Groningen: How Europe’s Largest Gas Field Was Shut Down With 450 bcm Still in the Ground

Groningen is the story of a country that decided to leave Europe’s largest gas field almost half full because the cost of extracting it had shifted from the balance sheet to the foundations of 28,000 homes. For sixty years the field financed the Dutch welfare state, anchored the Rotterdam petrochemical cluster and underpinned the low-cost gas economy of north-west Europe. Then a magnitude 3.6 tremor at Huizinge in August 2012 turned a known nuisance into a safety crisis, and a decade of production caps, lawsuits, failed reinforcement programmes and a damning parliamentary inquiry ended with the field shut, the operator in arbitration and the state committed to a generation of compensation. This article traces how it happened, what it cost, and what it means for a country that chose to close its own supply just as Europe lost Russian gas. It is part of the Netherlands Company Stories hub.

How did Groningen become the foundation of the Dutch economy?

NAM discovered the Groningen field near Slochteren in 1959, and within a decade it had reshaped the Dutch economy, financed a rapid conversion of homes and industry to natural gas and created the long-term contract structures that still define European gas trading. The field’s original recoverable reserves were around 2,800 billion cubic metres, making it one of the ten largest gas fields ever found and by far the largest in Europe. Nederlandse Aardolie Maatschappij, a 50/50 joint venture of Shell and ExxonMobil’s predecessor Esso, operated the field under a 1963 agreement in which the state, through its Maatschap Groningen partnership and later EBN, took the bulk of the profit.

Production rose quickly to more than 70 billion cubic metres a year in the mid-1970s, and Groningen gas was piped to Germany, Belgium, France and Italy under contracts that indexed the price to oil. The low-calorific “L-gas” from the field required specific burner settings, so a large share of appliances in the Netherlands, northern Germany, Belgium and northern France were built to Groningen specifications. That technical legacy meant the field could not simply be replaced by imports without conversion plants that blend nitrogen into high-calorific gas.

By the time production ended, gas extraction in Groningen had delivered about €363 billion to the Dutch treasury, according to the figures cited by the parliamentary inquiry. The revenue paid for infrastructure, social insurance and, in the 1970s, the phenomenon that economists named the “Dutch disease”, in which resource income inflated the currency and hollowed out manufacturing. The province of Groningen itself saw comparatively little of the money, a grievance that became central to the political reckoning half a century later.

What did the 2012 Huizinge earthquake change?

The magnitude 3.6 tremor at Huizinge on 16 August 2012 was the strongest induced earthquake ever recorded in the Netherlands and the point at which the Dutch state could no longer treat seismicity as a manageable side effect. Small tremors had been registered since 1986, and NAM had acknowledged a link to extraction in the early 1990s, but damage had been handled through a low-profile claims process. Huizinge damaged thousands of homes, and the State Supervision of Mines (SodM) warned in early 2013 that larger quakes, possibly above magnitude 5, could not be excluded while production continued at high levels.

The government’s first response was to keep producing. Economic affairs minister Henk Kamp allowed output to reach about 54 billion cubic metres in 2013, the highest level in years, because cold weather and export contracts demanded it. Only in 2014 did the cabinet impose a cap of 42.5 bcm, followed by 30 bcm in 2015, 27 and then 24 bcm in 2016, and 21.6 bcm for the 2017–18 gas year. Production around Loppersum, the most seismically active cluster, was cut from about 16 bcm a year to roughly 1 bcm over three years.

The caps did not stop the tremors. A magnitude 3.4 quake at Zeerijp in January 2018 prompted Kamp’s successor Eric Wiebes to announce in March 2018 that production would be reduced to 12 bcm as quickly as possible and ended entirely by 2030. In 2018 the state and the NAM shareholders also signed the Akkoord op Hoofdlijnen, which rewrote the profit split in the state’s favour, transferred responsibility for damage handling to the state and committed Shell and ExxonMobil to a wind-down. That agreement, and the later decision to close far earlier than 2030, is at the heart of the arbitrations now running at ICSID.

What did the parliamentary inquiry conclude in 2023?

The parliamentary inquiry committee chaired by Tom van der Lee reported on 24 February 2023 that the interests of Groningen residents had been structurally ignored by the state, NAM and their advisers, with disastrous consequences for safety, health and trust. The report, titled Groningers boven gas (“Groningers above gas”), ran to almost 2,000 pages and followed public hearings in which prime minister Mark Rutte, former ministers and Shell and ExxonMobil executives were questioned under oath. Rutte was later accused by MPs of having misled the committee about his knowledge of production decisions, an allegation he denied.

The committee found that the state had treated the field as a revenue source first and a safety problem second, that the “gasgebouw” structure of NAM, EBN, GasTerra and the ministry had blurred accountability, and that damage handling and reinforcement had been slow, legalistic and in places humiliating for claimants. It recommended that the state recognise an “ereschuld”, a debt of honour, and settle it through a long-term programme rather than one-off payments. Van der Lee said that redeeming the debt of honour started with putting the interests of the people of Groningen first.

