The Conundrum for Buyers Sourcing Competitive Gas
THE EDGE – SIMON FLOWERS
Global gas and LN
But in the current febrile environment, how do the buyers serving the European market – utilities and traders – make the critical decisions to secure gas at competitive prices for the medium term? Wood Mackenzie’s Massimo Di-Odoardo, Head of Gas Analysis, and Giles Farrer, Head of LNG Assets, shared their thoughts.
First, the number of players able to produce LNG at scale is shrinking. Qatar is one. The North Field East expansion project, currently under development and sanctioned before the crisis, will cement its place as a global leader.
TotalEnergies is to be Qatar Energy’s first partner in the project; a handful of other leading IOCs will be invited to join in short order.
North Field East is a giant. The largest single LNG project in the industry’s 60-year history will deliver 32 mmtpa in four years’ time and cost US$30 billion. All-in unit costs, though, will be among the lowest in the market, as will be the carbon intensity – utilising solar and CCS is part of the project spec.
These LNG cargoes will be competitive on costs and green credentials for the next 30 years. Crucially, much of the LNG has yet to be sold.
But changing investor appetite means that North Field East (and its yet-to-be-developed sister, North Field South) could be among the last of a kind. The project economics are exceptional. In contrast, most capital-intensive conventional LNG developments, many of which have delivered modest through-cycle returns in the past and have lengthy paybacks, just don’t do it for Big Oil anymore.
The wider industry is moving to a more phased, modular approach to investment (including smaller-scale modular FLNG) that puts less capital at risk. US developers, able to tap the vast shale resource without committing to upstream investment, are in pole position to benefit.
As a result, Qatar and the US are poised to dominate future LNG supply. There’s currently a Big 3 – Australia, US and Qatar – but the competition at scale is falling away. Australia is struggling to maintain its production, let alone grow.
Russia’s aspiration to make it into the ‘Big 4’ has turned to dust with the war, while Mozambique’s hopes to be a major force are on indefinite hold after the terrorist insurgency underway since 2019.
The combined global market share of Qatar and the US will be 50% by 2030, up from 39% today. Qatar and the US aim to deliver 127 mmtpa of additional LNG by the end of the decade, capturing 71% of demand growth. New buyers should be concerned about such control in the hands of so few and need to consider how best to support the development of other options.
Second, securing gas at an appropriate price for the medium term is a priority for LNG buyers but a conundrum in the current market. Changes to EU regulation last decade required domestic consumer markets to be priced on spot indices.
That forced European buyers to renegotiate legacy oil-linked contracts to spot (TTF) contracts. It worked well in derisking their wholesale business. Ample supply, including Russian piped gas, kept spot prices low and below Henry Hub-linked and oil-linked contract prices.
The war has blown the regulated construct to bits. Spot prices are now the highest of the three – current spot TTF is US$30/mmbtu, almost four times the average of the last 10 years (and equivalent to US$175/bbl Brent). Buyers will now be weighing up cheaper alternatives.
US Henry Hub-linked cargoes could be delivered into Europe for around US$14/mmbtu, well below TTF spot, even at today’s elevated Henry Hub price (US$8/mmbtu). The problem is that US LNG capacity is already sold out and Henry Hub-priced contracts are only available from pre-FID projects.
Most additional US volumes from projects either recently sanctioned or about to be won’t be available to buyers until 2025/26, and to access these volumes buyers will need to lock into at least 15-year contracts.
In this sellers’ market, oil-linked LNG contracts are getting more expensive by the day. The going rate for a contract starting this year is about US$20/mmbtu at today’s Brent price of US$120/bbl. That reflects 17% indexation to Brent, 50% higher than the 11% cited in contracts signed a year ago.
German utilities looking to buy volumes from Qatar may have to bite the bullet and lock into 10-year contracts at prices more than 50% higher than last year even before the rise in oil price is taken into account. Needs must.
Third, if the era of cheap gas is over, how do buyers derisk for the future? With energy policy in Europe moving away from gas in the medium term, governments may have to step in to back the longer-duration contracts demanded by sellers.
If European players aren’t prepared to build a global position in LNG to create new outlets for their volumes, the alternative is to let portfolio players take the risk.
Super-high prices won’t last forever. Our view is that spot LNG prices ease when new supply comes onstream in 2026/27. Uncertainties include how Russia behaves, and timing. The longer high prices persist, the greater the chances of an LNG bubble with too much new supply released at once.
A collapse in spot prices would put Henry Hub and oil-linked contracts out of the money. Ultimately, that’s what worries buyers – shifting out of expensive spot exposure today and being whiplashed when the market reverses.
Buyers need to build a low-risk portfolio that’s competitive on price. That’s a tough ask in a world in which prices are elevated and there’s wide divergence between Henry Hub, oil-linked contracts and spot.
On pricing, company contracting strategies need to go back to basics. Utilities and traders will get back to portfolios balanced across Henry Hub and oil-linked contracts and with less spot. When there’s no clear winner, a diversified portfolio is the safest bet.