Amid the North Sea’s decline, large companies are moving out and being replaced by smaller players, able to take on lower margin projects. But in practice, the looming spectre of decommissioning liabilities can derail these asset transfers.
If the conditions are not right to allow companies to transfer assets, decommissioning is inevitable. Large companies must consider the risks of a sale, versus the known quantity of decommissioning.
This trend threatens to accelerate the North Sea’s decline. If the government wishes to change the pace of decommissioning, it will need substantial investment to manage the consequences.
Decommissioning considerations are complex, Bracewell partner Alistair Calvert explained. There are “significant risks involving complex practical and regulatory issues and bespoke and potentially unforeseen issues on each site. Layered over these risks and the scope for dispute within the project itself, is the question of liability for the costs of decommissioning.”
The Petroleum Act 1998 sets out decommissioning responsibilities.
Changing plans
Sir Ian Wood wrote his 2014 report on maximising economic recovery (MER) from the North Sea. He came out strongly in favour of deferring decommissioning. At that time, he wrote, pushing back decommissioning by five years on average would provide an extra 1 billion barrels of oil equivalent.
The MER plan did not survive its encounter with the UK’s decarbonisation goals and was amended in 2021. The changes brought in a new focus on maximising value, over volume. The new strategy left more room for complexity, in its attempts to shift thinking in the region.
Complying with the strategy may “oblige individual companies to allocate value between them … it will not be the case that all companies will be individually better off”. Easy to say in a strategy document, but hard to implement.
The 2021 paper went on to say when considering decommissioning, companies must “be able to demonstrate that all viable options for that infrastructure’s continued use … have been suitably explored”. It went on to say that decommissioning should allow maximising economically recoverable resources.
Costs are on the rise in the basin, as producers must find ways to tackle emissions intensity. Initially this is in areas such as eliminating flaring, but the North Sea Transition Authority (NSTA) will move into requiring projects to be electrification ready.
The Energy Profits Levy (EPL) also brings more pressure to bear on the sector, particularly on mature fields. As a result, companies are likely to choose to halt production earlier and move into decommissioning as returns become more marginal.
On the rise
Amid increasing regulatory and fiscal pressures, the sense of an impending decommissioning wave is mounting. Offshore Energies UK expects decommissioning to escalate over the coming years. It accounted for 12% of spending in the North Sea in 2023, but could reach 33% in 2030.
The NSTA expects that between 2023 and 2032, industry will spend around £24 billion, an increase of £3bn from previous expectations.
The NSTA has criticised operators for being too slow, given the backlog of more than 500 wells that have missed their original deadline. While the regulator has the authority to impose fines, it has preferred to provide “stewardship”.
The regulator has set out a number of ways in which to manage the transition, including a “glidepath” to underpin activity plans. Under this framework, operators start the decommissioning plan process up to six years before production ceases.
The challenge of changing course for big companies – with big plans – is major. TAQA fell out with various of its partners on the Brae complex, in a dispute that ended up in court. The ruling, from December, found a number of reasons for TAQA to have taken its decision around decommissioning timing.
One partner wanted more development drilling, while TAQA wanted to “accelerate decommissioning so that it could align its decommissioning programme across all its North Sea assets”. The bigger company was also concerned on the adequacy of the Decommissioning Security Agreement (DSA), the court found.
Time’s up
This conflict between larger and smaller partners over decommissioning timing is not isolated. For instance, Nobel Upstream grabbed the limelight earlier this year when it announced it wanted to buy out TotalEnergies’ stake in the Gryphon FPSO.
The French company halted production on the facility at the start of 2025. It has set out plans to decommission this year and into 2026. The FPSO, which began producing in 1993, serves five fields and had been producing around 12,000 boepd.
Nobel executives, in conversation with Energy Voice, linked Total’s decision to decommission the Gryphon with its environmental objectives.
While the French company has set out plans to curb its emissions, there is little evidence that Gryphon’s emissions were egregiously high. Filings from Total to the NSTA show the project was responsible for the lowest emissions in 2023 – excluding drilling.
The FPSO did discharge the highest amount of produced water, although Total said it was taking steps to remedy this problem.
