Total plots a rich LNG future as expectations run high
The French major is aggressively expanding its LNG portfolio. Philippe Sauquet, chief executive of the company's gas and power division, talks to Petroleum Economist
Liquefaction costs are rising, the US has disappeared as an import market, European demand is shrinking, China wants to tap vast domestic unconventional reserves, and consumers in Asia are wondering why, when there's so much gas around, they are paying four times as much for it as buyers in North America.
Talk to Total if any of this makes you nervous about liquefied natural gas' (LNG) future. The company's bullish enthusiasm is infectious. It's been in LNG since the 1960s, when Algeria became the world's first major shipper of frozen gas and France its first major market. Now it vies with ExxonMobil and BP to be the second largest exporter of LNG among the majors (Shell is the biggest). It wants its liquefaction capacity to hit 20 million tonnes a year (t/y) by 2020 and has a string of projects in the pipeline.
"We are convinced that LNG (demand) growth will continue,- says Philippe Sauquet, head of Total's gas and power division. Consumption will rise more quickly than for gas in general, he says, and Asia will dominate this. It is a position Total has maintained for years. Previously, it said consumption of LNG in China had been hindered by insufficient regasification capacity, leaving pent-up demand that would be satisfied when more receiving terminals came on line. (China has five operating receiving terminals and another 16 have been proposed.) That judgement has been sound. China's imports of LNG in 2010 were 12.8 billion cubic metres (cm), according to the Economist Intelligence Unit.
Three more terminals have since come on line and last year imports reached 19.1bn cm and should grow to almost 24bn cm in 2014. The International Energy Agency expects China's total gas demand to rise from 130bn cm in 2010 to over 300bn cm in 2020 and 545bn cm in 2035.
China hopes its unconventional gas reserves, thought to be among the largest in the world, will satisfy some of this demand. Sauquet isn't so sure. Chinese shale gas could be a potential threat to LNG, he admits. But development "should be slower than some official objectives". Plenty more LNG will be needed, especially in the coastal cities, whatever happens in China's upstream.
Sauquet sees Asia bursting with other opportunities for LNG exporters. India's arrival as an importer may be tardier than China's, but is an area of "great hope" for Total.
As for Japan, the world's biggest importer, Total expects demand for LNG there to remain high, despite plans to refire some nuclear reactors that were shut down following the Fukushima accident. "You could take a case where nuclear would restart in one or two years time and we'd see a reduction (in LNG demand)," says Sauquet. "Not in our view."
High levels of Japanese LNG demand, which rose by about 40% to 87m t/y after the disaster, are "there for the long term," he says.
He's even hopeful about Europe, where gas consumption has been stagnating since the financial crisis. "It's not easy to build a case for a sharp increase of demand," says Sauquet. But the combination of declining European gas production and the EU's climate-change objectives should eventually support a recovery. European buyers, though, will need to compete for these cargoes with Asian consumers, he says. And prices in Asia have been on a flyer in recent years (See Figure 1).
Consumers blame this on oil-indexation, the system that prices LNG using a formula based on crude prices. Some analysts - and many buyers - think the method is past its sell-by date. It's not always clear to consumers in Asia why LNG imports might cost them around $16 per million British thermal units (Btu) when gas can be bought in the more liquid US market, where oil-indexation does not influence the price, for around $4/m Btu.
This is the wrong problem, according to Sauquet. Yes, there has been a trauma among some Asian governments, he admits, but in the absence of another proxy on which to base LNG prices in Asia oil-indexation remains the best alternative.
"We tend to favour oil indexation in Total, not because we think it will give us higher prices in the future - it could even be the opposite - but because it is an index more representative of the supply-demand balance of countries like Japan and China."
Notwithstanding oil's exposure to the supply-side political risks, it tends to give a good barometer of the global economy's health, Sauquet suggests.
The rise of US LNG exports will have an impact on this. Liquefaction projects there hope to capitalise on cheap Henry Hub prices to seize the arbitrate potential offered in Asia.
