With all the fervor surrounding the US shale gas revolution–it’s not every day that a country transitions so quickly from a growing importer of natural gas to one with an oversupply–it’s easy to overlook the international implications of this domestic supply glut, particularly on the global market for liquefied natural gas (LNG).

Disconcerted by the breakdown between domestic natural gas prices and drilling activity, North American commentators tend to regard global LNG markets as a potential outlet for production from the continent’s prolific shale gas fields.

What is LNG? When natural gas is cooled to minus 260 degrees Fahrenheit at a liquefaction facility, it condenses into a liquid that’s roughly 1/600th its original size. In this form, large amounts of natural gas can be safely transported overseas in specially designed ships. Re-gasification terminals warm the LNG to return it to its gaseous state before pipelines transmit the product to end users.

This technology is far from a recent innovation; the energy industry has relied on this technology for over 50 years. In fact, the Kenai LNG plant owned by ConocoPhillips (NYSE: COP) and Marathon Oil Corp (NYSE: MRO) has operated since 1969 and remains the sole US export terminal. However, that will soon change. In February the facility’s operator and 70 percent owner ConocoPhillips announced that the plant would be mothballed once its latest long-term contract expires. Over the course of its more than 40-year existence, the export terminal sent all of its LNG to Japan, save for one shipment.

A handful of recently proposed liquefaction terminals have captured the imaginations of many investors.

US-based producers EOG Resources (NYSE: EOG) and Apache Corp (NYSE: APA) are the progenitors of the Kitimat LNG joint venture, an export facility sited in Bish Cove, British Columbia that would supply Asian markets with natural gas sourced from the partners’ operations in the Horn River Basin. The source gas for the facility would arrive via the 463-kilometer Pacific Trail Pipelines system.

Source: Kitimat LNG

In 2009 the duo announced a memorandum of understanding (MOU) with Korea Gas Corp (Seoul: 036460) whereby the world’s largest LNG importer would purchase up to 40 percent of Kitimat’s output. The agreement also included an option for Korea Gas to buy an equity stake in the project.

The initial plan calls for a facility capable of processing 5 million metric tons per annum (mmtpa), though capacity could eventually double in size if warranted. The partnership filed with Canada’s National Energy Board (NEB) for a 20-year permit to export up to 10 mmtpa of LNG per year and expects to bring the facility onstream in 2015. The NEB will begin hearings for the requested 20-year export permit on June 7, 2011.

In March 2011, the partners welcomed natural gas producer EnCana Corp (TSX: ECA, NYSE: ECA) to the fold as a 30 percent stakeholder. Apache Corp’s Canadian division remains the operator. The partners awarded the design and construction contract to KBR (NYSE: KBR) and expect to make a final investment decision on the first phase of the project once the front-end engineering and design work is completed in 2011. The project is expected to cost USD4.5 billion for the two export terminals.

Shortly after a ceremony celebrating the Kitimat LNG partners signing a long-term land lease with the Haisla Nation, a second LNG export project came to light. Partnered with Houston-based LNG Partners LLC–a privately held firm that obtained approval for an LNG import terminal on Canada’s east coast and is working on building a floating natural gas liquefaction vessel–the Haisla Nation has applied for a 20-year export license to ship an average of 4,932 metric tons of LNG per day. The terminal’s capacity would be about one-sixth of the Kitimat LNG facility.

Two other proposed exports terminals would be built on the US Gulf Coast. In June 2010 Cheniere Energy Partners LP (AMEX: CQP) proposed adding liquefaction capacity to its Sabine Pass LNG receiving terminal in Cameron’s Parish, La. The sourced gas would come from a number of prolific fields in the region, including the Permian Basin and the Barnett, Haynesville, Eagle Ford, Woodford and Bossier Shale plays.

Initially, the company would add two liquefactions trains, each capable of producing 3.5 mmtpa of LNG. In the event of strong demand from customers, Cheniere would consider installing two additional trains. Thus far, executives from independent gas producers Encana Corp (TSX: ECA, NYSE: ECA) and Chesapeake Energy Corp (NYSE: CHK) have voiced their support for the project. Cheniere also recently announced MOUs with Morgan Stanley (NYSE: MS), Spain’s Gas Natural (Madrid: GAS) and ENN Energy (Hong Kong: 2688) for some of the planned export capacity.

On Sept. 7, 2010, the Dept of Energy approved Cheniere’s request to export about 803 billion cubic feet (bcf) of natural gas annualy over the next 30 years to nations with which the US has a free trade agreement. This was only the first regulatory hurdle. That same day Cheniere field a second proposal to export 803 bcf annually to World Trade Organization (WTO) members and non-WTO countries.

On July 26, 2010, Cheniere also initiated the process to gain approval from the Federal Energy Regulatory Commission (FERC) for the siting, construction and operation of its proposed liquefaction facilities. FERC recently articulated its support for the project, pending the resolution of several issues.

Freeport LNG and Macquarie Energy, the North American energy trading and marketing arm of Australian financial giant Macquarie Group (ASX: MQG), in late November announced that they would develop export capabilities at the terminal in Brazoria County, Texas. The proposed expansion would cost about USD2 billion and would be able to export 1.4 bcf per day by 2015.

