First Break talks to the global energy analyst S&P Global about what needs to happen to ensure that substantial remaining resources can still be recovered from the UK North Sea.
UK oil and exploration is at a critical juncture. Either the bulk of the remaining estimated 6-7 billion boe will be recovered and the industry will remain viable for at least the next 20 years, or the industry will start to run down and hubs will be decommissioned.
In November 2025 the UK government confirmed that no new oil and gas licences would be issued in the country’s waters, apart from in areas close to existing fields with ‘known hydrocarbon accumulations’ and only then if stringent environmental demands are met.
The stance taken by Ed Milliband, the UK’s secretary of state for energy security and net zero, has reportedly led to rows at the heart of government. The UK chancellor Rachel Reeves is pushing for an easing of the current regime to make it easier for new licences to be awarded.
Miliband claims that new exploration on the UK shelf would make little difference to UK energy security because most of the oil and gas would be exported elsewhere. Reeves wants the tax revenue new projects would bring to boost the UK exchequer.
The UK Treasury is understood to be pushing to accelerate introduction of a more favourable fiscal regime to replace the Energy Profits Levy (EPL) well before its slated phasing out in 2030.
David Whitehouse, chief executive of Offshore Energies UK, says: ‘Early implementation of the Oil and Gas Price Mechanism (OGPM) is critical. This permanent, price-triggered mechanism provides a fair return to the public when prices are high, while giving investors the certainty needed to commit capital. However, delaying its implementation to 2030 is too late. Reforming the tax now is the key to unlocking £50 billion of private investment.’
‘This would allow the UK to meet over half of domestic demand, enhance energy security, increase tax revenues, protect jobs, and reduce reliance on carbon-intensive imports.’
Without action the UK is set to rely on LNG shipments for over half its gas by 2035, he warns.
Fiscal regime
The UK government introduced the Energy Profits Levy in 2022 in response to energy companies profiting from a surge in oil and gas prices during the war in Ukraine. In November 2024 the new Labour government increased EPL, which brought the headline tax rate to 78%. In November 2025 the UK government confirmed that EPL would remain in place until 2030.
At that point the Oil and Gas Price Mechanism (OGPM) will replace it. After consultation with industry, this would introduce a predictable framework that would switch on and off (with a threshold of oil prices at $90 a barrel and 90p per therm gas price at today’s prices).
‘It would truly be a windfall tax, unlike the EPL, which in practice has almost no switch off,’ says Tania Pearson, lead fiscal energy terms and risk at the energy analyst at S&P Global. ‘It’s only a proposal and we hope the government will announce it in the autumn budget. Companies need a clear vision of what’s to come so that they plan and budget for that.’
Defenders of the current UK fiscal regime say that In Norway tax for oil and gas exploration is also up to 78%, albeit with explorers able to claim back substantial allowances, such as cash reimbursement for tax losses.
‘The thinking is that if Norway can operate with that burden and prosper, then the UK can as well,’ adds Pearson. ‘But the EPL has been adjusted several times since it first came in – its sunset date extended, the rate has increased and allowances have been removed – making the UK fiscal regime far less stable in comparison.’
Exploration
The Pensacola discovery was made in January 2023, targeting the Zechstein Haupt Dolomite Formation in the Mid North Sea High. Now operated by Adura (Shell/Equinor) and One-Dyas, it is a play opener and the largest Southern North Sea discovery in the past 10 years, with an estimated 326 million boe of oil and gas in place. A Final Investment Decision is expected next year.
All four exploration wells in 2024 made discoveries: Gilderoy, Selene, Baker and Jocelyn South. In 2024 the Talbot field, operated by Harbour Energy, was brought onstream.
In 2025 two appraisal wells were drilled by ONE-Dyas on the Crosgan discovery and by Harbour in the eastern area of the Brodgar field.
In 2025, the Jocelyn South field (Harbour Energy), the Affleck field (Neo NEXT+), the Murlach redevelopment (bp) in the Central North Sea, the Victory field (Adura), and the Penguins redevelopment (Adura) were brought onstream. Serica Energy’s Belinda Field in the Central Graben was brought onstream earlier this year.
Hibiscus Petroleum’s Teal West field will not be brought onstream until mid-2026 (delayed from 2025).
Three wells are planned this year. Adura is planning to drill the Adilie (in the Penguins field) in the Northern North Sea and the Shearwater well, 225 km east of Aberdeen (a sidetrack well), while bp is forecast to spud the Ariadne well in the ETAP field in the Central North Sea.
