The Global Liquefied Natural Gas Market: Status and Outlook
World LNG Market Structure
The structure of the international LNG market influences current and future LNG trade. Key issues include differences in history and pricing mechanisms between the Atlantic and Pacific Basins, recent market changes that increase flexibility in LNG trade, the declining trend of LNG costs throughout the value chain, and the addition of new participants to the market.
LNG trade evolved differently in the Atlantic and Pacific basins, and this continues to affect import volume, pricing systems, and contract terms. Importing countries in the Pacific Basin are almost totally dependent on LNG while countries in the Atlantic Basin use domestic supplies and pipeline imports as well as LNG to meet natural gas demand.
Recent changes in the LNG market have trended towards increased flexibility. Contracts have loosened terms on both price and volume, and can be negotiated for shorter periods of time. Additionally, flexibility in LNG shipping has led to an increase in short-term contacts.
Costs of liquefaction, shipping, and regasification have declined over time, lowering costs to producers. Since the LNG market is primarily driven by long-term contracts with pricing mechanisms pegged to petroleum products, however, lower operating costs do not necessarily translate into lower LNG prices, at least in the short term.
Buyers and sellers have been taking on new roles. Buyers have been investing in the upstream, including liquefaction plants (e.g., Tokyo Gas and the Tokyo Electric Power Company have both invested in the Darwin liquefaction plant in Australia). Traditional sellers, such as BP and Shell, have leased capacity at terminals and are extending their role into trading. New buyers have been emerging, including independent power producers in Puerto Rico and the Dominican Republic.
Atlantic and Pacific Basins Differ
In the 1980s and early 1990s, indigenous natural gas supplies were abundant for most countries in the Atlantic Basin, and pipeline gas readily available. It was difficult for LNG to compete and, as a result, LNG imports into the Atlantic basin grew very slowly.
LNG still makes up a small portion of the natural gas market in the United States and Europe, and competes with domestic supplies and pipeline imports.
In contrast, the LNG importers in the Pacific Basin – Japan, South Korea, and Taiwan – have little or no domestic gas production and no pipeline sources for natural gas imports.
Because current LNG importers in the Pacific Basin did not have access to domestic or piped imported gas, LNG imports into the region increased rapidly in the 1980s and early 1990s as these countries sought alternatives to oil. Security of supply was a more important consideration in the Pacific Basin than price.
LNG Pricing Around the World
LNG prices are usually expressed in U.S. dollars per million Btu (MMBtu). Prices can be calculated on a free on board (f.o.b.) or delivered ex-ship (d.e.s.) basis. Today most new contracts are f.o.b., since buyers see this as giving them more control over the landed price and allowing them to trade surplus LNG cargos.
Gas “hubs” involving both LNG and pipeline gas are emerging in the United States, Belgium, and the United Kingdom, presenting opportunities for price arbitrage and eventual convergence of price.
LNG prices have historically been higher in the Pacific than in the Atlantic Basin, averaging about US/MMBtu in the former and US/MMBtu in the latter over the past 10 years.
The rapid growth in Middle East LNG supply may contribute to a convergence of the Atlantic and Pacific prices. So far, the quantity of LNG flowing from the Middle East into the Atlantic Basin has been relatively small, but several projects in the Middle East are aiming to supply European and North American markets. In addition, if LNG import terminals are built on the North American West Coast, Pacific Basin suppliers could gain greater access to the U.S. market.
Atlantic and Pacific Basin LNG Pricing
LNG prices are benchmarked to competing fuels. There have been three distinct and relatively independent markets for LNG, each with its own pricing structure. Price risk is inherent in each pricing structure, although the degree of risk differs among the markets.
In the United States, the competing fuel is pipeline natural gas, and the benchmark price is either a specified market in long-term contracts or the Henry Hub15 price for short-term sales. Importers and exporters involved in U.S. LNG transactions are exposed to a significant level of risk given the high degree of price volatility in U.S. natural gas markets.
In Europe, LNG prices are related to competing fuel prices, such as low-sulfur residual fuel oil. However, LNG is now starting to be linked to natural gas spot and futures market prices.
In Asia, prices are linked to imported crude oil. The pricing formula typically includes a base price indexed to crude oil prices, a constant, and perhaps a mechanism for the review/adjustment of the formula. Asian prices are generally higher than prices elsewhere in the world.
