International Gas Trade

The cross-national gas trade has been growing for the past 50 years, since the first LNG exports began, from Alaska and Algeria, and the first pipelines were built, from the Netherlands to neighboring countries in Europe. Today, 30% of produced gas is traded across national boundaries, two-thirds by pipeline and the remaining third as LNG. Top gas exporters are Russia, Norway, Qatar, Australia, and, increasingly, the United States. Worldwide trade, especially in LNG, will continue to grow in terms of both the volume and the number of exporting and importing countries. 

During the past several decades, worldwide gas, both pipeline and LNG, activity has risen significantly. There are many reasons for this growth, which will be described in this section.

Global abundance of gas reserves 

Gas reserves are dispersed around the world in a broad belt from Latin America to West Africa, North Africa, the Middle East, the North Sea, Russia, Central Asia, Southeast Asia, Australia, and North America. Regions with a consuming market close enough to be supplied by pipeline gas display an extensive growth of pipeline networks. Remote regions, where gas reserves are close to ocean ports, support LNG as the solution to monetize these reserves.

High energy prices

Rising energy prices between 2000 and 2014 encouraged many international energy companies to work with host governments to develop previously stranded gas resources. High commodity prices reduced the challenge of financing investments in the LNG chain, and international energy companies, flush with cash, have sought large-scale investments, using predictable steady cash flow to offset their declining oil producing assets. LNG projects were seen as the vehicle of organic growth and long-term source of predictable revenues. Commercializing stranded gas reserves through LNG projects allows countries to book otherwise nonvalued reserves—a strong motivation during periods of dismal exploration success..

Desire to supplement oil reserves 

NOCs, which historically had focused their activities on domestic oil production, started to look toward gas to supplement their dwindling oil reserves. LNG and pipeline projects allow production of NGLs—mainly ethane, LPGs, and condensates—that otherwise might remain trapped inside oil and gas reserves. These can be sold at premium prices and are often not included in restrictive reporting on OPEC quotas. The relative successes of Malaysia, Indonesia, Qatar, Australia, and Trinidad have demonstrated to other gas-rich nations that dwindling or relatively minor oil production does not necessarily equate to reduced natural resource income. 

Declining European and Asian production coupled with increasing domestic demand

Oil and gas reservoirs in these regions are largely mature, characterized by expensive operating costs, declining production, and increased water production ratios. Outside of discrete provinces such as subsalt Brazil, Norwegian North Sea, US Gulf of Mexico, Eastern Mediterranean, and offshore Africa, there have been few major new discoveries of oil and gas reservoirs over the past decade. It is no longer feasible in many basins to offset oil production decline by drilling more local wells. 

Flexibility of terms and costs 

Increasing spot and short-term LNG imports into deregulated gas-on-gas markets with floating prices—such as the United Kingdom, and increasingly, continental Europe—threaten the concept of long-term contracts with oil-linked pricing for both LNG and pipeline imports to Europe. Buyers are demanding—and often receiving—flexible terms, shorter-term contracts, prices based on transparent market indices, price review clauses, and destination flexibility (to allow buyers to divert shipment to other ports).

Spot LNG trade

Although definitions vary, spot trades are generally agreements for LNG and gas deliveries with duration less than 3 months or as discrete as a single LNG cargo. According to the International Gas Union, spot LNG volumes accounted for less than 5% of LNG volumes traded in 2000, and as of 2014, this number has increased to 27% (64.7 MTA) of global trade. 

Spot and short-term flexibility has allowed buyers to better manage their contracts and to take advantage of higher prices during their own low-demand seasons. This growth in the spot market has coincided with an exponential increase in the number of players in the LNG market, in terms of both individual players and nations. A number of factors have contributed to the rapid growth of spot LNG trade in recent years. These include new uncontracted supply from producers in Australia, increasing demand by buyers to be able to resell their contracted volume, resulting in more relaxed destination restriction clauses for renewal contracts, easily available shipping capacity, growth in emerging markets willing to contract on short-term and spot basis, and the rapid deployment of FSRUs, providing a low-capital, rapid solution for importing LNG. 

Larger and more expensive LNG projects

As individual LNG trains have become larger, from around 1 MTA per train in the 1960s to the 7.8-MTA trains in Qatar commissioned between 2000 and 2011, total project output also increased proportionally. For many years, the cost per tonne achieved by the project developers showed economies of scale, culminating with the Equatorial Guinea and Egyptian projects completed between 2005 and 2010, when costs dropped to below $500/tonne. The International Gas Union estimates that liquefaction costs have (in real 2014 dollars) increased from an average of $321/tonne in 2000–6 to $851/tonne in 2007–14.2 Cost-per-tonne numbers are notoriously hard to calculate and standardize because project complexities vary greatly, with some requiring expensive pipelines and other infrastructure improvements that can distort the capital numbers (fig. 6–1).

International Pipeline Trade

As the global demand for gas increases and local supply options decline, the requirement to import gas via pipelines that cross international borders increases. Crossing international borders raises the complexity and risks of pipeline investment. It has been stated that every international border crossed raises the complexity of a project by an order of magnitude - this explains why pipelines, with the notable exception of Eastern Europe to Western Europe, are largely confined to domestic or single-border crossings. Crossborder pipelines amplify commercial risks, especially when third-party countries that are neither sellers nor final buyers of the gas are involved. These transit countries demand fees or other concessions - such as cheap or free gas - from producers or consumers, or both, in exchange for allowing pipelines to cross their territories.

