacity is an expansion of an existing plant or a new greenfield plant). In general, however, the available data indicate that construction costs for new liquefaction capacity have more than tripled since the early 2000s [66]. Some of the reasons for the increase are higher raw material costs for commodities such as nickel and steel, a shortage of experienced workers and contractors, full construction order books, and longer delivery times for key pieces of equipment. Although economies of scale can reduce unit costs, those reductions have not been sufficient to offset increases in other costs. For regasification facilities and receiving terminals, the available data suggest that the construction costs for new projects have increased by more than 50 percent over the past 5 years [67]. In addition, construction costs for LNG tankers have increased by 40 to 50 percent since 2003 [68], primarily because of rising costs for materials and equipment. Wood Mackenzie reports that ship prices remain on “an upward trend driven by a surge in new orders of large tankers, bulk carriers, and containerships, which compete with LNG carriers for berth space” [69]. Worldwide Demand for Natural Gas Contributing to the uncertainty about LNG supply availability is a worldwide increase in natural gas consumption and its effect on prices. In EIA’s International Energy Outlook 2007, annual worldwide natural gas consumption in 2030 varies by 35 trillion cubic feet between the high and low macroeconomic growth cases, or around plus or minus 11 percent when compared with the reference case [70]. For some countries, such as Japan and South Korea, relatively slow growth is expected for natural gas consumption, but because they are almost entirely dependent on LNG imports to meet natural gas demand, any increase is likely to affect LNG markets. For India and China, on the other hand, natural gas consumption has increased much more rapidly. Both countries have been actively searching for new domestic natural gas resources, and both have been pursuing pipeline projects that could bring more imported supplies to domestic consumers. China has been negotiating with Russia to obtain supplies, India has been negotiating with Iran, and both countries have been competing for pipeline supplies from Central Asia and Myanmar. The success or failure of domestic natural gas exploration efforts in India and China and the possible construction of new pipelines is likely to affect their demand for LNG imports and, ultimately, how much LNG will be available to the United States. Currently, the Organization for Economic Cooperation and Development (OECD) countries account for the majority of LNG imports. In 2006, 12 OECD countries [71] were net importers of LNG, and they accounted for just over 90 percent of all LNG imports. Five non-OECD countries [72] accounted for the remaining 10 percent. Among the world’s net exporters of LNG, however, 11 of 12 were non-OECD countries [73], and Australia was the only OECD country with net LNG exports in 2006. At the same time, natural gas consumption has been increasing at a faster rate in the non-OECD countries than in the OECD countries as a whole. Resource Development Policies In addition to the uncertainty associated with natural gas demand growth and project costs, many countries that are net LNG exporters have government policies or agreements that promote domestic natural gas consumption. Any expansion (or rollback) of such policies could affect their future domestic consumption of natural gas and the supplies available for export. Indonesia, Egypt, and Australia have or are considering domestic natural gas supply requirements for projects under development. Indonesia’s 2001 Oil and Gas Law imposes a 25-percent domestic market obligation on new contracts for natural gas production sharing, although implementation of the law is still uncertain [74]. In 2005, Egypt reduced the portion of natural gas reserves available for export from one-third to one-quarter. Unlike Egypt and Indonesia, Australia does not have any national regulations that require natural gas resources to be reserved for domestic markets; however, the Western Australia state government has negotiated an agreement with Northwest Shelf LNG developers to reserve 4.7 trillion cubic feet of Northwest shelf natural gas for the domestic market and, more recently, has negotiated a similar agreement with Gorgon LNG developers to set aside 15 percent of reserves for the domestic market. The Western Australia government has also been considering domestic reservation requirements for all future natural gas projects that would liquefy production for export [75]. Such a requirement could discourage development of marginal export projects, leaving some resources undeveloped. Domestic reservation requirements promote natural gas consumption by keeping domestic natural gas prices low. In addition, many countries that are net LNG exporters foster domestic consumption further by directly regulating domestic natural gas prices and keeping them below LNG net-back equivalent prices. Both China and India, two of the world’s newest LNG importers, also regulate the prices that electricity generators pay for natural gas. Without belowmarket prices, generators probably would be unable to use natural gas to generate power profitably for sale to domestic electricity markets, where prices also are regulated. Seasonal Usage Patterns The natural gas market in North America, where indigenous production meets much of the demand for natural gas, is a large, liquid market with ample storage capacity. Thus, even during periods of relatively low demand, it can still absorb imports. There is, however, a seasonal element specific to the U.S. market (Figure 25). More LNG is imported by the United States during the summer months, for reasons related as much to conditions in other