The cabinet’s answer came on 25 April 2023 in the form of Nij Begun (“new beginning”), a package of 50 measures worth €22 billion over 30 years for Groningen and northern Drenthe. The measures cover damage repair, reinforcement, social and mental wellbeing and economic perspective. The most visible change was that damage up to a threshold, originally €40,000 and later raised to €60,000, is now repaired without an investigation into whether gas extraction caused it. The cabinet also committed to report annually to parliament on progress, and the first State of Groningen and North Drenthe report was presented in Delfzijl on 15 April 2025.

How did the 2022 energy crisis test the decision to close?

When Russian pipeline flows to Europe collapsed in 2022 and gas prices spiked, the Dutch cabinet refused to raise Groningen production and instead cut it further, to 2.8 billion cubic metres for the 2022–23 gas year, the minimum level at which the wells could be kept operational. The decision, announced in September 2022 by state secretary Hans Vijlbrief, was taken despite calls from economists, industry and some European partners to use the field as a strategic reserve. Output of 4.5 bcm in 2021–22 had already been about 4% of peak levels.

The cabinet’s position was that Groningen would be used only as a last resort to keep Dutch households supplied, and that all eleven production sites would remain available until April 2023 for an emergency. A Council of State ruling in August 2022 confirmed that the government had been within its rights to keep the field open that year. Critics argued that leaving 450 bcm in the ground, roughly a year of EU consumption, during the worst supply crisis in decades was a costly act of political penance. Supporters replied that any increase would have undermined the reinforcement programme and risked further quakes in a region where trust was already gone.

The outcome was that the Netherlands absorbed the crisis through imports. Gasunie and Vopak opened the Eems Energy Terminal, a floating LNG facility at Eemshaven, in September 2022, and the Gate terminal in Rotterdam expanded. Production ended on 1 October 2023, and in April 2024 the Senate approved the law that closed the field permanently, with some senators demanding assurances about supply security before voting. The government said the residual risk would arise only after two exceptionally cold winters in succession. For a broader view of how Dutch industry reacted to the price shock, see the nitrogen crisis article, which describes another case where environmental limits overrode economic arguments.

How far has the compensation and reinforcement programme progressed?

By the end of 2024 the Instituut Mijnbouwschade Groningen (IMG) had paid out almost €2.5 billion in damage compensation, and the Nationaal Coördinator Groningen (NCG) reported that 60% of the roughly 28,000 addresses in its reinforcement workload met the safety standard, up from 43% a year earlier. The IMG total breaks down into about €1.6 billion for physical damage to homes and buildings, more than €500 million for loss of property value and more than €250 million for non-material damage, the last a category created after courts recognised the psychological toll on residents.

The reinforcement operation is the harder problem. The 2028 completion target set in Nij Begun is no longer considered feasible; NCG expects 85–95% of the work to be done by the end of 2028 and the final addresses to be completed between mid-2030 and mid-2032. The regulator SodM has repeatedly said the pace must increase, and a 2025 forecast by NL Times suggested the operation might not finish until 2034 at current rates. In June 2026 the advisory body ACVG, reviewing structural safety reports for around 28,000 addresses, found at least 213 reinforcement dossiers with errors, including homes that may have been wrongly declared safe and residents who received reports intended for other properties.

A separate law on damage handling, published in the Staatsblad on 8 July 2026, aims to simplify the legal basis for the no-causation-check repairs and other Nij Begun measures. The cumulative picture is of a state that has accepted liability in principle and is spending at scale, but whose delivery machinery is still slower than the political promise. For founders and investors used to project timelines, the lesson is that a reinforcement programme is in practice a 30,000-unit construction business run under public-law constraints and intense scrutiny, and should be budgeted as such.

Why are Shell and ExxonMobil suing the Dutch state?

ExxonMobil filed an Energy Charter Treaty arbitration against the Netherlands at ICSID on 30 September 2024 through a Belgian subsidiary, and Shell plc followed with its own ICSID claim on 23 December 2025 after consultations with the government failed, both arguing that the accelerated closure and the allocation of damage and reinforcement costs breached the state’s commitments. The companies’ position is rooted in the 2018 Akkoord op Hoofdlijnen, under which they accepted a reduced profit share and a wind-down to 2030 in exchange for what they regarded as a settled framework. The state then closed the field six years early and continued to bill NAM for costs the companies dispute.

NAM has paid about €5.31 billion to the state under protest and, according to the SOMO research institute, still owes about €550 million for building reinforcement. Shell and ExxonMobil have not provided financial guarantees for NAM’s future liabilities, which the Dutch parliament has repeatedly raised as a risk. In addition to the two treaty cases, NAM, Shell and ExxonMobil are parties to several arbitrations before the Netherlands Arbitration Institute covering damage compensation, strengthening costs and the wind-down of the Groningen joint venture.

