The US: A gas market turned on its head
US LNG-import terminals are signing agreements to export North American gas, but many variables affect the economics of these potentially risky ventures
Within nine months, the idea of exporting gas from the US Lower 48 as LNG went from cocktail-hour hypothetical to front-page news with extraordinary alacrity. Two Gulf coast regasification terminals – Sabine Pass and Freeport – have announced plans to export LNG from the US, while other companies are conducting feasibility studies to understand the conditions under which exports may be profitable.
In its 2000 Annual Energy Outlook (AEO), the US government agency forecast LNG imports to be flat over a 20-year period, at around 0.9bn cubic feet a day (cf/d). LNG was not on the radar.
Indifference soon gave way to panic. By 2005, the EIA expected the US would become the world's largest LNG importer, taking in almost 18bn cf/d by 2025 – double imports by Japan, which accounted for over 35% of LNG trade in 2009. More than 40 import terminals were proposed along the US east and west coasts, making plans for terminals in China seem yawningly subdued.
The 2005 forecast was the peak; by 2006, the EIA had begun lowering its expectations. Domestic gas production, driven by shale gas, started to rise and soon it became apparent that the US would not need all this LNG. Domestic production was booming and demand was sluggish, creating a prolonged environment of low prices. The last thing the US needed was more gas imports.
By 2009, the EIA had significantly lowered its import forecasts. By now, 2020 demand was put at 3.8bn cf/d, almost four-fifths below the 2005 forecast. But even that proved too optimistic and in the 2011 AEO, the 2020 number came down to 1.4bn cf/d. A decade later, the predictions were back to where they started: LNG would retain a marginal role in the US' gas-supply picture.
Despite the more negative outlook for LNG, companies spent billions building regasification terminals – US import capacity will have risen almost tenfold between 2000 and 2012 – that became stranded assets. Some facilities went months without receiving a cargo and utilisation rates are low. Looking for a new role, terminals have become storage units, importing LNG when it is cheap and then re-exporting when prices are high. Yet the real coup will be to export rather than merely re-export.
Exporting LNG from North America seems like a no brainer. Gas prices in North America lingered in a $3.5-5.0/m British thermal units (Btu) range in 2010. By contrast, South Korea paid $9.74/m Btu for LNG imports in 2010, while Japan paid $10.40/m Btu. In Europe, a mid-point between the premium Asian markets and the US, prices averaged around $8/m Btu.
However, what matters are not prices today, but prices tomorrow. Liquefaction plants have a four-year lead time from construction to completion and are designed to run for at least two decades. So the economics depend on how several variables will evolve over the course of a quarter century.
The first variable is US gas prices. Gas is cheap now, but less than three years ago prices topped $13/m Btu – and this was at a time when production was rising at double digit rates. Even so, the market has a bearish outlook for US gas. At the start of 2011, the futures market showed US benchmark Henry Hub prices would barely reach $7/m Btu during the next decade – a sign that companies and investors do not expect a rally in prices. Forecasts by the EIA and other parties (including PFC Energy) show similar bearishness.
Yet there are at least two uncertainties around this forecast. The first is supply. There is no doubt that there is an enormous amount of gas in the US and that it can be produced at progressively lower prices. Estimates for US gas reserves are regularly updated and revised, and the revisions are always upwards and fairly substantial. Today, the view that the US has ample gas is consensus.
What is uncertain is the regulatory environment for producing gas. While there is growing recognition that abundant gas supplies present a great opportunity for the country to rely on indigenous rather than imported energy, the debate on the environment effects of shale-gas production is not settled. Should the Environmental Protection Agency conclude that hydraulic fracturing damages the subsoil or water supply, how would producers and consumers, especially in the northeast, react? What kind of response would regulators implement and with what repercussions for production and pricing? These are open questions.
The second uncertainty about price comes from demand. For over a decade, US demand has disappointed, with 2009 consumption below 2000 levels. In the residential and commercial sectors, gas use is flat, fluctuating mostly because of the weather. There is growth in the power sector; however, this only offsets declining industrial use. But with abundant gas reserves, the gas industry and policymakers want to create demand. From natural gas vehicles, to replacing coal for power generation, gas is at the centre of a nexus of energy security, climate change and job creation policies. No matter what your concern, gas is the answer.