Cost-plus sales contracts could rival oil-indexed ones. Shigeru Muraki, head of Tokyo Gas, one of the world's largest importers of LNG, told the LNG 17 conference in Houston last month that oil-linked prices for gas in Asia were no longer "rational" given the cheaper supplies from the US. He reckons Henry Hub-linked prices could fetch $10-11/m Btu in Asia, well beneath recent prices his company has paid. East African LNG and Russian piped gas would be cheaper, too.
But Sauquet says these US contracts will carry risks. Cost-plus contracts may look cheap now, "but imagine if there is a ban in some area of the US of shale-gas production or there is a boom (there) in gas demand compared with expectations".
Asian buyers could find themselves locked into the most expensive prices in the world, he says. The US government has also not decided yet how much gas it will allow for export. Nonetheless, Total has itself contracted to buy Henry Hub-linked gas, signing a contract with Cheniere Energy in December to take 2m t/y from one of the trains being built at Sabine Pass, on the Gulf Coast.
This unfolding debate over LNG pricing will matter for Total in the coming years because the company is pursuing a "very aggressive" strategy to increase its LNG production capacity (See Table 1). It is a crucial business for Total. Its nearest rival among the majors, in terms of oil-equivalent production, refining and output-growth guidance, is Chevron. But Total's upstream portfolio relies far more on LNG than Chevron's (15% compared with 6%, according to Bernstein, an investment firm).
Total's equity output from nine plants is around 12.1m t/y according to Petroleum Economist. Angola LNG should be on line soon, adding more. That project could be something of a bellwether for the industry - and for buyers' enthusiasm for spot cargoes.
The project was designed to cope with excess gas that would otherwise have been flared, giving it a logic regardless of the market conditions. But it was also conceived as a supplier to the US. Now its output will be sold on the spot market, though Sauquet says mid- or long-term contracts could be incorporated into the export regime. Two other major LNG projects in which Total is involved - the Shtokman in the Barents Sea, with Gazprom, Yamal LNG, with Novatek - pose bigger tests. Shtokman, like Angola LNG, was also supposed to send LNG to North America.
Now, says Sauquet, its target will most likely be Asia, although "some of the energy could also be for Europe". Some analysts believe another partner will join Shtokman to help push the project forward. Shell and Statoil, which pulled out of the development last year, are said to be candidates. Sauquet says this is not the priority.
"Both companies have the necessary expertise. The urgency is to have a good dialogue between Gazprom and Total on the technical scheme."
Yamal LNG is also being developed with Asia in mind, although Total is also trying to market some of its future gas in Europe. If Asia is the destination for the bulk of it, the gas will be competitive with other export projects, such as those in Australia, says Sauquet.
"When you are in Yamal, the gasfield is below the liquefaction plant, below the harbour," he says. That will make production costs cheaper than elsewhere, even if the shipping costs are more expensive.
The project will use ice-breakers to ship the gas from offshore northwest Siberia into Europe on onwards; or, when summer opens the passage, through the North Sea Route to Asia.
But Yamal LNG will also depend on the Russian government, which must decide whether Novatek can break Gazprom's monopoly on international gas exports. Exports from Yamal LNG could begin in 2016.
Other developments will also take Total closer to its 2020 target. The Gladstone LNG project will be on stream in 2015 and another Australian one, Ichthys, in 2016. Greenfield projects are being considered, among them one in Cyprus, where Total took an upstream position with an eye on future exports. West Africa is another possibility, says Sauquet.
A seventh train could be added to Nigeria LNG, for example, or Brass could be expanded. Sauquet says Total is in "advanced discussions" about other projects around the world, though they remain confidential.
The company must also keep one of its older plants, the Bontang facility in Indonesia, on line. It is running out of feedstock gas. Sauquet says Total needs a renewal of its licence at the Mahakam field, which expires in 2017, so it can keep supplies to the LNG plant ticking over. "We want to take advantage of Bontang for as long as possible, to stop the decline or at least minimise it." Talks with the government are underway.
"It's not always an easy discussion because 2017 seems a long time away for a government but for investments in oil and gas that are going to pay off much beyond 2020 we need visibility on the future."