The Dutch courts are also active. On 14 June 2026 a court in Groningen ruled that the state’s bills to NAM of about €526 million for the depreciation of unsold homes in 2020 and 2021 were unlawful, because the valuation date of 1 January 2019 was too early under a 2019 Supreme Court standard; the ministry must issue a new decision. The same court upheld a separate €268 million claim for 2020 damage settlement costs. The pattern is of a long, expensive allocation fight in which the state has the political upper hand but not always the legal one. Shell’s wider retreat from the Netherlands, including its move to London, makes a negotiated settlement harder, because the company’s Dutch exposure is now a line item rather than a home market.

What has the closure done to Dutch energy security?

Since the closure the Netherlands has become largely import-dependent, relying on Norwegian pipeline gas, LNG from the United States and Qatar and declining output from small onshore and offshore fields, and Gasunie’s October 2025 security-of-supply report said that supply would be adequate only if the temporary Eemshaven LNG terminal stays operational beyond 1 October 2027. The report, sent to parliament by then-minister Sophie Hermans, concluded that Dutch homes could be heated even through a cold snap or a short supply interruption, but that the country was not well prepared for a long blockage, whether from sabotage of North Sea pipelines, disruption of LNG shipping or a closure of the Strait of Hormuz.

That last risk became real in 2026, when conflict in the Gulf disrupted Hormuz traffic and pushed European gas prices to three-year highs. Dutch storage at Norg, Grijpskerk, Alkmaar and Bergermeer was just over 70% full in early October 2025 against an 80% year-end target, and the cabinet had reserved €1.5 billion to buy gas if commercial filling fell short. Norg, ironically, was built as a buffer for Groningen L-gas and is now filled with converted imports. Dutch gas reserves in early 2026 fell to their lowest level since 2018, according to industry data.

The policy response has been to squeeze more from the small fields. In 2025 ministers signed a deal with the industry to increase North Sea drilling, One-Dyas doubled output at its platform north of Schiermonnikoog, and in April 2026 NAM began repairing idle wells at Warffum in northern Groningen, a small field excluded from the closure decree that holds about 1 bcm. The provincial council and the Groninger Bodem Beweging challenged the Warffum permit at the Council of State after a magnitude 2.1 tremor in May; in June the emergency judge allowed extraction to continue. About 90% of Dutch households still use gas for heating, and the government says supplies will be needed until at least 2045. The electricity grid congestion story explains why the alternative, electrification, is proceeding more slowly than planned.

How is the field being decommissioned?

The physical closure of Groningen is part of a national plug-and-abandonment programme covering about 800 onshore gas wells at 350 locations and the removal of some 1,750 km of pipeline, which began with the first well on 1 May 2024 and is expected to run for more than a decade. NAM has contracted WellGear Group, supported by Mammoet, to deploy a fully electric 180-tonne hydraulic workover unit that fills each well with cement plugs; the unit requires about 50 truckloads to move between sites.

The Groningen cluster sites themselves, including the large production locations at Bierum, Tjuchem and ‘t Zandt, are being dismantled in sequence, with the land to be returned to agricultural or community use. The costs of decommissioning are borne by NAM under the mining law, with the state carrying its share through EBN, and are one of the items in dispute in the arbitrations because the early closure brought forward spending the companies had expected to make in the 2030s.

NAM itself is being reshaped. The company announced in 2021 that it wanted to sell its small onshore fields and has since divested several licences, leaving it as a vehicle mainly for the Groningen wind-down, the Norg and Grijpskerk storage sites and the legacy liabilities. Whether NAM survives as an entity once the Groningen obligations are settled is an open question, and one that matters because the Dutch state has no guarantee from the parents for NAM’s future costs.

What can founders and investors learn from Groningen?

Groningen is first a lesson about externalities that compound. NAM and the state knew of the seismic link in the early 1990s, but the damage was small, diffuse and absorbed by a claims process. By the time it became a safety issue in 2012, the number of affected homes, the depth of local anger and the gap between promised and delivered repairs had grown too large to manage incrementally. Companies that generate slow-building harms, whether environmental, financial or reputational, should expect the eventual reckoning to be priced at the peak of public attention, not at the average.

Second, governance structures that blur accountability are a liability in a crisis. The “gasgebouw” arrangement between NAM, EBN, GasTerra and the ministry served everyone’s interests while revenue flowed and nobody’s when blame had to be assigned. The parliamentary inquiry’s central finding was not that any one actor behaved badly but that the structure made it impossible to say who was responsible. Investors in joint ventures with state partners should insist on clear lines of decision and liability before the first dividend.

Third, the state is both counterparty and regulator, and it can change the terms. The 2018 accord looked like a settlement; it became the baseline for a dispute. Treaty arbitration gives Shell and ExxonMobil a forum, but the Energy Charter Treaty is itself under withdrawal pressure across the EU, and the Dutch government has strong domestic support for its position. The investors who did best from Groningen were the pension funds and bondholders who benefited from sixty years of state revenue, not the operators who are now litigating over the last few billion.

Finally, the region’s experience is a reminder that economic value and local legitimacy can diverge for decades before they converge violently. Readers interested in how Dutch institutions handle other long-running regional and industrial transitions may find the Delta Works and Room for the River story a useful counterpoint, and the Germany Company Stories hub covers the neighbouring market that lost Groningen L-gas at the same time.

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