There are many underlying causes behind the current gas supply crisis unfolding in Europe. A “V” shaped market has seen global gas demand surge on the back of the post-coronavirus (COVID-19) economic recovery, driven by growth in LNG imports in China and other Asian markets. Gas producers have been slow to ramp up output in response, while Russia’s Gazprom has faced criticism for keeping some supply back – whether simply to drive up prices or to put pressure on European regulators to clear the way for the launch of the controversial Nord Stream 2 gas pipeline.
However, there is another factor that many EU politicians are keen to dismiss as a cause: years of underinvestment in domestic gas supply. Gas production in Europe has been falling for decades. In 2020, European output excluding contributions from Russia and other CIS states amounted to just 218.6bn cubic metres, according to BP’s statistical review, down nearly 30% from the level in 2010.
Gas production in the EU between 1970 and 2019 (millions of cubic metres)
Demand for gas has spiked this year as the business has been hit by a multiple whammy: Europe began 2021 with low storage levels after the collapse in demand and prices in 2020; LNG has been largely drawn off to Asia by even higher prices; the demand rebound caused by a recovery from the coronacrisis was far stronger than anyone anticipated; and Russia’s Gazprom is running up against its production and export constraints. That created the conditions for prices to spike in the summer when it became clear the glut of 2020 was rapidly turning. And all this was made even worse by the sharp decline in the EU’s indigenous gas production. The fact that last year was the year the EU decided to go over from long-term contracts to trading gas on a spot market only removed a built-in cap on prices and freed gas prices to soar into the stratosphere. In short, the last two years have created a perfect storm for the gas market.
All of Europe’s biggest gas fields are in decline. North Sea fields that were first developed in 1990s or even earlier are now mature, yielding less gas at an increasingly high cost. But many in the gas industry point instead to insufficient investment in new production, largely on account of environmental concerns. The EU’s new Green Deal has only made a new problem much worse. The EU is eager to phase out the use of gas and other fossil fuels over the coming decades as it strives towards net-zero emissions by 2050. But as the current crisis has shown, for the time being consumption remains robust. But curtailments in local gas production over the years have left Europe more dependent on imports than ever before. In the EU’s case, 90% of the bloc’s gas now comes from overseas.
For many decades, the Groningen field off the coast of the Netherlands was Europe’s largest gas producer. Its output hit a peak of 88 bcm in 1976, but production activities led to earthquakes, causing damage to property in the area.
That was why the Dutch government in 2014 ordered Groningen’s operators, Royal Dutch Shell and ExxonMobil, to start reining in supplies. Originally, the field’s full closure was anticipated in 2030, but this was brought forward in 2019 to 2022.
While the Netherlands ordered Groningen’s closure on account of the earthquakes, broader climate concerns influenced the government’s 2019 decision to fast-track the process. What is more, despite the current crisis, the government has insisted that Groningen’s closure will go ahead as planned.
The Netherlands has stifled upstream investment in other ways. Notably in 2019, a Dutch court ruled that the Netherlands’ previous standards for issuing construction permits violated EU laws protecting the environment from nitrogen oxides, putting billions of dollars of projects in many industrial sectors, including natural gas, on hold. Several operators have cited the nitrogen ruling as the main reason for cancelling investments, including German-Russian joint venture Wintershall Noordzee, which in November last year axed a plan to develop two oilfields. Meanwhile, the government has also delayed introducing new incentives to encourage investment in fields.
Dutch gas output slumped to an historic low of 20 bcm in 2020, down from over 75 bcm a decade earlier.
Years of UK decline
UK gas output has similarly been on a downward trajectory since the early 2000s. With an output of only 40 bcm last year, the UK now relies on imports to cover around half of its demand. In 2004, in comparison, the country was self-sufficient in gas.
Arguably, successive governments could have done more to incentivise offshore gas development over the years, but were discouraged from doing so because of climate concerns and the shift in priorities towards offshore wind power development. But the UK North Sea is also a mature region, and so to an extent the decline has been inevitable. What is more, its production is increasingly high-cost, making it vulnerable to market downturns like those that occurred in 2014 and last year.
