LNG gluts and cycles
Structural oversupply is about to hit the market and some projects will have to curtail output to cope. But buyers and developers must take a longer-term view
What a ride. Since liquefied natural gas (LNG) hit giddy highs a few years back, prices have collapsed from the high teens to levels around $5 to $6 per million British thermal units. This has been driven by low oil prices, rather than an oversupply of LNG.
But now comes an era of structural LNG oversupply, which will see spot prices remain depressed through to early next decade, even if oil prices rise. Established LNG producers and buyers, as well as new industry entrants, are having to adapt to the largest, steepest, most prolonged drop in prices the LNG industry has ever faced.
Plenty of LNG capacity, now under construction, is about to come online without demand to meet it. Global LNG supply availability will rise by more than 160bn cubic metres a year between 2016 and 2020, while LNG demand outside Europe will increase by just half that. This will leave around 80 bn cm/y of supply looking for a home in the market of last resort: Europe. But this LNG will have to compete with pipeline gas from Russia, Norway and Algeria.
Wood Mackenzie does not believe there will be enough demand to soak up the available supply. As a result, LNG output will have to be curtailed.
This will happen where the short-run marginal cost is highest: US LNG projects and the coal-seam gas (CSG, otherwise known as coal-bed methane) fed projects on Australia's east coast. These projects have to spend big dollars each year to maintain feedstock to keep their plants full, and are most affected by low prices. US LNG capacity will feel the brunt of the curtailment, and Australian CSG LNG will also reduce output, as LNG prices won't cover short-term production costs. It is a brave new world for the LNG industry. For the first time in its history, brand-new LNG plants are being deliberately run below capacity on an economic basis. We are already seeing Australian CSG LNG projects running well below capacity.
Yet more supply is on the way too. Qatar recently announced an expansion of its
LNG output, which could add an extra 20m tonnes a year to the market by 2025. And there are gas pipelines planned and underway to deliver gas from Central Asia and Russia into China, which could eat away at LNG's market share in the world's largest growing market for seaborne gas. But in context, Qatar's expansion would only push back market rebalancing by around a year. And LNG fares competitively against the economics of piped gas to China's key coastal demand areas, which will hinder pipeline gas penetration for the time being.
80 bn cm/y - Size of LNG oversupply, 2016-2020
With US LNG capacity lying idle, US gas prices will begin driving global spot LNG prices for the first time. It means the level of M&A activity in an oil basin like the Permian in the US, for example, will have repercussions for electricity prices in India or Australia.
Over the next few years, this will place increasing tension on legacy LNG contracts, which were signed during the boom years at higher oil-linked prices, while US LNG cash costs, and therefore LNG spot prices, remain low. Buyers are reluctant to sign up to new gas contracts under the terms and prices used in the past, and LNG contracts are becoming shorter, smaller in size and more flexible to meet the new market appetite. Many gas buyers in Asia will look to optimise their contracted position, as operational demand becomes increasingly uncertain and some have more gas than they need. For producers, and even some buyers, being a "portfolio player" is the new buzz term in LNG marketing. In a depressed market, being able to optimise trading and shipping can make all the difference. And the ability to offer flexibility to buyers that a portfolio provides can be a differentiator in marketing efforts. Traders—the likes of
Gunvor, Trafigura and Glencore—didn't exist in the LNG market five years ago. Today they account for an increasingly material portion of the short-term and spot market, and are being welcomed by some producers for helping open up markets and manage counter-party risk. New entrants and rising liquidity are creating a new reality for LNG markets. But things can change
If buyers continue to refrain from signing long-term LNG contracts, then the next phase of global LNG investment is at risk. When the LNG market rebalances and tightens towards the mid-2020s, the supply needed then might not exist, raising the risk of a price spike. Already positive market signals suggest that demand may tick up earlier than expected. Chinese demand is looking better, South Korea's new president is reining in the use of coal in favour of gas, and India and Pakistan remain gas hungry. New markets enabled by floating storage and regasification units collectively now rank as the third-largest LNG market after Japan and South Korea. And new markets for gas in heavy transport and bunkering provide further upside demand potential.
Around 10 new LNG trains could be needed by 2025 once the market has rebalanced. But there will be several supply sources chasing this market share and cost will be king. The high-cost greenfield projects of the recent boom will remain little more than ideas on paper.
Qatar's geographic location puts it in a strong position to advance volumes given the country's low costs. More volume can be added cheaply by turning up the trains to full utilisation and by debottlenecking. However, timing may depend on
Qatar Petroleum's negotiations with its IOC partners and developments in the wider market.
Industry has focused on cutting costs, with declines evident across the board for new projects compared with recent years. The LNG cost curve has become progressively lower and longer since 2014. There is little to choose, Wood Mackenzie believes, between the breakeven cost of delivering new LNG from East Africa, the US, West African floating LNG and Arctic Russia into North Asia. All can potentially deliver LNG in the $7.50-8.50/mBtu range. Long-term prices after 2023 will need to rise to reflect the cost of this new supply that will be needed to satisfy demand. And if buyers are not willing to sign long-term sales and purchase agreements (SPAs) in time, some projects will not achieve the financing needed to proceed.
Aside from Qatar, expansion of Papua New Guinea LNG will be a prime candidate for sanction, alongside a second modest wave of US LNG. Backfill of Australia's legacy LNG plants—finding new gas to replace declining fields—is also likely. The elephant in the room will be onshore Mozambique. With a huge resource base, Mozambique could displace a lot of competing volumes. The first two Mozambique trains would be more expensive, having to cover greenfield site works and infrastructure. But once the trigger is pulled, the next set of trains would be cheaper. And there is enough gas for more than 10 trains.
ExxonMobil's recent entry into the project is a strong sign of confidence in its viability, although the timeline remains uncertain. Swings and roundabouts
Buyers will take advantage of the glut to improve their position. But behaviour by buyers during the glut may well come back to bite them in future.
Japan's Free Trade Commission (JFTC) recently stated that clauses in free-on-board (or FOB) LNG SPAs that restrict resale of LNG are likely to be anticompetitive. This move may well provide buyers with greater leverage to negotiate more favourable terms during a glut. But when the market tightens, a prohibition on destination-restriction clauses (or clauses allowing profit sharing for cargo diversions), may result in LNG sellers becoming less amenable to providing volume flexibility in their contracts, in case it provides buyers with free options to arbitrage with the spot market. This will leave buyers with a greater burden to manage their variability in operational requirements. Similarly, any buyer threats to renegotiate existing contracts now will impede their ability to underpin new supply projects when they need to in the future.
For those with the financial capability, current conditions may provide favourable opportunities. Buyers may pursue upstream integration and M&A, at steep discounts to valuations during the boom, while producers rationalise and streamline their portfolios. Meanwhile, LNG project proponents able to take bold countercyclical final investment decisions will be able to take advantage of current low construction costs, starting up projects just as prices are forecast to recover. Producers will also have to decide whether to increase their marketing sophistication, or let it take a back seat while they focus on project operations, leaving marketing to traders and portfolio players who can extract more value out of a cargo.
Ultimately, when the market rebalances, prices will have to rise again to bring on new supply. Indeed, prices may well spike if sufficient supply hasn't materialised in time, and the cyclical nature of the industry will prove itself again. The LNG market has seen numerous periods of alternating buyer and seller favoured conditions over the last 20 years, through the Asian financial crisis in 1997, the global financial crisis in 2007, the Fukushima tragedy in 2011, and so on. But LNG projects typically live for more than 30 years. They ride out the cycles.
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