US LNG: rebellion or revolution?

In the second part of our series on Australia's gas sector, Gaurav Sodhi finds that the threat from US shale gas may not be all it's cracked up to be.

Key Points

  • Shale economics are fragile
  • US gas prices must rise
  • US cost advantage is limited

(This is the 'bull' case of a 'bull and bear' analysis of Australia's LNG sector – you can read MacroBusiness's David Llewellyn-Smith's more pessimistic take in Australia's $200bn LNG white elephant, published on 2 Dec 2013.)

All revolutions have their winners and their losers, and the shale gas revolution in the US is no different. Although oil and gas production has soared with the introduction of horizontal drilling and hydraulic fracturing, the bonanza has come with costs. Coal is one obvious casualty; another might be Australian LNG.

Rocketing American gas production has fuelled three main concerns about Australian LNG projects: that supply will overwhelm global demand; that the Americans will undercut Australian projects; and that changes to the existing contract system will lead to dramatic falls in LNG prices.

All these concerns are rational, legitimate and now widely accepted. LNG stocks have, as a result, been discounted and dumped. Do they really deserve such scorn? Is Australian LNG an inevitable casualty of the American shale revolution?

America will soon overtake Saudi Arabia and Russia to become the world’s largest producer of oil and gas. This doesn’t necessarily mean, however, that there will be an abundance to export. As prices have fallen and supply has expanded, demand for gas has exploded.

This has been most prominent in the electricity market where, in less than 5 years, gas has replaced coal as America’s prime generation fuel.

Gas use isn’t limited to electricity production. Since 2011, the Gulf Coast alone has attracted 128 new energy hungry industrial plants. Cement makers, ammonia producers, chemical crackers and fertiliser makers have all flocked to the US for abundant gas supplies. Over $100bn worth of new plants have already been built and many more are planned. Ten years ago, Nucor dismantled its US steel plant and moved it to Trinidad. This year it bought it back, attracted by the easy availability of gas. A new industrial revolution is underway.

Yet just as long-term demand is being installed, questions about the true cost of shale production are being asked.

Shale economics

The economics of conventional and shale gas differ starkly. Conventional gas wells entail a high degree of geological risk and large upfront expenditures to find and develop a gas field. Once this is done, however, producers rarely have to put in more cash: a small number of wells can generate reliable cash flows for decades.

Shale is different. Usually homogenous formations, shales entail very little geological risk: the probability of striking gas is very high and drilling one well is a fraction of the cost of deep water, offshore wells. A typical shale well will cost about US$10m to drill, frack and complete. A deep water gas well could cost 10 times that amount.

The typical shale well will, however, decline by 70-80% within 12 months. The rate of decline in conventional wells is nothing as dramatic. Whereas only a few wells are needed in conventional reservoirs, shales require thousands of wells. It is a far more capital intensive business.

In some cases the capital costs have proved too much. Big producers are already writing down assets and limiting activity. Shell, Exxon and BHP have all expressed growing caution over shale operations. To understand why, let’s examine one of the stars of the boom, locally listed Aurora Oil and Gas (ASX Code: AUT).

The Aurora example

Aurora’s share price has increased 1,500% over the past five years and its market capitalisation is now over $1bn. Over the past five years it has reported operating cash flows of about $170m and capital expenditure of over $700m. Net debt has risen to over $550m and the company’s cash needs get larger and more urgent every year.

This is the curse of shale producers. Every production increase comes with the need for additional cash. Hardly any producer in the industry generates free cash flows. Estimates suggest that, to sustain current US production rates of about 7.8m barrels of oil per day (bopd), producers in the US will have to drill about 6,000 wells each year at a cost of about $35bn. No wonder the big boys are leaving.

There is a second, geological, problem: new wells aren’t as productive as those they replace because the best areas are picked over first. In other words, diminishing returns are starting to kick in. With poor economics and deteriorating geology, some suggest that US production could peak by 2017 and start to decline by 2019.

Higher demand and poor returns for producers mean one thing: that US gas prices must rise. If that happens, production could be sustained for longer. Will it threaten Australian output?

The global shudder

When US listed Cheniere Energy announced it would be the first US company to export LNG to Asia, Australian LNG producers shuddered. Korea Gas, a key customer, boasted it had signed a deal based on US domestic prices, known as 'Henry Hub'. The old link to oil prices had finally been broken. With US gas prices among the cheapest in the world, any deal forsaking an oil price link for a Henry Hub link would leave other producers uncompetitive. Well, not quite.

The Korea Gas deal calls for a 115% link to Henry Hub prices, worth about US$4.60mmbtu (millions of British thermal units) today. Liquefaction and transport costs add another US$7-8 suggesting prices of about US$12mmbtu. That’s a long way from today’s spot prices of US$16-17mmbtu.

As we have suggested, however, US gas prices will rise. The forward curve suggests prices of about US$6mmbtu, although private sector commentary suggests prices as high as US$9mmbtu by 2035. Using the forward price of US gas suggests an LNG price of about US$13-14mmbtu.

Although this is lower than the spot LNG price, it is very close to the contracted price at which most Australian LNG is sold (see Chart 1).

LNG contracts are notoriously secretive. Our best guess – and admittedly it is only a guess – is that they are about 15% of the oil price, or about US$14mmbtu at today’s price. As Chart 1 suggests, Cheniere is a cheaper producer but not dramatically so. It will make better returns than many Australian projects, but it will hardly undermine the existing LNG order.

Capital advantage

What about the long line of US projects awaiting export approval? The US coastline is dotted with 12 LNG import terminals made redundant by shale gas production. With a small capital injection, they could be turned into LNG export terminals. This is the true source of America’s LNG advantage.

Cheniere will produce fabulous profits on its project not because its operating costs are slightly cheaper but because its capital costs are substantially cheaper. Cheniere will convert the Louisiana LNG import facility to an export facility for about US$5bn. To construct a new terminal from scratch would cost at least 3 times that sum.

Most LNG projects that have been approved or are awaiting approval involve converting an existing import facility. This point is vital: the first 12 US LNG projects will undercut most of the world's production because they can access an infrastructure advantage. The 13th LNG project from the US will have no such advantage.


The American shale gas revolution is an important event but geological and economic evidence suggests its success may be overstated.

US gas prices must rise to sustain the revolution and, as they do, the economics of American LNG will start to resemble those of other producers. There is a limited opportunity to export LNG at substantially lower costs, but we should not confuse a limited infrastructure advantage for a lasting competitive advantage. The closer you inspect it, the more US LNG resembles a rebellion rather than a revolution.

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