The great LNG market showdown
Sellers say a supply crunch is looming. Buyers say suppliers are out of touch with the changing times
Nestled within some of Tokyo's most famous parks, Japan's iconic cherry blossoms are in full bloom, signaling the start of a new season. The flowers are symbols of transience in Japan, and while that may not apply exactly to the global gas glut, suppliers have a message for buyers: the good times are coming to an end.
"With supply short-term being abundant it's very understandable that buyers don't want to look beyond, but they need to look over the crest of the hill," Peter Coleman, Woodside Energy's chief executive, told the 29th Gastech conference in Chiba Prefecture, on Tokyo's eastern outskirts. "And it's clear that a supply shortage looms unless investment decisions are taken soon."
Such a warning may seem laughable to liquefied natural gas buyers enjoying a market characterised by sheer abundance. This year global liquefaction capacity is expected to reach 408m tonnes, says Energy Aspects, a consultancy—a 70m-tonne increase from 2015. But LNG imports (the closest proxy for demand) will be just 261.2m tonnes, a rise of just 15m from 2015.
Much of this new capacity will come from Australia, which could overtake Qatar's 77m tonnes a year of supply to be become the world's largest exporter. A few years behind will come the US—its capacity will more than double this year, to 25m t/y, and reach 65m t/y by the end of the decade.
Inevitably, LNG prices have been under pressure.
LNG landed in Japan, for example, will sell for about $5.50 per million British thermal units this year, reckons Energy Aspects, before dropping to around $4.20/m Btu in 2018. Just two years ago, an exporter could expect to sell a cargo in Asia for almost $16/m Btu.
But the cure for low prices, say producers, is low prices. The weak market now has pushed capital investment in costly new projects off a precipice. That means one thing, says hopeful exporters—an inevitable supply dearth that will force prices higher.
"The current conditions are not favourable to major greenfield developments," Coleman says, citing a hosts of risks discouraging investment, from geopolitics and policy, to climate change measures, taxation, changes in contract terms and rising funding costs. "The result is that only small volumes have gone to final investment decision (FID) in 2016. And 2017 looks set to be another challenging year."
That, say LNG boosters, is exactly where the opportunity is. Charif Souki, the former head of US LNG exporter Cheniere Energy who is now running Tellurian Investments, which wants to build more American export capacity, says the dearth of new projects means the global market will be soon be short 100m t/y of capacity needed to meet demand. It's the basis of his bullish take on the market.
LNG buyers aren't convinced. They think the fundamentals are in their favour - and are glad to see the back of contract terms that used to favour exporters, like decades-long contracts pegged to oil prices (often with destination clauses preventing them from selling on excess gas). Producers need to be more flexible now that power lies with a new breed of importer, they say.
"Particularly conservative sellers say we need long-term contracts and a lack of investment will create a shortage of supply and buyers need to be aware of that. But it's the market that will drive the changes," Sam Muraki, executive advisor at Tokyo Gas, tells Petroleum Economist. "Probably they are thinking about traditional buyers, like utility companies. But for new markets like southeast Asia, the Middle East, India or in LNG bunkering—who is going to take long-term contracts?" His advice for exporters? "They have to change their mindset."
Not that Muraki is gloomy about LNG. He expects the global trade in seaborne gas to exceed that by pipeline by 2040—but alongside the shift will come a slow but steady move away from long-term oil-indexed contracts to spot-trading models. Asia will be at the forefront of the new market dynamics.
For now, long-term LNG sales contracts—which today comprise around two-thirds of the trade—will be the mainstay. But over time, the power of the long-term deal will wane as more and more deals are done on a spot basis.
"The large suppliers with a large portfolio, like Shell and ExxonMobil—they will be more flexible. But Woodside? They don't have a portfolio," Muraki said. "They only have projects in Australia and very expensive construction costs. Woodside doesn't represent all the sellers (in the market)."
Buyers are clubbing together to reinforce their power, too. In March, South Korea's Kogas, Japan's Jera and China's Cnooc formed an alliance to buy LNG and pressure producers to restrictive contract terms, such as destination clauses. The group has some clout, buying about a third of the world's LNG.
Regional demand surge
One positive for exporters is that the market for LNG is widening. Japan and South Korea once accounted for about 70% of global LNG demand, but buyers in India, China, Bangladesh, Vietnam and the Philippines offer new—often more dynamic—growth centres. Helping them along is the rising uptake of floating, storage and regasification units (FSRUs). "Regasification technology has allowed new countries to enter the market and imports into countries using FSRUs is growing," Coleman says.