LNG-importing countries as to conditions in the United States. The conditions that make North America an attractive year-round market are not likely to change, but changing conditions in the rest of the world could reduce the availability of summer LNG imports to the United States. The natural gas market in OECD Europe is comparable with the North American market in size— about 71 percent as large in 2005. Whereas North America relies almost entirely on storage withdrawals to meet incremental winter demand, OECD Europe employs a variety of sources, with indigenous production, natural gas imports, and storage withdrawals all rising in the winter months to meet increased demand (Figure 26). The United Kingdom, Belgium, and the Netherlands currently have active market-based systems for natural gas. In addition, European Union regulators are trying to introduce regulatory reform into additional markets and bring more liquidity into continental European markets. Although OECD Europe also has less storage capacity than North America, even when the relative size of annual demand in the two markets is taken into account, it has many geologic structures that could be suitable for seasonal natural gas storage. By 2015, OECD Europe could add almost 1 trillion cubic feet of additional working natural gas capacity in seasonal storage facilities [76]. The seasonal LNG supplies available to the North American market could also be affected if new importers of LNG develop in the southern hemisphere, where peak demand for heating occurs during the northern hemisphere’s summer. Argentina became the first South American country to import LNG, offloading its first partial cargo in May 2008. Argentina and its neighbors are anticipating a shortage of natural gas this winter (June-August), and Argentina is planning to import LNG on special ships with onboard regasification capability while the construction of onshore regasification terminals is being discussed. Brazil and Chile also will soon become LNG importers. Brazil has two floating regasification and storage units on order, the first of which could begin operation on the country’s northeast coast during 2008. Chile has at least one regasification terminal in the advanced planning stage, and others are under consideration. The terminal planned for Quinteros, Chile, is expected to enter service in the second quarter of 2009 with a capacity of 2.5 million tons of LNG (116 billion cubic feet of natural gas) per year and a contract with BG Group for supply of 1.7 million tons (79 billion cubic feet) per year [77]. Implications of Uncertainty in LNG Markets Changing expectations about global LNG demand, supply, and prices are reflected in the AEO2008 reference case. Demand for natural gas overall is lower in AEO2008 than in AEO2007 as a result of expectations for slower economic growth and higher energy prices, including natural gas prices. With the additional assumptions of higher LNG costs, stronger competition for global LNG supplies, and growing constraints on LNG production, U.S. LNG imports in 2030 are 1.7 trillion cubic feet lower in AEO2008 than the AEO2007 projection for LNG imports in 2030. There remains, however, considerable uncertainty about the future of the global LNG market, which could lead to higher or lower LNG imports. To quantify the possible effects of that uncertainty, AEO2008 includes high and low LNG supply cases in which U.S. imports of LNG are assumed to be higher and lower, respectively, than in the reference case. The high and low LNG supply cases are not based on explicit assumptions about the causes of increased or decreased availability of LNG imports but only examine their potential impacts on natural gas supply, demand, and prices in the United States. Gross U.S. LNG import levels were specified for the high LNG supply case by increasing LNG imports by 10 percent in 2011 relative to the reference case level, followed by a gradual increase to three times the reference case level in 2030. For the low LNG supply case, U.S. LNG imports are held constant at the reference case level in 2009 through the end of the projection. All other assumptions in the LNG supply cases, such as oil prices and domestic resource levels, are the same as in the reference case. In 2030, LNG imports are specified to be 8.5 trillion cubic feet in the high LNG supply case and 1.0 trillion cubic feet in the low LNG supply case (Figure 27). Varying the amount of LNG imports affects domestic production, consumption, and price levels for natural gas. In general, lower LNG imports result in the use of higher priced domestic production, leading to higher prices and, subsequently, reduced consumption and total supply requirements. In the low LNG supply case, 23 percent of the reduction in LNG imports is made up by a decline in natural gas consumption (primarily in the electricity generation sector, where more than 90 percent of the reduction occurs). The other 77 percent is made up by an increase in supplies from other sources, primarily domestic unconventional natural gas production (26 percent) but also other domestic lower 48 production (20 percent), Alaska production (20 percent), and pipeline imports (11 percent) (Figure 28). The lower supply requirement helps moderate the price increase relative to the reference case (Figure 29). Wellhead natural gas prices in 2030 are 4.4 percent higher in the low LNG supply case than in the reference case. In the high LNG supply case, the impact on consumption is larger. An increase in natural gas consumption amounts to about 45 percent of the increment in LNG imports relative to the reference case, and the remaining 55 percent offsets declines in domestic natural gas production and pipeline imports. Wellhead prices in 2030 are nearly 17 percent lower in the high LNG supply case than in the reference case.
Contact: Phyllis Martin |
