The future of LNG

May 1, 2012
Should we convert LNG import terminals to export terminals? With conversion costs up to $8 billion per terminal, we need to consider the long-term prospects for the export market first.

Should we convert LNG import terminals to export terminals? With conversion costs up to $8 billion per terminal, we need to consider the long-term prospects for the export market first.

Bradley J. Richards, Haynes and Boone LLP, Houston

In the early 1970s, during its first major energy crisis, the United States began building and operating ship terminals to import liquefied natural gas (LNG). Today, we have 12 terminals scattered around the country. The newest operating terminal built by Cheniere Energy in Sabine Pass, La., began importing LNG in 2008.

But, times have changed. Once we had a shortage of domestic natural gas, Now we have a glut. It no longer makes economic sense to import LNG.

America's natural gas reserves have increased because new technologies, including the use of hydraulic fracturing (or fracing) in shale formations stretching from Texas to New York, have enabled greater efficiency in extracting gas and provided greater access to natural gas deposits. The country has so much natural gas that contracts for April delivery of natural gas were selling in mid-March at the low rate of $2.29 per million British thermal units (MMbtu) at Henry Hub in Erath, La., the nation's largest centralized point for natural gas trading.

So, the real question facing the natural gas industry, shippers, policy-makers, and investors is whether some of those 12 LNG terminals should be converted from import terminals to export terminals. With conversion costs estimated at $2 billion to $8 billion per terminal, the question is not academic. Like all capital intensive issues, however, the long-term prospects for export must be considered with any proposed conversion.

The ExxonMobil Corp.-operated Golden Pass LNG terminal on the Sabine Pass waterway near Port Arthur, Texas, received its first commissioning cargo in late 2010. The 15.6-million-tpy (peak) terminal is a joint venture of Qatar Petroleum International (70%), ExxonMobil (17.6%) and ConocoPhillips (12.4%). Photo courtesy of ExxonMobil.

Supply, demand factors

The Brookings Institution, a respected, independent research organization based in Washington, DC, released a draft report in January 2012 on prospects for the export of LNG, and foreshadowed its findings with a statement that captures the breadth of change: "Less than a decade ago, the United States was facing a major shortfall in the supply of natural gas as declining conventional production and reserves were outpaced by rising demand. Since 2005, the situation has dramatically reversed."

In its report, Brookings cautions that factors on both the supply and demand sides will influence the potential for LNG export. On the supply side, estimates of US natural gas reserves vary widely. A few respected petroleum engineers are concerned that the shale deposits will be short-lived and that political and physical limitations will limit long-term growth prospects. They point to production declines in recently drilled wells. Moreover, potential new environmental regulations from Washington and by state regulators, and public concern about the dangers of hydraulic fracturing, could impact the supply.

However, most experts are much more bullish. They believe the shale gas resource plays are still in their infancy and estimate that the US has more than a 100 year supply of gas. The bulls' argument is bolstered by the sheer amount of potential reserves yet to be exploited, as well as by the perception, even in Washington, that gas production should be encouraged because it burns cleaner than other fossil fuels.

On the demand side, the Brookings study indicated that growing domestic consumption by power plants and petrochemical and industrial plants would determine whether we have sufficient supplies of LNG available for export. The cost of complying with clean air regulations as well as pricing pressure from inexpensive natural gas is encouraging utilities to shut down last-generation, coal-fired power plants.

As recently as the 2011 State of the Union Speech, President Obama highlighted nuclear power as an important additional energy source. But, following the Fukushima Daiichi nuclear disaster in Japan, support for nuclear power has eroded. Inevitably, at least in the short run, the US is likely to become even more reliant on natural gas to support the nation's power plant infrastructure.

Yet, within the US, gas and coal prices tend to move in tandem, and thus coal is selling very inexpensively. The 2012 futures price for Central Appalachian coal declined 11.7% toward the end of February, falling from $69.67 per short ton at the beginning of the year to $61.50 at the close of trading on February 24, according to the US Energy Information Administration.

The volume of coal consumed by the US electric power sector was expected to decline by 1.3% during the first quarter of 2012 compared to the same period last year, while natural gas use by the power sector was forecast to rise by 12%, according to the EIA.

Utilities tend to favor coal for their base-load power plants, using gas to fuel smaller peak-load plants that typically operate only 10% to 15% of the time. With abundant coal supplies available at low prices, utilities will continue to be motivated to develop "clean coal" technologies that - if successful - will compete with natural gas. It is easy to conclude that natural gas demand in the US will grow but that its growth may be tempered by these other factors.

Gas and LNG

Meanwhile, demand for natural gas outside the US is booming, and the prospects for US exports of LNG are positive.

Gas is already exported through pipelines to Mexico, but gas pipelines can't reach overseas markets. To move gas across the ocean, the gas must first be cooled and liquefied, with the resulting LNG transported aboard specially equipped LNG tankers.