West of Shetland the most promising standalone development is the Rosebank field, operated by Adura (Shell and Equinor), which has 336 million boe of recoverable reserves and as much as 500 million boe and could yield 69,000 barrels a day. A $3.8 billion final investment decision was made in September 2023. Approval was ruled unlawful in January 2025. It is hoped to come on stream in 2027.
BP has yet to submit a FDP for Clair South Phase 3, 75 km West of Shetland, which still has significant resources.
Anastasia Polymeni, principal analyst at S&P Global, says: ‘West of Shetland remains highly prospective, but limited infrastructure means larger discoveries are needed to meet development thresholds. Costs are also significantly higher given the remote location and harsh environment.’ Typically, a 70 km tie back into existing infrastructure. In the Central North Sea, it would be a 10/20 km tie back.
The Jackdaw gas field in the Central Graben in the North Sea is being developed as a tieback to the Shearwater infrastructure. Operated by Adura (Shell/Equinor), approval of the project has been under review by Energy Secretary Ed Miliband. It has the potential to supply approximately 6% of UK gas demand with infrastructure partly in place.
Other potential projects are Glengorm gas field (NeoNext+ and CNOOC) in the Southern North Sea; and Glendronach, a significant gas field near the Shetland Islands that has been stalled by the current tax regime.
Cambo in the North Sea is considered the UK’s second-largest undeveloped discovery. Buchan in the North Sea is a major redevelopment project involving bringing a formerly dormant field back into production.
‘Since 2019, activity has dropped off — not just because of Covid-19, but also due to growing uncertainty around taxes and regulation,’ adds Polymeni. ‘Exploration drilling, access to funding and final investment decisions have all slowed, and rebuilding confidence will take time and consistent policy.’
Big players that remain have merged. For example, TotalEnergies has merged its UK assets with NeoNext (Repsol) to form NeoNext+. Assets include the Greater Laggan Area (GLA) production hub. Small independent players such as Ithaca and Serica are still active.
Equinor/Shell merged their UK North Sea operations to form Adura in December 2025, which includes 12 producing oil and gas assets: Mariner, Rosebank, Buzzard, Shearwater, Penguins, Gannet, Nelson, Pierce, Jackdaw, Victory, Clair, and Schiehallion. Overall, it is producing 140,000 barrels a day.
Smaller independent companies have moved in. For example, Serica recently bought TotalEnergies’ West of Shetland assets. The largest independent is Ithaca, owned by Delek Group. Its assets include Alba, Captain, Cook, Cygnus (largest single producing gas field in the UK), and the Greater Stella Area, cumulatively producing 119-125,000 barrels a day.
Big US players such as Exxon Mobil and Chevron have already left (and have also exited Norway) and are unlikely to return, because the potential size of discovery is not enough to replace their reserves.
Bp is reported to be considering a sale of its UK North Sea assets for $2.7 billion. London-listed Harbour Energy, which has been a big player in the North Sea, is also rumoured to be thinking of putting its money into other countries.
Environmental requirements
Scope 3 emissions must now be included in UK Field Development Plans. Since December, three have been submitted, all by Ithaca Energy: Fotla, Cambo and Tornado. Rosebank and Jackdaw also have to do this retrospectively, says Gethin Baker, senior principal analyst at S&P Global. ‘Previously, it was taking approximately six months from submission to approval and now it’s well over a year.’ Even then Miliband will have the final say and could still withhold approval.
As part of emission reduction plans any new field development is expected to be electrified in 2030. ‘There are no electrification projects in UK at the moment,’ adds Baker. ‘The Captain field is the most progressed but Ithaca Energy cancelled the project, citing the fiscal environment, significant investment required and uncertainty with securing a grid connection,’ adds Baker, ‘Retrofitting old infrastructure is so costly, especially under the current fiscal regime with companies unlikely to undertake such investments.’
Ian Conway argues that continued oil and gas exploration in the North Sea will support the energy transition. ‘Offshore platforms, pipelines, ports and a highly skilled workforce underpin carbon capture and storage, hydrogen production and electrification, all of which are essential to delivering net zero while maintaining secure and affordable energy.
‘Some projects depend on North Sea infrastructure remaining in place and would be maintained by future oil and gas revenues. If future revenues aren’t there in future, then developing projects like CCS will be more costly. The two do play off each other.’
