US LNG - exporting a revolution

November 7, 2013 | 00:00

US LNG – exporting a revolution

When large-scale exports of US LNG become reality – before the end of this decade – the US will become much more than just another supplier. Along with the methane molecules, it will be exporting a new way of doing natural gas business. The implications are profound, for buyers everywhere and for new supply projects in other regions. And yet some leading executives of major companies do not seem to fathom the enormity of the US LNG export rush.

(c) Bloomberg / Bloomberg View
The debate about whether the US should or should not become a large-scale LNG exporter is all but over. With the point of no return now past, it is time to consider the various impacts that this new energy revolution is likely to have – not least in the hearts and minds of buyers and sellers. These impacts are already being felt, even though exports from the Lower 48 states will not begin until 2015 or 2016.

The US becoming a large-scale LNG exporter raises three crucial questions: how large an exporter will it become? How will the new commercial models being adopted by the front-runner projects affect how business is done? And what are the likely impacts on proposed LNG supply projects elsewhere?

How large an LNG exporter is the US likely to become?

How much LNG is eventually exported from the US is less important than the amount of capacity likely to be constructed. The over-exuberance we are seeing among sponsors of potential projects suggests that more capacity will be built than will be fully utilised; export licence applications continue to arrive at the Department of Energy, despite the queue. As of last month the DoE had received 34 applications. As one source drily commented: “There is a propensity for over-investment.”

This may not matter much to the project sponsors if the business model for a project is a tolling contract, as most of them are – so long as they are paid the tolling fee for their liquefaction capacity. Whether gas passes through the facility is more a matter of concern for buyers – as we will see.

In evaluating which projects are likely to proceed, the following factors are key:

  • Do they have export approvals from the DoE?
  • How far advanced are they in gaining the – costly and time-consuming – siting, construction and operation approvals they need from the Federal Energy Regulatory Commission (FERC)? According to Charif Souki, the CEO of Cheniere – the only company to have so far reached the end of this long road – securing such an approval takes between 18 months and two years, and costs around one hundred million USD.
  • Have they sold their capacity to buyers?
  • And will they be able to attract finance?

The various debates at last month’s World Energy Congress in South Korea suggest that the enormity of the US LNG export stampede has yet to sink in – even amongst leading executives of major companies.

Already the DoE has given full export approvals to four projects – Sabine Pass, Freeport LNG, Lake Charles and Dominion Cove Point – each of which is a major undertaking.

The clear leader is Cheniere Energy, which is constructing four liquefaction trains at its Sabine Pass project. These alone will have a nameplate capacity of 18 mtpa, all covered by long-term arrangements, and actual capacity of around 20 mtpa. In September the company made a formal application to the FERC for train five (whose capacity is mostly already contracted) and train six, putting it on track to develop some 30 mtpa. In 2012 only one country produced more LNG than this: Qatar.

Freeport LNG is proceeding with two 4.4 mtpa trains, for which it expects FERC approval next year. All the capacity has been contracted. Moreover, it has recently sold the capacity in train three and is considering a fourth. Like Cheniere, it expects the capacity of its trains to exceed nameplate, so it could end up with some 20 mtpa.

And so the list goes on. There are plenty other credible projects, not least the Golden Pass venture being pursued by ExxonMobil and Qatar Petroleum: 15 .6 mtpa of capacity for an estimated $10 billion (compared with Australia’s Gorgon – 15.6 mtpa costing over US$50 billion).

It is looking a fair bet that the US will overtake Qatar in terms of capacity sometime early in the next decade and it is conceivable that US LNG capacity could exceed 100 mtpa by 2025.

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

The US front-runner projects are a major departure from the traditional way of developing such projects. They are mostly conversions of regasification projects and so already have storage tanks and ship-handling facilities in place. Generally, this makes them highly competitive with green-field projects in capital expenditure. They will take gas from the pipeline network rather than dedicated fields.

Most significant of all, the business model being adopted by most projects is a tolling arrangement, so customers contract for liquefaction capacity rather than LNG. Sabine Pass, the first project is an exception, but its sales and purchase agreements are so structured that the net effect is very similar. Buyers will pay 115 percent of the Henry Hub (HH) 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 oil-linked contracts, are so enthusiastic about buying US LNG, with price indexed to HH.

The attraction is only partly to do with price level. At current oil and HH prices, US shale gas would be some 30 percent 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 oil-linked LNG being cheaper than HH-linked LNG.

A further attraction therefore is optionality. US LNG bought under tolling arrangements is free of destination restrictions, allowing buyers to trade the gas however they wish. Buyers can also choose not to use the capacity they are paying for. They would not then have to pay for molecules, transportation or regasification.

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 pricing. New price indices such as HH and NBP will emerge . . . A portfolio of long-term, short-term and spot contracts, as well as destination flexibility, will lead to increasing liquidity.”

As for buyers in Europe, the more LNG is exported from the US, the less will be the price pressures that buyers here have to face as Asian demand pulls flexible supply away from Europe.

What are the likely impacts on LNG supply projects elsewhere?

The chorus of comments from Asian buyers echoing Muraki must be impacting the thinking of proposed LNG supply projects that have not yet reached final investment decision – in Alaska, Canada, Russia, East Africa, the Mediterranean and Australia.

Chevron has just indicated it will be re-considering train four at Gorgon. Woodside has abandoned planned onshore liquefaction for Browse and is considering floating LNG to reduce costs.

Much will depend on the progress that US projects are seen to be making. Most of the proposed projects in other regions do not have the capex advantages of the regas conversions and some will need expensive pipelines and other infrastructure. High-cost projects are likely to want to underpin their investments with traditional oil-linked long-term contracts.

Once again, the LNG industry finds itself in the throes of transformation – with the future looking hard to predict.


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