Nobel does not hold any equity interest in the FPSO itself, but does hold small stakes in two of the fields supplying the hub.
Speaking earlier this year, Equinor’s Philippe Mathieu highlighted the importance of long-term value.
“You have a choice. When you sit and own a position in a mature asset, you can try to fight the decline and you need to invest quite a lot. Or you de-risk and you cash out the value of that and then you turn to a project which is next generation and has more longevity.”
Those owners of mature assets must make a choice around how to cash out value. Sometimes this is as much a question of curbing risk on decommissioning liabilities, as it is maximising reward.
Tough talk
Total has not responded to requests for comment on its motivations, to decommission rather than to sell.
But there are costs involved in a sales process, such as opening a data room and engaging external parties, while there is no guarantee of success.
There is still financing for deals in the space, Adam Waszkiewicz, partner at Bracewell, said.
These could be either on a reserve-backed loan (RBL) or pre-payment basis for “newer assets and for the right opportunities in later life assets. Such deals in the UK are likely to require a DSA and, increasingly, we see M&A deals structured such that the seller retains a certain portion of decommissioning liability in the asset.”
For a big company, that has been making plans for years under the NSTA’s glidepath, it can be a tough sell to shift from decommissioning to sales. And to go through this process while still having to retain liabilities, over an asset they no longer have direct control of, can be a bitter pill.
Searching for security
At the heart of these challenges is the question of financial security for decommissioning costs. Bracewell’s Calvert explained DSAs were not obligatory for such deals, but they are common and NSTA guidance expects field-wide agreements.
“DSAs provide (a certain degree of) comfort to the relevant parties that sufficient funds are set aside to fund decommissioning,” he said.
However, Calvert continued, they do not “protect against a potential commercial disagreement between large and small companies as to when to decommission an asset, although the option for a smaller company to seek to buyout a larger company’s interest is always available”.
Welligence VP for North Sea Dave Moseley said companies had to make decisions around risks and rewards.
“The sale of an asset tends to see the liability passed to the new owner. But if the buyer defaults – it runs out of money, or goes bankrupt or something – then that decommissioning liability can ‘grandfather’ back to the preceding company. In that situation, the old owner has very little control over the state of the decommissioning process they inherit.”
The upside of a sale is relatively modest for the company. But the risk is substantially higher.
“Those big companies will have a relatively cost-effective decommissioning plan. To scrap a process that is already likely well under way, sell the facility – probably get very little for it – while also potentially missing out on abandonment relief is a concern,” Moseley said. “The risk around selling and pushing back decommissioning is higher than the potential reward.”
Regulator impact
With North Sea assets in decline and sales challenging – on risk worries if nothing else – what can be done?
The government, perhaps via the NSTA, could take steps to incentivise companies to transfer assets rather than decommission.
Government is already taking a role in decommissioning, given its financial exposure. The NSTA’s most recent report suggests a cost to government of £10.8bn, made up of £5.7bn in tax repayments and a £5.1bn reduction in offshore corporation tax.
Waszkiewicz explained there may also be incentives to repurpose assets for carbon capture. The government has proposed “to legislate to provide for tax relief for payments oil and gas companies make into decommissioning funds when the payment is associated with the transfer of an asset from an oil and gas company to a carbon capture usage and storage [CCUS] company”.
But can government have a more direct impact in delaying decommissioning and continuing production? Without a willingness to absolve companies of the grandfathered risk, it seems unlikely.
When taking into consideration the political pressures around North Sea oil and gas production, this moves from unlikely to impossible.
Most decommissioning projects go ahead without companies falling out. But the North Sea faces a risk of decommissioning over asset transfers. The EPL has intensified this pattern by reducing mature fields’ economic viability.
Large operators phasing out of the basin face a clear financial equation that creates a powerful disincentive to sell.
The fundamental issue is trust. Reaching deals requires confidence in the counterparty’s ability to deliver into the future. If companies cannot establish trust, decommissioning becomes the default option. This will hasten the basin’s decline and increase the financial burden on government.
Industry will need to find new ways to collaborate, or risk ever more visits to court.
Recommended for you
