Strong demand stokes the LNG flame

Robust demand for LNG should see the sector withstand threats of increased supply abroad and changes to the gas pricing mechanism.

The prospect that sanctions on Iran might be lifted and that it might be able to resume oil exports is being seen as another potential threat to the economics of the LNG sector.

This adds to the threat posed by the possible rebuilding of Iraq’s oil industry and the expected build-up in North American LNG exports.

Apart from the obvious – that there is no certainty that the embargo on Iranian oil will be lifted; Iraq and its oil industry remain destabilised by savage internal conflict; and exports of the gas flowing from the US shale gas boom are still some years away – no-one in the industry would have committed to investing the vast amounts of capital required to build LNG plants on the basis that the current $US100-plus oil price would be sustained indefinitely.

A sharp decline in the oil price, or the prospect of a flood of LNG out of North America, might impact LNG projects still on the drawing boards and give their promoters pause for thought. However, none of the promoters of the projects currently under construction in offshore Western Australia or at Gladstone in Queensland are publicly or privately displaying any real concern.

That’s partly because the economics of their projects are stronger than they’ve been given credit for and partly because the fundamental supply-demand backdrop appears so favourable.

The cost blowouts experienced by many of the new projects and the potential for increasing oil supply and lower prices could adversely impact profitability. However, LNG prices would have to be decimated before the projects came under real pressure.

Attempts by Asian buyers led by the Japanese and Indians to change the reference point for LNG pricing will probably have only a relatively modest impact on the way most LNG is priced.

Between now and 2025, demand for LNG driven out of Asia is forecast to rise at a compound annual rate of about 5 per cent a year, reaching about 450 million tonnes a year.

According to a presentation given last year by Santos’ vice-president for strategy and development, Peter Cleary, it would require about 45 new LNG trains producing about 4 million tonnes of LNG a year to meet that demand.

At present, the pricing of most LNG contracts is linked to the oil price. But even if oil prices fell, or that linkage broke down in new contracts, the underlying demand picture is very supportive.

The existing LNG projects and those under construction are supported by long-term (20-year-plus) contracts. In most instances, the customers on the other side of those contracts have equity stakes in the projects. The Queensland coal seam methane-fed LNG plants, for instance, are underpinned by long-term and binding off-take agreements with shareholders.

Origin Energy’s Grant King has also said in the past that the three big projects being built at Gladstone would recover their costs at an oil price of about $US40 a barrel and their cost of capital at $US50 a barrel. This provides an insight into the extent to which they could absorb changes to the market and oil prices.

A lower oil price and/or greater competition from North American exports into Asia based on US domestic Henry Hub pricing might reduce the profitability of the projects. But unless there is a very significant change to the projected outlook for demand, their economics ought to be quite robust – at least for the next decade or so.

Cost inflation, the prospect of lower oil prices and competition from North American producers for contracts might, however, impact on those projects yet to be given the go-ahead.

The Japanese and Indians are encouraging North American exports and contracting supply from promoters of LNG export facilities in the US in an attempt to inject more supply and competition into the LNG market and break down the oil-liked pricing of gas that the industry has used for decades.

Cheniere’s conversion of an import terminal in Louisiana is the most advanced of the US facilities. It has signed contracts based on a gas price set at about 115 per cent of the Henry Hub price. At today’s price of around $US4 per MBtu, that would equate to about $US4.60, although the forward curve shows the Henry Hub price rising over time to more than $US6.

Add liquefaction and re-gasification and transport costs of between about $US7 and $US8, and the price ‘’advantage’’ the US might have is not as significant as one might have thought.

While there may be some projects that discount the price relative to current international prices to secure contracts and funding, the discounts are likely to narrow over time as various segments of the supply chain seek to retain profit rather than just hand it to customers.

It is probably also the case that large-scale exports of US gas would drive up the US domestic gas price over time, which is what we are experiencing here as Queensland projects effectively import international gas prices into the domestic market. This would tend to have an impact on the amount of gas available (or the amount that US authorities would allow to be made available) to the international market.

The best guesstimate about the amount of US gas that could be sold into the international market by 2025 is around 30 to 40 million tonnes a year – less than 10 per cent of the projected demand at that point.

There is potential for vast new conventional gas resources in China and Europe, as well as known resources of gas in east Africa. But supply from those sources – if there is meaningful supply – is a long way off.

Lower oil prices and/or increased competition on the supply side of the LNG sector would have some impact on both existing and future LNG projects in the next few years, as will the significant escalation in construction costs.

Projects that have been built to service 20-year contracts, however, were never going to be based on expectations that the status quo of pricing and supply will simply be maintained for the next several decades.

Whether it is increased supply from the Middle East and North America (and consequently lower oil and gas prices), changes to the pricing mechanism in new gas contracts, or even their own cost inflation, the economics of projects with such massive up-front capital commitments and such long-term time horizons ought to be robust enough to cope.

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