Demand in Asia

Existing LNG tankers primarily service two regional markets: the Pacific Basin and the Atlantic Basin. The Pacific Basin includes Japan, the world's largest consumer of LNG, as well as South Korea and Taiwan. Japan produces only 4% to 6% of its natural gas needs domestically. Korea and Taiwan are similarly limited. These three countries currently import their natural gas in the form of LNG from Qatar, Indonesia, Malaysia, Nigeria, and Australia.

The triple meltdown at the Fukushima Daiichi nuclear facility following a March 11, 2011 earthquake left Japanese policy-makers in a quandary over the future of nuclear energy. With all but 2 of its 54 reactors idled as of mid-March 2012, Japan is facing electricity shortages that have damaged manufacturing centers in Osaka and Tokyo. According to The Washington Post, two-thirds of Japanese citizens now oppose nuclear power generation. Therefore, Japan may offer a great market opportunity for additional LNG imports.

Following the Fukushima disaster, natural gas prices in Japan shot up to $17 MMbtu. Today, they remain at approximately $16 MMbtu. By comparison, during the pre-recession period of 2006-2008, US natural gas prices - at their highest in modern times - ranged from $6 to $10 MMbtu. As supplies overshot demand, the price in the US fell to $2.50 to $2.75 MMbtu by early 2012. That price differential should whet the appetite of potential US exporters.

Even when processing and transportation costs are added to the mix, the price arbitrage between the US and Asia remains compelling. To make a "back of the envelope" calculation of potential margins, one can take the current Henry Hub price of $2.70 per MMbtu and add the following costs, estimated in a study by the Massachusetts Institute of Technology: $2.15 in liquefaction costs; $1.25 in shipping costs; and $0.70 in re-gasification costs, although these costs certainly would vary depending on the size of the liquefaction plant built, shipping fuel costs, ship size, and local conditions. MIT's estimated total cost of $5.35 MMbtu to make domestic natural gas LNG export-ready suggests that exports would be highly profitable in today's markets, as long as the Asian-US price spread holds up.

It is relatively easy to predict that the spread will hold. Fukushima is only one factor affecting prices in the Pacific Basin. Qatar has stopped production from one gas field and placed a limit on exports to prop up prices. Other Middle Eastern countries have limited exports to meet heightened domestic needs. However, as a cautionary note, it is worth noting that Canada, which is seeing substantially increased natural gas production and only moderate growth in domestic demand, is also looking to export natural gas in the form of LNG. Export facilities in British Columbia, on Canada's West Coast, would be ideally situated to serve Pacific Basin markets such as Japan, and could compete with US interests.

Prices in Asia are also supported by continued energy demand in China and India. The EIA's latest international energy outlook projects that China and India together will consume 31% of the world's energy in 2035, up from 21% in 2008. Although China has potential shale gas deposits that it can exploit, its reserves are still modest.

The US Central Intelligence Agency estimates that China has 800 billion cubic meters of gas reserves (a tenth of estimated US reserves). To meet their domestic demand for gas, both China and India are counting on imports and have invested in infrastructure to convert LNG back into gas.

In 2014, the Panama Canal expansion will be completed. Currently, only 6% of the world's LNG carriers can be accommodated through the canal's locks. According to Silvia de Marucci, head of liquid bulk traffic at the canal, upon completion of the expansion project, 80% of the carriers will be able to transit the canal.

Andy Flower, head of consultancy Flower LNG, has told Interfax that for tankers serving Texas and Louisiana liquefaction plants, use of the canal "will knock around 20 days off their journey to Asian markets, and shave around $0.80 MMbtu to $1 MMbtu off cargo prices."

Atlantic Basin and Europe

While there are small potential LNG export markets in the Caribbean and South America, the Atlantic Basin market is mainly oriented toward Europe, which now relies primarily on natural gas transported in pipelines from Russia and Norway.

Norway's reserves are growing but its exports declined in 2011. And while Russia's natural gas production remains strong and is projected to increase by roughly one-third between 2010 and 2035, Europe cannot depend on Russia. This winter, Russia cut its normal export levels to Europe because of brutal weather at home. Italy reported over the winter that it was experiencing "critical" shortages of Russian natural gas. Moreover, Russia, under Vladmir Putin, has used the threat of supply disruptions as a foreign policy weapon against importing states. Thus, Russia is not a reliable supplier of natural gas to Europe.

Europe faces other uncertainties that will affect its gas supplies.

Germany has decided to phase out its nuclear reactors after the current generation ages out, shifting much of the demand for fuel to natural gas. Italy also has decided against building new reactors. Shale gas deposits in Europe could be opened if public opposition to hydraulic fracturing can be overcome. But, most observers are not optimistic about these prospects, except in Poland.

Clearly, while economic growth may not produce the demand for gas that we envision for Asia, there are forces at work that give promise to prospects for significant LNG exports to Europe.

The US-Europe price spread is not as wide as the US-Asia price spread, but it is still consequential. According to, the European price was about $13 MMbtu in early December, when the US price was approximately $5 MMbtu. Significantly, the trend in Europe has been for prices to rise, whereas the trend in the US has been for prices to fall. Inevitably, a significant price spread will remain.