Between 2012 and 2016, LNG demand from FSRUs trebled to 30m t/y. Indonesia, Pakistan, Argentina, Brazil, Egypt and Jordan are among the countries turning to the new floating technology. "FSRUs are simply a game changer for our industry. Emerging markets now account for 5% of global LNG demand and that's expected to grow to around 27% by 2025," Coleman says.
And with that new source of demand in mind, he has some advice for importers. "It's time for buyers to engage again in recognition that this time of abundance will not last. Those who move first will get access to the most promising projects offering the most eligible supplies. The changes occurring in the market now mean there will be competition for those supplies very soon."
That might depend on Japan. Its LNG demand fell by around 2% last year, to 83m tonnes, as some nuclear capacity coming back online. Around 12 of the country's nuclear plants have applied to restart, and if they get the go-ahead LNG consumption will fall by 70m t/y by 2020, predicts Wood Mackenzie, a consultancy.
So the market may need to digest a lot of LNG before supply and demand start tightening. "Japan alone consumes more LNG than the entire Atlantic basin," notes Kerry Anne Shanks, an analyst at Wood Mackenzie. "If its nuclear restart programme is successful we may see a situation where you haven't got this reliable customer, which could create some price volatility".
Others are more bullish. Tokyo Gas's Muraki says political opposition to nuclear power will hinder the restart, allowing gas to hold onto its market share. He adds: "There is a new type of buyer coming into Japan's fully liberalised gas market: large commercial, industrial customers who can come to the market and can directly buy LNG." They provide a new, overlooked, source of competition for gas—and they'll help drive the trend toward spot trading and greater liquidity in Asia's LNG market.
Asia's eyes on the Atlantic
And, in the mood for flexible and cheap gas, these new buyers are looking to North America for their cargoes.
"The new president of the US is a big disrupter but his administration will promote exploration and exports of gas and oil, as well as infrastructure development," says Muraki. "They have some pipeline bottlenecks but if they can build some (new pipelines) between the northeast and the Gulf then transportation costs will be reduced and US natural gas will become even more cost competitive—as long as they have reserves."
For Muraki, the US' growing LNG exports offers buyers the chance to help develop a new, highly fungible and transparent industry. And he gives short shrift to producers like Woodside, whose boss Coleman says today's weak LNG prices offer no incentive to invest. US producers seem ready to invest, Muraki points out. "Sellers have to innovate to reduce the cost of projects." "The Qatari model"—long-term contracts for high-priced gas—is also no longer relevant," he says. Only if Henry Hub prices reached $7-8/m Btu, or more than double their level now, would the shine come off the idea of US LNG imports in Asia.
And that's not going to happen, says Tellurian's Souki, who thinks US gas will sell for $3/m Btu for the next two decades. "At the moment, in the northeast US there is 20bn cubic feet per day of production that is mostly constrained by infrastructure and that is available at the wellhead at $1/m Btu or less."
Souki told the Gastech conference he would consider offering LNG from Tellurian's proposed Driftwood project on a five-year fixed price deal at around $7-8/m Btu. The first train from the project, which has not yet been approved, is scheduled to come online in 2022.
Once operational in 2025, the five-train project would have capacity to export 26m t/y of LNG from a terminal on the Calcasieu River, south of Lake Charles in Louisiana.
By then, the dust might have settled on today's collision between buyers and sellers. "At the moment we don't have a business model in the industry because we can't get anyone to agree," Souki says. "If buyers are counting on the spot market, well we haven't invented the business model yet."
Souki told Petroleum Economist Tellurian certainly wouldn't be indexing its LNG against oil ("I don't understand the concept of pegging one commodity against the price of another"), but would sell most of it under term, not spot, contracts.
And he's optimistic that the glut will soon pass. "These very low prices are stimulating demand. You can be oversupplied on a 12-month basis but that doesn't mean that in winter when everyone needs gas that you're actually oversupplied," Souki says. "I'm reasonably certain that all the excess gas will have been absorbed by the end of the decade and we'll be in another price crisis and all the buyers will be complaining."
Japan isn't the only big player that might have a say in that.
On 3 April, Qatar, still the world's biggest LNG exporter, said it would end its self-imposed moratorium on development of the North Field. The move—a surprise to many in the market—carried a few messages. One was that Qatar would not stand by while Iran developed its own gas business across the maritime border, at South Pars (the Iranian name for the North Field it shares with Qatar). Another signal was sent in the direction of Australia, and suggested Qatar isn't ready yet to surrender its title as the world's pre-eminent LNG exporter.
But the bigger meaning of the North Field reopening will be understood across the LNG industry. If a dearth in supply is to emerge in the coming years, Qatar will be ready to help fill it, and fight for its share of the market. And in a world of abundant supply, the low-cost producer will be king.
Source: Energy Aspects