Gas shock exposes Europe’s strategic frailties
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Gas shock exposes Europe’s strategic frailties
Winter crisis eases but energy transition woes persist
How much natural gas will Europe need over the next 20 years, and from where? As the winter crisis eases, tricky questions abound. European politicians are pointing fingers at Gazprom amid surging energy poverty. The Nord Stream 2 soap opera has been sidelined by US-Russia crunch talks over Ukraine and NATO. EU climate ambition and LNG imports have never been higher. What exactly is Europe’s strategy for gas during the energy transition?
The role of gas in Europe has never been more divisive. A rancorous relationship with Russia brings a geopolitical dimension to EU efforts to marginalise the fuel to achieve rapid emissions reductions — an endeavour that is being thwarted by planned nuclear retirements and unscheduled reactor shutdowns.
The worst of the winter energy crisis seems to have passed. A flood of LNG has pushed send-out rates from European terminals to record highs, aided by milder weather in Asia. Wholesale gas and power prices have softened from recent peaks, but will remain elevated as depleted stocks are replenished. The shock is still reverberating through European capitals.
Rather than bringing clarity of thought to the EU energy debate, the ebbing gas crunch and escalating Ukraine crisis seem to have polarised it. To save face, European politicians are pivoting from antagonising Gazprom and Russia to chastising them. Until recently, their message to Moscow went along the lines of:
‘We will not sign long-term contracts with you, and stifle your ability to make long-term upstream investments’
‘We will shift to market-based hub pricing to make you compete with global LNG suppliers’
‘We will stop buying your product in the next couple of decades and this will hurt your economy’
‘We will hit you with a carbon border tax unless you figure out how to decarbonise your exports’
‘We will prevent you from operating a brand-new export pipeline even though this would reduce the use of decrepit, leaky old pipelines that belong to our friends’
Now that energy-intensive businesses are throttling output and millions of consumers are facing huge rises in winter heating bills, rhetoric towards Gazprom has shifted to:
‘Why did you not voluntarily send us extra gas when supply became tight, even though we didn’t explicitly ask for any?’
What a change of tone! Now, none of this is to say that Gazprom has not exploited the situation. With EU gas stocks running precariously low and post-Covid Asian LNG demand poised to roar back, the company saw a commercial opportunity and seized it.
Whether Gazprom’s behaviour dove-tailed with Russia’s geopolitical agenda seems irrelevant in hindsight. European buyers also colluded to inflate prices on western hubs by sending Russian gas eastwards into Poland and Ukraine. Politics was not a factor in their actions.
Besides, all of this was enabled by the EU Commission’s concerted effort in the 2010s to liberalise gas trade. Their bet that competition would lower prices for consumers paid off – until it didn’t.
Back to basics
The question of how best to meet Europe’s substantial gas demand as it declines during the transition to renewables is becoming almost too toxic for politicians to discuss. So let’s filter out the noise and focus on some fundamental trends. BP statistics and EU data tell us the following:
Europe is today by far the world’s largest gas importing region. Europe imported 326.1 billion cubic metres (Bcm) of gas in 2020. This accounted for 34% of the global total, and is about the same as China (139.1 Bcm), India (35.8 Bcm) and OECD Asia (161.7 Bcm) combined.
European domestic gas production is falling more quickly than demand. European gas demand fell -0.4% per annum since 2009 to hit 541 Bcm in 2020, but production fell -2.5% per annum to 218 Bcm over the same period.
Europe relies on imports to meet more than half of its gas demand. This is split between pipeline imports (39%) and LNG (21%).
The EU is even more dependent on imports because Norway and the UK are not member states. Less than 25% of the EU’s gas needs are currently met by domestic production. The rest is imported, mainly from Russia (31%), Norway (28%), and Algeria (5%), with the rest coming from LNG.
Europe’s growing reliance on gas imports is being met by LNG. Europe-wide LNG imports rose 5.4% per annum over 2009-19 to 115 Bcm in 2020, while pipeline imports grew by only 0.8% pa to 211 Bcm in 2020.
On the current trajectory, all else being equal, Europe’s gas import reliance could grow to as much as 70% by 2030. LNG imports could more than double by 2035, depending on the speed of energy transition.
Mind the credibility gap
Velocity will be determined by hard policy, not woolly pledges. The difference between the two is illustrated in the IEA’s World Energy Outlook 2021, which models gas demand in two scenarios: stated policies (STEPS) and announced pledges (APS):
What is striking about this chart is that, in any scenario, Europe will have to compete with Asian buyers to satisfy marginal demand. As China, India and other Asian nations wean their economies off coal there will be an almighty global struggle to secure adequate LNG volumes. BP’s 2020 Energy Outlook illustrates the coming LNG tussle this way:
The message here is that, no matter how quickly Europe reduces its gas demand, residual demand must be met in the context of competitive global LNG markets. Europe can either compete with China and others now to secure long-term supply, or compete with them later for spot cargoes to meet marginal demand when it arises.
It is either LNG by design, or LNG by default. Competing with Asia for spot cargoes is heaping pain onto European consumers. Is there perhaps a better way?
An accelerated transition might reduce Europe’s overall gas import dependence, but the volume of gas consumed is only part of the problem. Use of marginal pricing to clear gas and power markets means only a tiny proportion of gas-fired generation (to meet peripheral demand) sets the wholesale price across the grid.
Under this model, gross gas burn for power could reduce significantly but gas would still set the price if marginal generators are called upon to balance the grid for the same number of hours over the year.
