It Is a Good Year To Be Selling LNG
Tight gas supplies, and uncertain Russian gas supplies mean sky-high prices for LNG suppliers now and a chance to lock in attractive contracts long term. But this opportunity won’t last forever.
Natural gas supply worries and elevated prices in Europe this winter could have lingering benefits for LNG suppliers and oil companies considering the development of oil fields in Europe, according to predictions from Wood Mackenzie.
There is a lot of overlap in predictions of changes ahead for Europe and the world because dwindling gas in storage there has been the big driver for higher gas prices this winter. The overshadowing variable is the uncertain future of the Nord Stream 2 pipeline, whose future is tangled up with fears of armed conflict between Russian and Ukraine.
The outlook offered a range of near-term scenarios, from lower prices if there is normal winter weather and clarity regarding when gas will flow through Nord Stream 2, to much higher prices if it is colder and the pipeline startup remains uncertain.
For now, the reality is somewhere in between those extremes. Nord Stream 2’s start date remains up in the air, but the gas supply situation is better, if not actually secure.
“In Europe, an inundation of more than 10 million tons of LNG across December and month-to-date in January has helped calm TTF prices [the benchmark gas] down to around $26/MMBtu,” said Rystad, in its weekly European gas outlook.
But even when winter ends, the gas supply problems in Europe will remain.
Prices there are nearly six times higher than the US benchmark because of “storage levels languishing at 53% of capacity,” as well as decreased supplies of gas flowing from Russia, the Rystad report said.
Europe will need to more than refill its gas reserves, which were low going into the winter and could be empty by the end of it.
“Cold weather in Europe could exacerbate the situation further, adding up to 10 Bcm to gas demand through the rest of the winter, pushing storage levels to zero unless more Russian gas is supplied,” said Kateryna Filippenko, principal analyst, European gas research.
She advised against assuming a big increase in Russian gas supplies anytime soon because the Nord Stream 2 startup could be delayed past the first quarter of this year. That delay will increase the leverage of LNG suppliers in a market also supported by continued strong Asian demand.
“2021 saw the return of contracting activity to its highest levels over the last five years. Asia accounted for 85% of global contracts signed, with China leading the pack,” said Valery Chow, vice president and head of APAC for Wood Mac.
Europeans eager to buy large supplies of gas in a seller’s market will likely lead to longer-term contracts that will command a premium price over the next 3 years. Wood Mac said increased supplies from Qatar and Russia will limit prices.
More long-term deals are expected to speed project approvals. Over the next 2 years, the report predicts final investment decisions on LNG projects totaling 79 mtpa, split among the US, Russia, and Qatar, with more possible.
This year’s surge in LNG spot prices could also reverse the long-term trend away from contracts indexed to the price of oil. Those deals had been fading because oil prices were far higher than gas prices. But this winter’s price surge was a reminder of the risk in betting on spot prices.
LNG suppliers will be competing with Russian pipelines as 49 Bcm worth of European gas purchase contracts expire this year, Wood Mac said. More than 40% of that volume has been supplied by Russian pipelines.
The supply shortages may also force European energy regulators who have focused on the energy transition to pay more attention to promoting local hydrocarbon energy production
“Some operators may see this time as ‘now or never’ for their projects, particularly inspired by the possibility of high prices,” said Conner McKinney, a Wood Mackenzie European gas research associate
Norway, which approved tax incentives to encourage more field development, could see final investment decisions on King Lear, Asterix, Dvalin North, and Linnorm projects, he said. Permitting could also allow changes that will increase production from Troll and Oseberg, and some operators may choose to sell gas rather than reinject it.
The report said this trend may extend to the UK and Romania, where development of the Neptun Deep field in the Black Sea could produce 6 Bcm of gas a year. The development, which would make the country an energy exporter, has been stalled by unresolved financial and regulatory disputes with the Romanian government.
There is a downside to higher prices; users begin looking for lower-cost substitutes.
“Despite strong economic growth in Europe, gas demand in industry and power is down 4% since the summer, compared to the past five years,” Wood Mac said.
In Asia, however, demand for LNG continues to rise because “most supply is priced at legacy oil-indexed contracts, currently trading at half the value of Asian LNG spot prices.”
As oil prices have risen, so has the price of gas in oil-indexed LNG contracts, which will eventually reduce the incentive of coal users to switch to gas.
All of which are a reminder that hydrocarbons remain an important energy source, but that doesn’t mean the industry will stop feeling pressure to quickly reduce carbon emissions.
One of last year’s trends was the rise of carbon-offset LNG—with 28 cargos announced, which Wood Mac said was a fivefold increase from the previous year.
This year, Wood Mac said the trend will be to establish that the emissions offsets claimed by sellers represented actual reductions.
Initially, the focus for producers has been on lowering flaring, venting, and methane leaks. For LNG producers, it has been buying gas certified by third parties as “low emissions.” Now, more expensive options, such as carbon capture and storage or low-carbon power are under consideration.
The report concluded that “a suitable global carbon price associated with the energy trade might be required for substantial investments to be spent in reducing Scope 1 and 2 emissions [from operations and purchased energy]—and that is still a few years off.”