There are several obvious benefits to using natural gas. First, it is the cleanest burning fossil fuel, with lower emissions and fewer pollutants than either oil or coal. Second, it is becoming more available. Since the early 1970s, global natural gas reserves have steadily increased, at an annual rate of some 5 percent. Similarly, the number of countries with known reserves has increased from around 40 in 1960 to about 85 in 2005.

One reason for the anticipated increase in natural gas demand will come from public concern over environmental issues. Another reason will come from the U.S., the world’s biggest natural gas market, whose demand will continue apace despite declining production in Canada, which has long been America’s biggest supplier.

While natural gas demand is expected to continue, production increases in the near future will likely be driven by additional demand from the power generation sector. There is little overlap in the uses of natural gas and oil in large markets. However, certain moves on the horizon, including electric-powered transportation, will push natural gas use to ever higher levels.

Although potential natural gas supplies abound throughout the world, it is expensive to build facilities and infrastructure to receive the product and distribute it to the market, and their development can easily be hindered by geopolitics. These drawbacks have historically inhibited the full potential of natural gas in world energy markets. Natural gas is transported either by pipeline mainly across landmasses (73 percent of internationally traded gas in 2005), or by LNG oceanic shipping (the remaining 27 percent). The rapid expansion of worldwide LNG infrastructure over the past decade is enabling natural gas to penetrate many more markets through the development of remote gas reserves that were once considered stranded and uneconomic to develop. Ongoing construction, expansion, and newly built LNG receiving terminals in North America will open up that lucrative market to gas imports. European and Asian markets are also hungry for LNG.

Beyond the U.S. and Europe, China and India have emerged from the developing world to become globally significant economies in their own right, requiring massive energy imports to sustain their galloping economic growth. This has left the rest of the world scrambling for the same energy sources, including natural gas. The U.S. is hampered by the myriad of required permit approvals and public opposition to LNG receiving-terminal sites. Nevertheless, major U.S. companies and others are investing heavily in building new LNG liquefaction infrastructure in Qatar, West Africa, and Sakhalin.

Transportation is an essential aspect of the gas business, since gas reserves are often quite distant from the main markets. Gas is far more cumbersome than oil to transport and as noted above, the majority of gas is transported by pipeline. There is a well-developed network in Europe and North America, and a relatively adequate one in the former Soviet Union. However, in its gaseous state, natural gas is quite bulky: over a given time, a high-pressure gas pipeline can transmit only about one-fifth the energy of a similarly sized oil pipeline, even though gas travels much faster. When gas is cooled to minus 160° C it becomes liquid and much more compact, occupying 1/600 of its standard volume. Where long overseas distances are involved, transporting gas in its liquid state becomes economical. But the supply chain consists of expensive and specialized facilities for both upstream and downstream, and dedicated marine vessels.

The LNG industry is set for a large and sustained expansion, as during the past decade, improved technology has reduced costs and improved efficiency along the entire supply chain. This shift in natural gas market dynamics will further commoditize and diversify gas in the global market. New LNG carriers are 1,000 feet long, and require a minimum water depth of 40 feet when fully loaded. The existing global fleet of LNG carriers reached 217 by the end of 2006, with more than 11 million tons of LNG capacity. The order book for new LNG marine carriers to the year 2010 is some 120 firm and 32 proposed, meaning the fleet may exceed 370 vessels by then. The fleet had just 90 vessels in 1995 and 127 vessels in 2000. The current fleet transports more than 140 million metric tons of LNG every year (converted to 7 Tcf), about 23 percent of gas trade internationally and about 6.5 percent of gas consumed worldwide. Table 1 provides the 2006 worldwide distribution and sizes of LNG liquefaction plants.

Table 1: Regional distribution of gas liquefaction
plant locations and capacities

During 2005-06, new liquefaction trains also came on-stream in Oman (train 3: 3.3 mtpa), Nigeria (trains 4 and 5: 4 mtpa each), Qatar (Rasgas trains 4 and 5: 4.6 mtpa each), and Trinidad and Tobago (Atlantic LNG train 4: 5.2 mtpa). Figure 1 identifies the current LNG exporters.

Figure 1: Global LNG exports by country
in 2005. Four countries (Indonesia, Malaysia,
Qatar, and Algeria) accounted for 60
percent of global LNG exports

Future Gas Liquefaction Growth

In the near future, several countries are set to become new LNG exporters (Figure 2). These include Equatorial Guinea (Bioko), Norway (Snohvit), Russia (Sakhalin), and Yemen (Balhaf). In the last few years, plans for new gas liquefaction plants as well as their construction have mushroomed, with some new countries set to become LNG exporters (Angola, Peru, and Brazil) and several current participants expanding or modernizing their facilities (Algeria and Libya).

