Why aren’t investors scrambling to build new LNG projects?

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Energy traders make eye-watering margins by selling spot cargoes of liquefied natural gas (LNG). Extremely depleted gas storage levels in Europe are keeping LNG spot prices well above seasonal norms. Persistently high prices would indicate a structural shortage, but so far there has been no inflow of capital into new LNG production capacity. Investment cannot be made without certainty on demand, which is fraught with risks in terms of energy transition.

Anatol Feygin (left), vice-president of the American company Cheniere Energy, and CEO of the Polish oil and gas company PGNiG Piotr Wozniak (right) signing a 24-year American agreement to deliver LNG to Poland, November 2018 , Warsaw. (Photo by Janek Skarzynski/AFP via Getty Images)

What profit can be made from a single spot cargo of LNG? In October 2021, a notional trade in a US LNG cargo arriving in Asia in December would have generated a net margin of approximately $21.64 per million British thermal units (MMBtu), had it captured the Asian futures price spot LNG of $34/MMBtu. . For a standard vessel carrying 165,000 m3 of LNG, this equates to approximately $77 million in profit (after paying the cost of production and shipping through the Panama Canal).

These margins boosted US LNG production to new records towards the end of 2021, allowing the US to challenge Qatar and Australia for the title of the world’s top fuel exporter. The US Energy Information Administration expects this to happen by the end of 2022 – but how long could the United States maintain this distinction? Other new LNG export plants planned along the US Gulf are struggling to secure investment, despite the global gas crisis.

Mixed market response

A record increase in fuel demand will always prompt operating liquefaction plants to maximize production and utilize any unused production capacity. However, it alone is not enough to support commercial capital investment in new LNG export plants. This would require revenues to be secured by a binding contract that commits a buyer to take or pay for cargoes over a decade or more.

The reason is simple: risk averse lenders. Banks will not offer project financing to cover construction costs unless an LNG plant pre-sells the bulk (~80%) of its production under sale and purchase agreements (SPA) long-term with creditworthy buyers.

Making this commitment is a big ask from some gas buyers, even in today’s overheated market that is crying out for more supply. This requires demand security at a level that makes a 10- or 20-year SPA contract significantly more profitable than buying in the spot market.

Buyers on the hook for long-term LNG purchases have not forgotten how the Covid-19 crash of 2020 flooded global markets with cheap spot cargoes, leaving them to hold costly and loss-making contract volumes. A series of cargo cancellations ensued, but these came at a cost: US LNG exporter Cheniere’s customers paid $708 million between April and June 2020 to cancel around 67 LNG cargoes during this period.

How sure can buyers be that this won’t happen again or that paying occasional penalties will always be cheaper in the long run? For state-controlled entities selling to captive customers in regulated Asian markets moving away from coal, that certainty may exist, but if you are a European utility operating in liberalized wholesale gas and oil markets electricity that decarbonizes, long-term fossil fuel supply means considering a myriad of political and macroeconomic factors. Where exactly will European gas demand be after a decade of feverish climate policy-making?

Meme Stocks and Difficult Lenders

The most likely evolution of the energy transition is bullish for gas, at least in theory: gas offers a complement to renewable energies, is potentially much cleaner than coal (according to the methane footprint) and is the reference source to replace nuclear and coal. retreats. Moving away from gas for home heating, fertilizer production and energy-intensive industrial processes will take a lot of time, money and unwavering political support.

These factors have captured the imagination of retail investors, whose fervor has propelled publicly traded US LNG exporters such as Tellurian and NextDecade into meme stocks. Tellurian’s share price has rebounded from 2020 lows on hopes it can finally make a final investment decision (FID) on its flagship Driftwood LNG export project in Louisiana in the first half of 2022 .

The Tellurian fan base believes the company can find enough long-term buyers to capitalize on the debt. Driftwood has pre-sold more than half of its nameplate capacity of 16.5 million tonnes per annum (mtpa), leaving a small shortfall to meet the 80% threshold imposed by lenders. Other deals are in the works to bridge this gap, but the terms on which they are signed deserve careful scrutiny.

Commodity traders Gunvor and Vitol will buy much of Driftwood’s volumes at prices pegged to the Japan Korea Marker and the Dutch Title Transfer Facility, meaning Tellurian’s revenues will fluctuate with the Asian LNG spot price and European gas hubs. Banks do not like commodity price risk and are reluctant to lend to projects exposed to it.

The situation for NextDecade is even more difficult. The company’s 11 mtpa Rio Grande LNG project in Texas has pre-sold just 2 mtpa to oil major Shell, leaving a big shortfall to satisfy lenders. Tellurian and NextDecade have repeatedly missed FID target dates for their respective projects. They will only progress if the promise of strong LNG demand is anchored in watertight contracts that reduce risk to make them bankable.

Fundamental uncertainty

“Going long on LNG” means betting against another black swan event that weighs on the global economy and energy demand. Substantial commitment also requires guarantees that not all utility buyers are willing or able to provide – and politics cannot be ignored either. Any commitment to lock in 10-20 years of fractured shale LNG in the United States would be an affront to the stated ambitions of some EU countries to marginalize the transitional role of gas in Europe.

NextDecade found this out to its detriment in late 2020 when semi-state-owned French energy company Engie pulled out of a tentative deal to buy LNG from Rio Grande. This reportedly followed the intervention of French government officials appalled by the methane and flaring footprint of the shale fields that would power the project. Engie has since signed a smaller deal with rival exporter Cheniere that has flown under the radar, while NextDecade has been scrambling to reinvent itself as the “world’s greenest LNG” supplier.

Some buyers enter into new LNG sales agreements. Since global gas markets tightened in the third quarter of 2021, Chinese companies have signed SPAs for a total of 8.8 mtpy (over different contract lengths) with LNG exporters in the United States, Qatar and in Russia. This equates to approximately 13% of China’s total LNG imports in 2020; however, China alone cannot guarantee a new wave of investment in LNG infrastructure sufficient to meet the growing global demand for gas.

Decarbonisation and efficiency will cause European gas demand to fall by 3% to 495 billion cubic meters per year over the period 2020-2040, according to oil major Shell. However, domestic production is falling faster, meaning the region’s reliance on LNG could increase by 7% to 84 mtpy over the same period. Unless this additional supply is secured by long-term contracts, Europe will be increasingly exposed to the vagaries of the spot market to satisfy marginal demand.

Even if pragmatism prevails and European companies go on a LNG buying spree, it takes 3-5 years to build a new LNG plant after taking an FID. That makes nice winter spot margins now seem like a bankable certainty for the rest of this decade. The problem for most projects vying for investment, however, is that banks don’t see it that way.

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