The scale of international pipeline projects, both completed and planned, is staggering, with the majority of future pipelines connecting central Asia to markets in Europe and Asia. Pipelines to export Iranian gas are mired in internal politics, while pipeline projects to connect South East Asia will like be superseded by regional LNG trade. North America is poised to become a surprising player in future gas pipeline construction as shale gas production becomes abundant and economics of selling gas to regional and international markets become compelling. As one would expect, the price of steel and construction may make many of these projects commercially and technically challenging.

Liquefied Natural Gas (LNG) Trade

Two distinct LNG trade regions developed as the industry grew rapidly in the period from the 1970s to the 1990s: namely, the Atlantic and Pacific regions. Until Qatar and, to a lesser extent, Oman began to export LNG to both regions in the mid-1990s, the two regions were kept largely separate, each with its unique suppliers, pricing arrangements, project structures, and terms. The massive Qatar volumes and the growth of the spot and reloading trades after 2000 increased cross-regional trades, although the market dynamics remain distinct in these two regions. It remains to be seen how the entry of US LNG will affect pricing, contractual terms, and supply dynamics between the regions; however, more integration is expected as US LNG is exported to all regions on similar terms and regional gas-on-gas hub prices become established in both basins. 

Historically, prices in the Pacific region were higher and more likely to be based on oil product–linked price formulas than Atlantic region prices. Atlantic basin LNG prices were either linked to consuming market hub prices—US hub prices for imports into US, oil product–linked prices in Europe, and, more recently, National Balancing Point (NBP) and title transfer facility (TTF) prices—or determined using a cost-plus formula based on exporting country hub prices plus costs for liquefaction and shipping. 

Since 2014, as global oil prices began to fall, there has been a marked convergence in international prices as the differential between the Atlantic and Pacific regions has decreased. Although the pricing basis remains as before, where the majority of LNG in the Pacific basin continues to trade on oil-linked formulas, falling oil prices have reduced the absolute price of LNG in the Pacific to levels similar to Atlantic market prices. Surplus LNG volumes and declining shipping costs have allowed shippers and traders to move cargoes between regions, reducing any price arbitrage between markets relatively quickly. As the number of cargoes between the regions increases and more suppliers are willing to export to both markets, the lines between the formerly distinct trading regions will become increasingly blurred.

World LNG trade is projected to increase by 50% or more from 2015 to 2035. Future large projects will be in resource-rich countries such as the United States and, if costs can be controlled, then also in Canada, Russia, and East Africa. In the near term (2017–2025), most of the growth is expected to come from midsize LNG projects, many promoted by independent project developers such as Texas LNG. This would represent a significant change from the past decade, which was dominated by increasingly large projects promoted by supermajor energy companies—nearly all of which suffered from massive cost increases and schedule delays. Figure 6–2 shows current and future trade patterns of LNG.


LNG Markets

Pacific Basin
For many decades, the Pacific Basin was the centre of LNG innovation and activity. The Pacific trade, previously accounting for more than 70% of worldwide trade but now lower due to increased LNG imports to Europe, includes exports to Asian consumers from Asia, Western Latin America (Peru), Middle East and, in the future, East Africa. The convergence of the Atlantic and Pacific markets has grown due to the efforts of producers such as Qatar who are able to arbitrage across both markets. Once North American and East African project begin to export LNG, this trend will accelerate as these new entrants would be able to supply both markets as well.

Main buyers in the Pacific region are Japan, South Korea, Taiwan (the 'JKT' buyers), and emerging buyers such as China, India, Thailand, Indonesia and, in late 2013 Singapore. Both Singapore and Thailand are aiming to become LNG hubs that will allow cargoes to be offloaded, stored and resold when the prices are favourable. Singapore, in particular, is encouraging LNG trading companies to relocate to the island-state by granting favourable taxation. Japan's dependence on LNG has grown after the 2011 disasters and there are signs that Japanese buyers are beginning to be less conservative and willing to emulate buyers such as Korea's KOGAS, which has become the world's largest buyer of LNG by taking large interests in projects and, in some cases, technical (ie: FLNG and Unconventional) and exploration risks.

Atlantic Basin
The Atlantic LNG trade has developed differently than the Pacific trade. Until last decade, the regions were completely separated, with no common LNG suppliers. The regions have begun to converge as Qatar, and to a lesser extent, Oman, have begun to supply both markets. The growth of the spot and short-term markets has also encouraged markets to cooperate. However, there remains large price disparity between the markets which will likely continue until new large scale suppliers (such as the US) disrupt both markets with new pricing schemes and flexible supply.

The Atlantic basin is dominated by key European markets; UK, Spain, Italy, France and Belgium / Holland. LNG has been imported into Continental Europe since the mid 1970s, when France signed an agreement with Algeria. In the past few years, a majority of European countries with sea ports have built LNG terminals.

European pipeline trade from Russian and CIS is largely influenced by the German market; likewise the North African pipeline trade is under the control of French, Italian and Spanish interest. Gas from Norway is sold to both continental and UK markets.

The US import market was expected to be a significant LNG player - however, with the incredible growth of shale gas production since 2005, the US share of the world wide LNG trade is minimal - though the US continues to import large volumes of Canadian gas via pipelines. The likely prospect of North American LNG exports around 2016 onwards will, however, disrupt the global LNG trade and potentially cripple the LNG pricing formulas (sustainability of oil-price linkages ) and contract terms familiar with buyers today. If the US experience of shale gas is repeated in other regions, an unlikely prospect due to a variety of reasons, the global gas markets could be altered radically.