Approving projects such as Rosebank and Jackdaw would also potentially lower the UK’s carbon footprint, he argues. ‘The carbon footprint of generating energy from domestic gas generally can be shown to be smaller than if you are bringing gas from the US, Qatar or Australia into the UK for the same purpose.’
Licensing
While Norway is pressing on with its latest Awards in Predefined Areas for 2026, UK oil and gas licensing rounds have stopped. ‘In 2020, there were 120 companies involved in UK exploration and now there’s about 60,’ says Baker.
The UK government is introducing ‘Transitional Energy Certificates’ (TECs) that could be awarded ‘for a block of acreage which is part of, or adjacent to, an existing field (linked by a tieback),’ and where ‘the activity is necessary for a managed, prosperous and orderly transition.’
The government is consulting with industry on TECs and it remains to be seen how much take up there will be.
Seismic data
TGS, along with Viridien and Shearwater and a number of smaller companies, are still active in the UK in the UK North Sea.
'In the UKCS, there continues to be proprietary seismic imaging work reprocessing, harmonising of legacy data, and some OBN acquisition work, but the demand for new multi-client data acquisition is limited,’ says James Raffle, seismic imaging manager at TGS. ‘The UKCS multi-client data that exists is of good quality and there is potential to do more with it using modern imaging technology.'
'Using AI and machine learning, we can extract greater value from existing data. We can train seismic foundation models with the large amounts of multi-client seismic data that TGS owns. We can then use this general subsurface representation to undertake efficient multiple interpretation tasks with limited human input. The UK government making well data available with open access, so we can train well foundation models, is a positive. There is an awful lot of innovation in other parts of the world that could be applied to the UK.'
'Acquiring new seismic data continues to become more cost-effective. We can also use modern, cloud-based algorithms such as elastic FWI to quickly provide higher resolution images of the subsurface and help to reduce the risk.'
'Imaging technology developments and cloud computing are enabling cost effective solutions for the development of high-resolution near-surface models. These can be applied in a traditional sense to derisk well planning.'
The future
What remains of the UK oil and gas industry is in danger if hubs are decommissioned early, leaving stranded volumes in the ground that will be uneconomic as standalone developments in the future.
Anastasia Polymeni at S&P Global, says: ‘If infrastructure-led exploration (ILX) opportunities are not pursued and satellite fields are not developed, key hubs could be shut down too early, leaving valuable oil and gas unrecovered, going against the goal of maximising economic recovery. The longer these resources are left undeveloped, the less likely they are to be produced at all.’
But all is not lost, says Conway. ‘With a more favourable fiscal regime, even standalone developments in the West of Shetland and the Mid North Sea High could be justified. The UK is still a stable place to invest and still attractive because of the comparatively low risk in global terms.’
David Whitehouse of UK Oil and Gas, says: ‘There is significant potential left in the North Sea. With the right tax and regulatory policies, the UK can still produce over seven billion barrels of oil and gas between now and 2050.’
History of North Sea exploration
Offshore UK exploration started in 1964. The West Sole gas field was discovered in 1965. The first offshore field to come into production in 1967, it was still onstream In 2024, having produced some 2.168 Tcf of gas (at the end of 2023).
UK Production peaked in 1999 at 4.64 billion boe/d. In 2023 it had reduced around 70% to 1.2 million boe/d. The UK has been a net importer of oil and gas since 2013.
The most recent bidding round was the 33rd Offshore Licensing Round, launched in October 2022 and closed in January 2023. Acreage held in 2023 was at the lowest level since the 1970s.
Oil and gas production in 2024 averaged 580,247 bo/d and 3.1 Bcf/d, down from 656,560 bo/d and 3.4 Bcf/d in 2023. Drilling activity has more than halved since 2019.
Over the past 10 years, 6 billion boe has been produced while 600 million boe was discovered, representing a 10% reserves replacement rate. In that time the average discovery was approximately 20 million boe, with an average of seven discoveries per year.
The Labour government pledged not to grant new licences in its manifesto, and it confirmed these plans in the document Building the North Sea's Energy Future, published on November 26, 2025.
Compared to 2023, UK oil and gas production is forecast to be half by 2030 and 2028, respectively, if no new fields are brought onstream.
Discovered but undeveloped (contingent) resources are estimated to be 6.1 billion boe, 70% of oil, with 30% gas.