Recent Market Changes: Contracts and Pricing
Although long-term LNG contracts are not likely to disappear, importing companies are seeking increased flexibility and better contract terms. According to the Groupe International des Importatuers de Gaz Liquefie (G.I.I.G.N.L.), contracts covering the sale of nearly 30 million tons per year to Asian countries will come up for renewal over the next decade.
Traditional LNG contracts focused on security of supply for the buyer. Contracts were long-term (often 20–25 years) and rigid. Take-or-pay clauses shifted the volume risk to the buyer. LNG was generally shipped d.e.s., that is, the LNG was transported in designated tankers. Contracts also contained “destination clauses” that prevented buyers from reselling the cargos to third parties.
Changes to this situation have been underway since the mid-1990s. LNG suppliers offered more favorable terms, including substantially lower prices, to new importers in India and China, which led traditional LNG buyers to seek lower prices when renegotiating their contracts. Some examples:
— Owners of Australia’s Northwest Shelf project agreed to sell LNG to China for a price reported to be around per million Btu when crude oil prices are per barrel (with the actual LNG price varying with the price of crude oil). Existing contracts with Japanese buyers are reported to be about 20 percent higher than the Chinese contract.16
— When Japanese utilities renewed an expiring 20-year, 360-Bcf-per-year (7.4-million-tpy) contract for Malaysian LNG, they reportedly obtained a 5-percent price reduction, a two-tier contract arrangement whereby 58 Bcf (1.2 million tons) per year is sold for 4 years and the rest for 15 years, and an agreement that about one-fourth of the volumes will be sold f.o.b., which will increase shipping flexibility and reduce freight costs for the buyers. The contract also covers short-term purchases17
In the U.S. market, LNG prices are linked to Henry Hub prices, which have been steadily rising. Prices for natural gas in the United States are expected to remain in the to per million Btu range, which would reduce the LNG price differential between the Pacific and Atlantic markets. Meanwhile, the European Union is insisting that LNG sellers remove destination clauses from their contracts.
The changing market is boosting short-term LNG sales, which accounted for a record-high 8 percent of traded LNG in 2002. The short-term LNG market was virtually nonexistent until a few years ago, and few LNG facilities were built until sales contracts were signed for the entire capacity. Recently, some projects have gone forward with capacity unclaimed. Spare capacity and more flexible contracts should lead to increased short-term sales.
Recent Market Changes: Growth of the Short-Term Market
One very significant result of this changing environment has been the emergence of a short-term LNG market. All cargos not traded under long-term18 agreements are here described as short-term sales. This includes cargos traded under 1-year contracts as well as individual cargos of LNG that are bought and sold.
Several factors continue to drive the short-term market:
— Uncommitted production capacity, as some new plants are being built (e.g., Malaysia Tiga) without committing the full production volumes.
— Market demand for more LNG, especially in Spain and the United States, where receiving terminals have excess capacity, and Korea, which needs greater volumes in winter.
— The availability of ships not committed to projects.
— Greater contract flexibility.
The short-term market has grown from virtually zero before 1990, to 1 percent of the LNG market in 1992, and to 8 percent (400 Bcf or 8.4 million tons) in 2002. In 2002, 32 companies traded 218 shipments of LNG either as short-term transactions or as swaps. The leading short-term sellers in 2002 were Algeria, Oman, Qatar, Trinidad and Tobago, and the UAE. Short-term imports were dominated by the United States and Spain, followed by South Korea and France.
Short-term trading is projected to continue to grow, especially in the Atlantic Basin, and could reach 15 to 20 percent of LNG imports over the next decade. However, whether LNG will ever become a true commodity is still a matter of debate.
What is LNG?
Liquefied natural gas, or LNG, is natural gas in its liquid form. When natural gas is cooled to minus 259 degrees Fahrenheit (-161 degrees Celsius), it becomes a clear, colorless, odorless liquid. LNG is neither corrosive nor toxic. Natural gas is primarily methane, with low concentrations of other hydrocarbons, water, carbon dioxide, nitrogen, oxygen and some sulfur compounds. During the process known as liquefaction, natural gas is cooled below its boiling point, removing most of these compounds. The remaining natural gas is primarily methane with only small amounts of other hydrocarbons. LNG weighs less than half the weight of water so it will float if spilled on water.
where
A majority of the world’s LNG supply comes from countries with large natural gas reserves. These countries include Algeria, Australia, Brunei, Indonesia, Libya, Malaysia, Nigeria, Oman, Qatar, and Trinidad and Tobago
Credit:ivythesis.typepad.com
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