On a wing and a prayer
The EU Commission is not really talking about this. Instead, it is putting out highly ambitious models showing the bloc’s entire gas demand falling below the amount of LNG that BP expects Europe to be importing by 2035:
The chart above was published with the EC’s recent gas regulatory proposal. It plots “total fossil gas” demand at roughly 210 Bcm in 2035. Under the WEO’s APS scenario, Europe will still be consuming this much gas in 2050 unless it backs up climate pledges with concrete policies. (Granted, one is for EU-only demand and the other includes non-member states, but there is still a discrepancy.)
The implied assumptions in the PRIME model’s MIX scenario above are that:
Overall EU gas demand drops very sharply on efficiency improvements and electrification
Indigenous biogas output rises sharply to offset pipeline and LNG imports
Gas distribution networks are ready to accommodate a spike in decentralised biogas production
The many thousands of farms and anaerobic digesters implied here will meet strict gas quality and safety criteria for pipeline blending
All of these things might happen, and hopefully they will. But what if they don’t? Judging by the almighty spat between European leaders over the EU’s farcical green taxonomy, the hard policies needed to replace fossil gas with biogas could be thoroughly softened along the tortuous legislative journey.
Paralysed by doubt
Demand uncertainty hampers strategic decision-making around gas procurement. Filtering long-term market signals from noise is not easy because rhetoric sets policy direction. This probably explains why there has been no rush to sign long-term LNG sales and purchase agreements (SPAs) to secure future UK/EU supplies – unlike China, which signed a flurry of deals with the US, Russia and Qatar when gas markets tightened last autumn.
If long-term supply deals are not made, Europe’s exposure to the whims of the spot market will widen, cementing the region’s role as the ‘market of last resort’ for LNG. This means higher price spikes when supplies tighten and deeper troughs when there’s a glut. It is the opposite to a hedge against volatility.
And because the UK and Europe are wedded to the concept of liberalised energy markets and marginal wholesale pricing, that volatility will be passed through very quickly to consumers. The risk of political intervention in UK/EU energy markets is becoming structural. If the ongoing winter energy crisis is anything to go by, this could become an annual phenomenon.
Not only is Europe taking an ad-hoc approach to procurement of a fuel that will (despite best transition efforts) remain of vital importance to ordinary people and their livelihoods for years to come. It is also leaving the rest of the world to determine which sources of new gas supply enter production, and those that don’t. The ‘do nothing’ approach will alter the complexion of those gas and LNG projects that get built.
No deal = no US LNG
In the absence of long-term supply deals with creditworthy offtakers, only those LNG projects that don’t need revenue certainty to secure finance will proceed. It is notable that the only project to achieve final investment decision (FID) last year was Qatar Energy’s behemoth 45 Bcm/year (33 mtpa) North Field East expansion, the single largest LNG FID ever:
The NFE project benefits from two unique characteristics: Qatar’s unrivalled access to the world’s cheapest feed gas from the North Field in the Persian Gulf, and the geopolitical importance of LNG exports to the state of Qatar.
Pre-selling LNG under long-term SPAs was not necessary to take FID. Qatar is the world’s cheapest supplier so its cargoes will always find a home in an oversupplied market – and the emirate needs the “substantial revenues” that the expansion will yield for state coffers.
Australia recently overtook Qatar as the world’s largest LNG exporter, and this year the US will take top spot. But no western LNG exporter will stay there for long unless they build new liquefaction projects, and that means tying down fickle demand in bankable long-term contracts.
Europe is the natural destination for US Gulf Coast LNG exports due to the direct route across the Atlantic (Qatari cargoes must traverse the Strait of Hormuz and the Suez Canal). But American LNG export projects can’t access debt finance without pre-selling most (~80%) of their output under binding 10/15-year SPAs with customers. Independent US LNG developers such as NextDecade and Tellurian don’t enjoy Qatari levels of state sponsorship, and struggle to compete on price.
This means potential buyers must shoulder volume and price risk. Going long on US LNG means accepting another ‘black swan’ market crash could leave them holding out-of-the-money LNG contracts, as we saw in 2020. Customers of US LNG exporter Cheniere paid $708 million to cancel an estimated 67 cargoes over April-June 2020 amid the first wave of Covid-19 lockdowns. Is this a risk worth taking for European companies? It might be, but how can they possibly know for sure?
A plea for pragmatism
For all the reasons described above, certainty is in short supply. Big commercial commitments require strategic clarity, and that is sorely missing in Europe’s energy debate.
Renewables are undeniably the future and will ultimately replace gas, aided by heat electrification and more efficient homes and industrial processes. This is to be firmly welcomed, and the sooner the better.
But until we get there, European leaders need to take a pragmatic view of the continent’s diminishing gas requirements. Then they must decide how best to meet these according to security of supply, cost, emissions and geopolitical objectives, and communicate honestly the trade-offs.
Balancing competing priorities means reconciling what is necessary during the energy transition with what is desirable. This might mean a revival of upstream gas exploration in European waters, revisiting Europe’s shale potential, or buying an appropriate amount of LNG from a transatlantic ally. If it means letting markets decide, why not inform those commercial decisions with a realistic profile of declining gas demand?
None of these options is ideal. Whatever the preferred course of action, it needs to be resolved transparently and articulated clearly. A generation of European consumers will have to live with the consequences — both good and bad.
Seb Kennedy | Energy Flux | 20 January 2022
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