The time for doubt is past. The US is well on its way to becoming a major LNG exporter – on a scale to rival Qatar and Australia. In part 2 of this two-part series, energy journalist Alex Forbes reviews the implications of what he is convinced will be the next gas revolution to come out of the United States. (Part I was published on 14 October here.)

Implications for US gas consumers

Cheniere’s 2010 application for LNG export approval took many people by surprise and attracted a lot of attention and opposition. Somewhat taken aback, the DoE eventually gave its approval in 2011 but put all the other non-FTA applications on hold, while it awaited the conclusions of two studies into the issue: one produced by the Energy Information Administration (EIA), which looked at how different export scenarios would affect domestic gas prices, and a report commissioned from NERA Economic Consulting, which examined the wider potential impacts on the US economy.

The EIA report, published in early 2012, considered four scenarios for US LNG exports: the first two assumed exports would reach 6 Bcf/d, phased in either at a slow rate of 1 Bcf/d per year or a faster rate of 3 Bcf/d/year; the second two assumed exports would reach 12 Bcf/d, phased in at the same rates. It concluded that: “On average, from 2015 to 2035, natural gas bills paid by end-use consumers in the residential, commercial, and industrial sectors combined increase 3-9% over a comparable baseline case with no exports, depending on the export scenario and case, while increases in electricity bills paid by end-use customers range from 1% to 3%.”

The EIA report was controversial enough, but nowhere near as controversial as the NERA report published by the DOE in December 2012, after a number of delays. Entitled “Macroeconomic Impacts of LNG Exports from the United States”, it concluded that: “ . . . for every one of the market scenarios examined, net economic benefits increased as the level of LNG exports increased. In particular, scenarios with unlimited exports always had higher net economic benefits than corresponding cases with limited exports.”

To date the DoE has shown no sign of concern about the volume of LNG exports it has approved. Its view appears to be that, for now, US gas production will be sufficient to meet large-scale LNG exports with only a modest impact on US gas prices. There is still opposition from several quarters to more licences being granted, but it is much less vociferous than it was following the publication of the NERA report at the end of 2012.

That said, the DoE has this year commissioned yet another study, which will examine the potential economic impacts of LNG exports exceeding 12 Bcf/d (around 90 Mt/y) – in other words beyond any of the scenarios in the NERA report. This is a clear indication that the DoE now believes that LNG export capacity could conceivably exceed 100 Mt/y.

How will the new business models affect the way LNG business is done?

The various players in the LNG industry are watching the US developments closely, not just because of the potential volumes that could be exported but also because of the business models that are being adopted by US projects – which are having a big impact on how LNG business is conducted.

The US front-runner projects are in several ways a major departure from the traditional way of developing LNG export projects. They are mostly conversions of existing regasification projects and so already have substantial infrastructure in place, notably storage tanks and ship-handling facilities. In general terms, this makes them highly competitive with green-field projects in terms of capital expenditure. They will take their gas from the pipeline network rather than dedicated fields.

Most significant of all, the business model being adopted by most of the projects is a tolling arrangement, so the customers contract for liquefaction capacity rather than LNG. Sabine Pass, the first project, is an exception, but its sales and purchase agreements to date are so structured that the net effect is very similar. Buyers will pay 115% of the Henry Hub price for their gas, but do not have to take it if they feel the price is too high – though they still have to pay the liquefaction fee of $3-3.5/MMBtu.

This helps to explain why Asian buyers, most of whose imports are under long-term contract with prices indexed to oil prices, have been enthusiastic about buying US LNG, with the gas price effectively indexed to Henry Hub(HH).

The attraction is partly to do with price level. At the levels of oil price and HH gas price that have prevailed in recent years, US shale gas would be some 30% cheaper than oil-linked LNG by the time it reaches, say, Japan, even allowing for the cost of liquefaction shipping and regasification: around $10-11/MMBtu rather than $15-16/MMBtu. However, Asian buyers are aware that oil prices could go down while HH prices could rise – which could lead to a situation where oil-linked LNG is cheaper than HH-linked LNG.

A further attraction therefore is optionality, in several forms. One is that US LNG bought under tolling arrangements is free of destination restrictions, allowing buyers to trade the gas however they wish (except to certain countries that the US will not allow exports to, such as Iran and North Korea). The other main one is that buyers can choose not to use the liquefaction capacity they are paying for. This would cost them just $3-3.5/MMBtu of capacity (in the case of Cheniere) as they would not have to pay for molecules or transportation or regasification for gas they are not taking.

In the words of Shigeru Muraki, vice-president at Tokyo Gas: ““In the new dynamics of the Asian LNG market, the key word is diversification . . . Contractual conditions will be diversified in terms of the pricing. New price indices such as Henry Hub and NBP will emerge. Oil-indexed gentle slope and S-curve will be re-introduced, to reduce volatility, which is more attractive for consumers, and to secure the long-term return for producers.

“A portfolio of long-term, short-term and spot contracts, as well as destination flexibility, will lead to increasing liquidity of the LNG market. Then LNG traded markets will be developed and an Asian hub will be – possibly – created. Trading and arbitrage between the Pacific and Atlantic markets will be promoted.”

As for buyers in Europe, the more LNG  is exported from the US, the less will be the price pressures that they have to face as Asian demand, especially after Fukushima, has tended to pull flexible supply away from Europe.

What are the likely impacts on LNG supply projects elsewhere?

The chorus of comments from Asian buyers, echoing to a greater or lesser extent those of Muraki, has undoubtedly had an impact on the decision-making processes of proposed LNG supply projects that have not yet reached final investment decision – in Alaska, in Canada, in Russia, offshore East Africa, in the Mediterranean, and, most significantly of all, in Australia, where few new projects, if any, are likely to reach FID.

How this will play out remains to be seen. Much will depend on how much progress the US projects after Sabine Pass, Cameron and Freeport are seen to be making. Most of the projects in other regions do not have the capital expenditure advantages of the regasification conversions in the US and some will need expensive pipelines and other infrastructure. Expensive projects are likely to want to underpin their investments with traditional oil-linked long-term contracts, not least to help secure finance.

Once again, the LNG industry finds itself in the throes of transformation – with the future looking hard to predict. One of the factors that will determine what happens next is that project developers are in a stampede – and in such circumstances logic may not always be the main driving force.