It is not hard, therefore, to bracket this base-case price forecast with upside risk: what if supply disappoints; what if demand pushes up prices?
If US prices are the first variable, the cost of liquefaction is the second. Here is one area where empty import terminals come in handy: by using the same storage tanks, tanker jetty and permits, companies believe they can achieve brownfield economics for their export facilities. This would be crucial given that costs for liquefaction plants remain high. Even with brownfield economics, the likely cost for a facility, assuming baseload utilisation, would range from $1.50-2.50/m Btu, perhaps even more (Cheniere, operator of Sabine Pass, says $1.50/m Btu). If the facilities are used only for part of the year (for trading only), the unit cost increases proportionally. Putting these costs on top of Henry Hub, this gas starts to look expensive.
The third variable is sales price: at what price can this gas be sold? To simplify, assume a gas contract linked to oil – although in Europe it is important also to account for UK NBP pricing. Over the past two years, a series of LNG-supply contracts have been signed at a small discount to oil parity, but most of these were signed in Asia. There are fewer data points in Europe and European companies tend to buy gas more cheaply. So a robust project would need to be competitive in Europe given its gas-pricing system, further reducing the margin between cost and price.
The outcomes differ in terms of: (a) cost of liquefaction, and; (b) the coefficient for gas pricing in Europe. In the best outcome (highest coefficient, lowest cost) LNG exported when Henry Hub is at $6/m Btu would need Brent at $60 a barrel to work; at the worst, it would need $90/b Brent. And, of course, exporters must cope with the curse of arbitrage trade – which is profitable as long as you're the only one doing it. If exports take off, gas prices in the US should rise and the coefficient in oil-linked markets should fall, making exports less attractive.
It will require a certain comfort with these variables before risking a multi-billion dollar bet on them, which begs the question: why go to the US for gas anyway?
Is the US competitive?
Now more than ever, the gas world is torn between two radically different world-views. On one hand are companies saying the world is awash in gas: they point to unconventional gas in both the US and internationally; the potential growth of Australian LNG exports; uncertain demand because of efficiency gains and renewables. They argue that the world has more gas than it knows what to do with – a view heard in Europe and in North Asia.
But there is an alternative view, which sees gas as a winning energy source in a carbon-constrained world and points out that existing and future LNG supply will be challenged just at a time when LNG markets are mushrooming all over the world. Contract prices for post-2015 deliveries are still at a small discount to oil parity and that is ample proof that this is a supply constrained world." Most international oil companies and gas producers share this world-view.
For a company that thinks "the world is awash with gas", the prospect of US shale-gas exports offers an attractive long-term source of cheap LNG supply. But for those companies, the urgency to do a deal is low – if there is so much gas, what's the rush? For those with "the world has too little gas" view, the case for going to the US is stronger. With no illusions that this gas will be cheap, a company that sees few good options for securing new supply, especially in the Atlantic basin, would be lured to the US.
PFC Energy predicts the following: at $4.50/m Btu Henry Hub, a project can be very competitive. But increase Henry Hub to $6.50/m Btu and the project becomes the world's priciest – a place to go when out of other options. So far, the companies that have signed memoranda of understanding (MOUs) for capacity at Cheniere's planned Sabine Pass export project are mostly non-traditional buyers (Gas Natural Fenosa being the exception). This suggests most European utilities – the logical buyers for US LNG – retain their hesitant approach to signing new contracts.
Can it work?
So is this going to work? One reason to be optimistic is Cheniere's sheer enthusiasm and ability to sign MOUs with potential buyers. The broader story is that US gas producers want to play the potential for oil/gas-price arbitrage. So far, they are doing this by drilling for oil, or in liquids-rich shale-gas plays; an oil-linked sales contract can serve the same purpose. There is always the question, of course, of who will bear what risk. This can complicate matters, but can be settled through negotiations.
This is far from a done deal, but with the disparities in global gas prices as they are, a few companies seem more likely than ever to place a bet on trying to bridge them. Risk free, it is not; but possible? Yes.
Nikos Tsafos is manager, upstream and gas practice, PFC Energy.