Freeport, the owner and operator of the LNG facility, will submit requests to the Dept of Energy for an export license and to FERC for the project itself. Management expects the approval process to take roughly two years.

In recent weeks, operators of two other LNG import terminals have discussed the possibility of adding export capacity. The CEO of Dominion Resources (NYSE: D), for example, stated at an industry conference that the firm’s Cove Point LNG facility in Lusby, Md., would be an ideal candidate to become a bidirectional facility. Although the company hasn’t yet filed for permits with the appropriate regulators, management noted that the terminals proximity to the Appalachian Basin would make it an ideal release valve for gas produced from the Marcellus Shale. The operator of a proposed LNG terminal in Oregon, a legacy of the construction boom earlier in the decade, has also speculated about the possibility of adding export capacity.

These projects underscore the gradual transition of natural gas from a regional fuel to a (somewhat) global commodity and growing demand in emerging-market Asia. But these proposals aren’t the only international ramifications of the US shale gas revolution; not only has output from unconventional fields flooded the domestic market, but this oversupply has also indirectly flooded global markets with excess LNG.

Earlier this decade most analysts projected that US LNG imports would increase steadily, offsetting lower domestic production. Back in 2003 there were at least two dozen proposals to build new re-gasification terminals. But US LNG imports never reached the 812 bcf per year that the Energy Information Administration (EIA) projected in its Annual Energy Outlook 2004 and have fallen off a cliff after peaking in 2007. In fact, according to the EIA, the US imported only 431 billion cubic feet of LNG in 2010, down from the 2007 peak of 771 billion cubic feet.

Source: Energy Information Administration

This decline in US imports, coupled with the demand destruction that occurred during the great recession, flooded the market with low-priced LNG. Much of this gas has found its way to European markets such as Spain, Belgium and the UK, which this year became the forth-largest LNG importer. This influx has prompted some Continental countries to reduce purchases of pipeline gas to the lowest levels allowed by contract, replacing these volumes with lower-priced LNG.

Some analysts have suggested that while this trend won’t mark the end of the long-term gas export contracts favored by the likes of Gazprom (Moscow: GAZP, OTC: OGZPY), this competition could force the Russian giant to become more flexible and reduce the duration of contracts. Meanwhile, Germany’s recent decision to temporarily shutter seven of its nuclear reactors and to accelerate plans to phase out its nuclear power plants should provide another source of LNG demand.

Even more impressive, rising demand for LNG in–where else?–emerging markets has also helped to absorb excess supply and should continue to drive demand over the long term.

For example, the Chinese government’s long-term plans call for natural gas to account for 10 percent of the country’s energy mix, one-third of which will be imported via pipelines or LNG.

Natural gas has been growing in popularity in China, particularly in power-generation facilities located near major cities. Concerns about air quality mean that many of the high-rise residences constructed during China’s recent housing boom are equipped for piped gas. Further migration to urban areas will only increase demand.

LNG imports will be part of the solution. China’s first re-gasification terminal opened in Guangdong province in 2006, and the country currently boasts three import facilities. But that capacity is slated to expand substantially over the next decade. Check out the table below.

Source: Reuters

In addition to a source of demand growth, Chinese energy companies continue to invest in projects overseas that will ensure a steady supply of natural gas.

For example, CNOOC (Hong Kong: 0883, NYSE: CEO) on Dec. 8 agreed to pay AUD50 billion for a 50 percent stake in Exoma Energy’s (ASX: EXE) five exploration blocks in Queensland’s Galilee Basin. Once the deal gains regulatory approval, the resulting coal seam gas will contribute to CNOOC’s LNG supply.

India’s lack of energy resources represents another opportunity for LNG producers, primarily in Australia and Qatar. The country’s Ministry of Petroleum and Natural Gas expects LNG imports to increase from 33 million cubic meters (mcm) per day to 162 mcm per day by fiscal year 2029-30. Over this period the government expects natural gas to grow to 20 percent of India’s energy mix from 9 percent. LNG imports could easily exceed estimates if expected pipeline imports don’t materialize–a distinct possibility–or domestic production falls short of expected production.

Two LNG terminals currently operate in India, Petronet LNG’s (Bombay: 532522) 10 mtpa facility at Dahej and Royal Dutch Shell’s (LSE: RDSA, NYSE: RDS.A) 3.6 mtpa installation at Hazira. Petronet LNG plans to add 2.5 mtpa of additional capacity. Ratnagiri Gas and Power’s 5 mtpa plant in Dabhol remains under construction, though 1mtpa of capacity could come online before the project is completed. Two additional LNG import terminals are in the early stages of planning.

What are the best ways for investors to profit from the near-term rebalancing of the global LNG market and rising demand for this fuel over the long term? Consider investing in the companies that own the tanker ships that transport LNG from liquefaction terminals to re-gasification facilities. Firms that have flexible supplies of LNG also stand to benefit from increased demand for the commodity from Japan, which continues to struggle from an electricity shortage in the wake of a devastating 9.0-magnitude earthquake.

Elliott H. Gue is always on the lookout for lucrative energy-related investments. To learn more about opportunities in international LNG markets and the ramifications of Japan’s nuclear crisis, consult the March 24, 2011, issue of The Energy Strategist, The Fallout.