Figure 2: Areas where gas liquefaction projects
are either under construction, in
planning, or likely to be developed
during the next decade

Demand for LNG Driven by Three Expanding Markets

Consuming countries in North America, Asia, and Europe continue to develop LNG importing infrastructure (Figure 3). They are looking at LNG not just for diversification and cleaner energy production, but because some of the largest consumers (e.g., the United States and China) have growing energy supply deficits – that is, production of domestic energy resources is failing to satisfy growth in energy demand. Therefore, LNG is attractive to a variety of consuming nations.

• Those with indigenous industries that have hit or passed peak output, such as the U.S. and U.K., which have highly developed gas delivery infrastructure but are increasingly net importers.
• Those without significant reserves, such as Japan, South Korea, and many major E.U. economies (Spain, Italy, France, and the Netherlands).
• Developing economies that are energy hungry. This obviously includes China and India, both of which have underdeveloped gas handling and pipeline infrastructures but huge growth potential in the number of end-users.

There are approximately 60 LNG receiving terminals worldwide. Of these, 26 operate in Japan, with one in the planning stage. All but two are along the industrial southeast coast of Honshu. Japan has storage space for some 15 million cubic meters of LNG with capacity close to 90 mtpa; the country used about two-thirds of this in 2005. Asia holds more than three-quarters of current worldwide LNG import storage tank capacity, although investments in Europe and North America are set to change this.

Figure 3 illustrates how LNG trade is concentrated in two main areas, the Pacific Rim and the Atlantic Basin. From the 1970s to the 1990s LNG trade was concentrated in the Pacific, dominated by Japan and South Korea, and natural gas consumption for the two consists almost entirely of LNG. However, the number of exporting countries and the destinations of the LNG exports has expanded and diversified rapidly since 1996.

Figure 3: Japan and the Pacific Rim
continue to dominate LNG consumption,
but the Atlantic Basin (Europe and North
America) is expanding it’s LNG imports rapidly

The Emergence of China as an LNG Importer

China has dominated world energy consumption growth in the last few years. All three of China’s state-controlled oil and gas companies – CNOOC, Sinopec, and CNPC – are now sponsoring LNG import projects. Some 18 different projects to build LNG receiving facilities were announced from 2002 to 2005, although several have been placed on hold since LNG to supply these terminals cannot be secured at prices at or below $4/mmbtu (the maximum gas-trading price within China).

CNOOC is China’s leader in LNG and natural gas, bringing its first LNG terminal on-stream in mid-2006 at Guangdong in Guangzhou province (a joint venture between CNOOC and BP). In May 2006, China’s first shipment of Australian LNG arrived at the Guangdong LNG terminal. The 60,000-ton cargo came from the North West Shelf liquefaction facility at Karratha. The $846-million terminal will import more than 3.7 mtpa of LNG in its first phase. Over 300 kilometers of gas transmission pipeline was also constructed as part of the first phase to take the imported gas to industrial customers. The second phase, planned for completion in 2009, will see the terminal expanded to 5 mtpa and the connecting pipeline network expanded by 240 kilometers. LNG is imported under the sale and purchase agreement at prices less than $3 per mmbtu – from a seller’s perspective, the worst LNG price ever for a major LNG export project.

China’s second terminal (controlled by CNOOC, located in Fujian province, and importing LNG from the BP-operated Tangguh liquefaction plant under construction in West Papua, Indonesia), should be operational by the end of 2007, followed by a third in Shanghai in 2009. There are signs that China is now reconciled to the fact that a repeat of the Guangdong supply purchase price is unlikely. In 2006, CNOOC reportedly secured its third supply contract for the Shanghai terminal with Malaysia (MLNG Tiga) in the range of $5 to $6 per mmbtu.

Evolving LNG Markets of the Pacific Rim

Figure 4 shows LNG infrastructure, liquefaction, and regasification around the Pacific Rim. The existing liquefaction plants are geared towards supplying the East Asian markets (Japan, South Korea, Taiwan, and from 2006, China). New, initially small markets are planned to emerge in the Philippines and perhaps in Thailand. Also, Singapore is considering establishing itself as an LNG storage and distribution hub.

When the Sakhalin liquefaction plant finally comes on-stream (in 2008, at the earliest) it will introduce substantial new competition for LNG supplies to the East Asian gas market due to shorter shipping distances than those of suppliers such as Australia and Indonesia. For this reason the Asia-Australasian liquefaction plants need to develop new markets if they are to justify expansion and construction of new trains. India is one potential market, but competition from Middle East suppliers will be fierce there. The west coast of the U.S. and Mexico is the market that has drawn the attention of potential LNG suppliers from all corners of the Pacific basin for the past few years. A small market for LNG imports is also emerging in Chile, which can no longer rely totally upon gas supplies from its neighbors.