Impact on domestic prices

If LNG were shipped overseas, how would that affect the domestic market for natural gas? Several analysts have attempted to model the supply curve for and price elasticity of natural gas.

Navigant Consulting found in 2010 that exports of 2 bcf/day would result in an increase in domestic natural gas prices of 49 cents per MMbtu by 2035. A 2011 study by ICF estimated that exports of natural gas of 2 bcf/day and 6 bcf/day would increase Henry Hub natural gas prices by 22 cents and 64 cents per MMbtu, respectively, between 2015 and 2035. Deloitte released an economic analysis in November 2011 showing the impact of 6 bcf/day LNG exports to be 10 to 22 cents per MMbtu.

If the minimal price effects hold, domestic opposition to natural gas exports should remain muted. Nevertheless, political opposition to exports could increase at any time if natural gas supplies in the US come under pressure or industrial users who fear price increases obtain additional allies.

Making exports pay

Cheniere Energy has already indicated that it believes its salvation lies, in part, in LNG exports. It received financing for its Sabine Pass import terminal in 2005, but the market has turned 180 degrees in the last seven years. The highly leveraged company is now focused on financing a liquefaction facility at Sabine Pass.

Project Finance magazine reported in February that Cheniere will finance the facilities, estimated to cost between $4.5 billion and $5 billion, with loans backed by contracts. For Phase 1, Cheniere secured contracts in late 2011 from BG Group of the United Kingdom and Gas Natural of Spain. For Phase 2, Cheniere plans to secure loans or bonds backed by GAIL and Kogas, natural gas distribution companies in India and South Korea, respectively. To provide further support to these efforts - and validating the strategy - Cheniere announced in late February that Blackstone agreed to buy $2 billion in new senior subordinated paid-in-kind units in Cheniere.

Potential export projects inevitably will be capital-intensive. Cheniere's experience suggests that these projects are not for the faint-of-heart. High up-front capital costs raise the stakes enormously. Price arbitrage certainly can help secure a good lending package, provided the offtake agreement provides sufficient long-term price protection.

Moreover, because the price of gas is affected by daily trading volumes and market expectations for future supply and demand, any company entering a long-term contract must also develop a hedging plan to reduce the price risk for the buyer, the seller and the banks that are relying on the offtake agreement for debt service.

To reduce risk and attract lenders, exporters will need to structure their projects so that they include pipeline infrastructure to the terminal, strong partners capable of providing credit support, long-term offtake contracts with credit-worthy buyers, and a sophisticated hedging policy.

Export licenses

Under Section 3 of the Natural Gas Act, any party wishing to export LNG from the US must obtain authorization from the Secretary of Energy. To issue his approval, the Secretary must determine that the proposed export is not "inconsistent with the public interest." Cheniere has been successful in obtaining conditional authorization for the export of up to 803 billion cubic feet (equivalent to 803 million MMbtu) per year from Sabine Pass for a period of 20 years.

Because the exports would be to non-free trade agreement countries, the US Department of Energy noted that it issued the conditional authorization based on a review of the effect of the exports on domestic supply. The conditional authorization, therefore, may be impacted by subsequent applications, because the Department will need to examine the cumulative effect of these exports on the domestic natural gas market.

Recently, several additional applications for LNG exports have been made. Gulf Coast LNG Export LLC is seeking approval to export 1022 billion cubic feet per year from a facility in Brownsville, Texas, for a period of 25 years. Freeport LNG Expansion LP has applied for authority to export 511 billion cubic feet for 25 years. And Cambridge Energy would like to export 500 metric tons (equal to 0.038 billion cubic feet) of natural gas per year for 25 years.

Although these license applications collectively reflect requests to export significant amounts of LNG, the total amount from these four applications (less than 2500 billion cubic feet) pales in comparison to the total natural gas produced in the US.

When produced, natural gas contains contaminants, which must be processed either at the wellhead or in processing plants. According to the EIA, in 2009 there were 493 operational natural gas processing plants in the US with a combined operating capacity of 77 billion cubic feet (bcf) per day. Using only those plants, it would take about 32 days to process the maximum amount currently requested for export. Thus, the export license process should not limit future opportunities for export.

A 'golden age'?

A key message from the LNG Shipping Conference held in London last February was that the expansion of LNG supply and demand worldwide should continue over the next decade, supporting an optimistic outlook for LNG exports.

That sentiment was echoed in the International Energy Agency's book World Energy Outlook, published in December 2011. The IEA's chief economist, Fatih Birol, said decisions made in Beijing, New Delhi, and Moscow will have an impact on developed nations. The IEA expects the consumption of gas to catch up with the consumption of coal.

"We are entering a golden age for gas," said Birol.

Exporters who can structure deals to limit risk and maximize opportunities will be rewarded. The byproduct of their efforts should be higher US exports of LNG, with strong returns.

About the author

Bradley J. Richards is a partner in the energy practice group in the Houston office of Haynes and Boone LLP. He specializes in complex cross-border financial transactions, working with banks, energy companies, project developers, foreign investors, and others across the world.
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