The UK has considerable onshore shale gas reserves, estimated by the British Geological Survey at nearly 40 trillion cubic metres. But amid strong local opposition to the use of hydraulic fracturing, these unconventional resources remain locked in the ground. The UK’s Conservative government, which has long advocated shale gas extraction, imposed a temporary moratorium on the use of hydraulic fracturing in November 2019, in order to shore up support ahead of general elections that year. This was largely seen as the death knell for the sector.
It is difficult to say exactly how much of an impact large-scale shale gas development would have had for the UK’s energy mix. But in 2013, then Prime Minister David Cameron estimated that if even 10% of known reserves were extracted, the UK would be able to cover its gas needs for over 50 years.
Moving forward, the UK government looks set to take a more aggressive stance against gas development. Under a revised policy, upstream regulator Oil and Gas Authority (OGA) has said it will scrutinise new projects more over their environmental impact. And earlier this month, the Offshore Petroleum Regulator for Environment and Decommissioning refused to approve Shell’s plan to develop the Jackdaw field, expected to supply a substantial share of UK production in the late 2020s.
OGUK, a lobby group for the UK gas and gas industry, warned on October 6 that without continued investment in gas supply, production could fall by a further 75% within the next decade, leaving the country dangerously reliant on energy imports.
“We will need gas to power us through this green transition,” OGUK CEO Deirdre Michie said in a statement. “It would be far better to get as much of that gas as possible from sources we can control rather than rely on other countries.”
Denmark ends exploration
Gas supply in Denmark has also been falling for years, as a result of natural decline and, more recently, the closure of its largest field for redevelopment work. From 8.5 bcm in 2010, the country’s output was only 1.4 bcm last year.
The offshore Tyra gas field operated by France’s TotalEnergies was by far Denmark’s biggest source of production until its closure in September 2019, so that a redevelopment programme could take place. This programme involved the replacement of the topsides at Tyra’s platforms, which over many years of production had subsided, as well as the installation of new jacket extensions.
The work had been due to wrap up in July 2020, although there were delays as a result of coronavirus restrictions imposed at fabrication yards in Asia. The field still has not resumed gas supply. As a result, Danish authorities now predict that national gas output will never again reach the level of 4 bcm per year that it was prior to Tyra’s closure, and will instead re-peak at only 3 bcm in 2027.
Further dimming prospects for Danish gas supply, the country became the latest to end all oil and gas exploration in December last year under an agreement between the government and Parliament. Denmark is the largest oil and gas producer to have taken such a step.
Romanian Black Sea delays
Contributing to the current tightness of the European gas market, Romania’s ambitious plan to develop a series of gas fields in the Black Sea has largely not materialised. Rather than an environmental policy, the industry has blamed the lack of investment in offshore discoveries to radical changes to the country’s offshore law that were introduced by the government in late 2018. Among other things, the revised law imposed restrictions on where operators could sell their gas as well as introducing caps on prices.
OMV Petrom and ExxonMobil have repeatedly delayed taking a final investment decision (FID) on the largest of Romania’s offshore discoveries, Neptun Deep, citing the regulatory changes. The centre-right minority government of Prime Minister Florin Citu wants to reverse the changes to the offshore law, but opposition parties have tried to prevent this. The country is now in the midst of a political crisis, with Romanian lawmakers voting overwhelmingly to topple Citu’s government in a no-confidence vote on October 5. As such, it seems unlikely there will be any improvements to the law any time soon.
The Norwegian bright spot
The notable exception to declining gas supply rates in Europe is Norway, which has kept its output stable in recent years. It produced 111.5 bcm of gas last year, much of which went to Europe, making it the continent’s second-biggest supplier after Russia.
And indeed, Norway shows no sign of following other European countries in imposing restrictions on oil and gas development. The former centre-right government announced in June a new energy strategy that would see the country continue to hold regular licensing rounds for oil and gas exploration for decades to come, although a 65% natural decline in production is envisaged by 2050. Norway’s Labour and Centre parties are due to form a new minority government following elections in September, although both are eager to protect the Norwegian economy and jobs, making a tougher stance against gas development unlikely.
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