California desperatly needs large volumes of natural gas supplies to meet its growing energy demand. But public opposition has frustrated the state’s energy planners and potential suppliers. Approval for several proposed LNG regasification facilities has been slowed, and none is yet under construction. Plants will probably be built in Canada and Mexico, to supply part of California’s needs. One way or another, the California market will be opened to LNG. And competition to supply it will be intense, with competitors from Sakhalin, Australia, Indonesia (Tangguh), South America (Peru), and even potentially a new liquefaction plant in Alaska, all bidding for the business.

Flexible LNG Contracting Arrangements Prevail

The re-emergence of the U.S. LNG market has enabled arbitrage opportunities between the U.S. and Europe. The relationship between suppliers and buyers, and the point of origin and end-point for LNG shipments, are no longer rigid. Historically, a principal concern of the LNG buyers was supply security, particularly in the absence of alternative gas sources. Thus, many buyers developed a portfolio of long-term, relatively inflexible contracts with suppliers. In addition, some buyers have used spot or short-term purchases to manage seasonal peaks, unexpected demand growth, or shrinkage. However, changes in the global gas markets are forcing buyers to adopt increasingly flexible and diversified contracting strategies.

Security for buyers and sellers, and the ability for each to extract value from the LNG supply chain, is now achieved by both through involvements along the full length of the supply chain and trading of the LNG on an FOB basis (at point of loading), rather than on a CIF (delivered) one. As LNG buyers have expanded along the LNG value chain they have become involved in shipping, trading, liquefaction, and upstream. This change has been motivated by the buyer’s need to develop operational flexibility to deal with seasonality and price/volume risks. This relates to the need to diversify revenue streams and take advantage of increased buying power.

New Options for Price Indexation in LNG Contracts

Buyers are also using new types of price indexation in contracts that link LNG purchase prices to factors other than oil price. In some cases, LNG prices are linked to spot-market gas prices, or coal, or fuel oil/distillate prices where these fuels are the main energy alternatives to LNG.

Competition for LNG supplies is also growing, leading to increased economies of scale, from expansion of existing LNG receiving facilities to construction of larger liquefaction trains. Higher materials and services costs, and skilled manpower shortages in the LNG industry due to the high demand of the past two years, have slowed progress towards lower unit costs for facilities. Few expect such challenges to seriously impact the growth of the LNG industry in the medium and long-term, but they may impact delivered LNG prices and the break-even prices for liquefaction plants now under construction.

Integrated Gas Hubs Merge Upstream and Downstream

In countries where significant, relatively low-cost gas resources are present, companies and governments are now developing integrated complexes incorporating LNG, gas-to-liquids (GTL), and other gas monetization processes. Such complexes are under construction in Qatar and Equatorial Guinea and will benefit from shared port and handling infrastructure. In addition, suppliers have identified the value of integration in the LNG value chain.

Downstream in Europe, LNG receiving terminals at Zeebrugge in Belgium, and future terminals planned for Rotterdam in Holland, will act, in conjunction with pipeline gas imports, as trading hubs and entry points for LNG into the wider European gas markets. As deregulation of Europe’s gas markets matures, increased numbers of gas trading hubs, integrating LNG receiving terminals, can be expected to emerge. In a similar fashion, several of the Gulf of Mexico LNG receiving terminals under development are located where major pipelines bring gas ashore from GOM production, and are linked with underground gas storage facilities.

Gas Price Volatility in U.S. and U.K. Markets Presents a Challenge

One cloud on the horizon is the possibility that government energy strategists in the U.S. and U.K. will respond to short-term gas price volatility and recent winter gas price spikes, and sanction new nuclear power plants on a massive scale. This would probably not dampen the gas infrastructure development growth in the medium term, but could have a long-term impact on the role gas ultimately plays in the primary energy mix.

Both the U.S. and U.K. remain vulnerable to insufficient gas supply to meet peak demand during a cold winter. The forward price curves for both countries reflect the expectation of high winter gas prices driven by supply constraints (Figure 5). Both countries are investing heavily in new infrastructure – the U.K., in LNG receiving terminals and new gas pipelines from Norway and the Netherlands. By 2008, when much of the infrastructure under construction in 2006 is in place and operational, gas prices will likely fall dramatically in both countries. Gas prices should then stabilize at levels competitive with coal and nuclear. If this happens, then growing gas demand in the long-term can be expected to take an increasing share of the primary energy mix. If LNG prices remain high, then coal and nuclear will likely continue to erode some of gas’s overall market share.

Figure 5: High and volatile natural gas
prices have dogged U.S. and U.K.
markets in recent years and the forward
gas price suggests this will continue
in the short-term. New LNG
infrastructure should help stabilize prices
in the medium term

David Wood is affiliated with David Wood & Associates, Lincoln, U.K.