Every time oil prices spike, calls to reopen North Sea exploration resurface. One point should be clear from the outset: domestic drilling will not lower the price at the pump. Oil is a globally priced commodity, and UK output is too small to move international markets. Proponents nonetheless put forward several arguments — that new exploration generates tax revenue, that the industry sustains tens of thousands of jobs across Scotland and beyond, and that domestically produced oil carries lower upstream and transport emissions than crude shipped from the Middle East. These arguments deserve to be taken seriously. But they do not answer the specific question this article examines: is new North Sea exploration financially viable under a genuinely no-subsidy regime, where operators must deposit the full decommissioning cost upfront before a single well is drilled?
The decommissioning deposit is not a procedural footnote. It is the mechanism that determines who ultimately bears the risk. Plugging and abandoning a well costs roughly $2.5–5 million; once associated infrastructure is included, the average rises to around $10 million per well. The total decommissioning liability across the UK Continental Shelf (UKCS) is estimated at $56 billion. Nuclear power stations are required to provision for decommissioning costs during their operating lives — the North Sea should be held to the same standard. When operators are permitted to defer payment, the public absorbs a contingent liability. That is a subsidy in economic effect, even if it carries no line item in a government budget. Exempting operators from upfront deposits is not a neutral regulatory choice; it is a transfer of risk from shareholders to taxpayers.
Existing fields already in production cost around $25 per barrel to operate in 2024, with some harder-to-reach fields exceeding $38. These figures reflect only the running costs of infrastructure that was built and paid for years ago. New exploration is a fundamentally different calculation. Operators must first fund seismic surveys and exploration wells, some of which will find nothing. If a viable discovery is made, developing it requires tens to hundreds of millions of dollars in new infrastructure. Adding operating costs over the field life and a full decommissioning deposit, and spreading everything across the recoverable barrels of what are now predominantly smaller, deeper, and geologically complex remaining reservoirs, the full-cycle cost of new North Sea production falls in the range of $90–115 per barrel.
The industry frequently cites the 78% windfall tax rate as proof that the fiscal regime deters investment. This argument obscures more than it reveals. The current system includes a 91% investment allowance that dramatically compresses the taxable base, meaning the effective burden on new capital is far lower than the headline rate implies. If the special fiscal regime were abolished entirely and oil extraction were taxed as an ordinary business at the standard corporation tax rate of 19–25%, with no special allowances and full decommissioning deposits required, the break-even price for new exploration would rise to around $120–130 per barrel. Cutting the headline tax rate sounds like relief for investors, but removing the investment allowance costs them far more. The result is counterintuitive but arithmetically straightforward: stripping away the current regime raises the break-even, because the allowance was doing more work than the rate reduction saves.
Brent crude broke $110 per barrel in March 2026, which at first glance appears to bring some projects within range. The futures market tells a different story. The US Energy Information Administration forecasts Brent will fall below $80 by the third quarter of 2026 and average around $64 in 2027. The current spike reflects the geopolitical shock of US military action against Iran and partial disruption to shipping through the Strait of Hormuz — not a structural shift in supply and demand. New North Sea projects take five to ten years from exploration to first production, and the industry plans on a long-run price assumption of $60–75 per barrel. Without a government-backed price floor, no bank will finance a decade-long project on the basis of a geopolitical premium that the futures curve has already priced out.
This exposes a fundamental contradiction. Every argument for reopening North Sea exploration, however it is framed, ultimately requires some form of government intervention — a price floor guarantee, investment allowances, or exemption from upfront decommissioning deposits. Each of these is a subsidy. Once public support is acknowledged as a precondition, the question shifts from whether to subsidise to where public money yields the most return. Equivalent resources directed at accelerating renewable energy deployment and improving energy efficiency would reduce structural demand for fossil fuels, delivering economic and environmental benefits that new North Sea fields cannot match.
The North Sea has moved from a growth basin to a harvest basin. The fiscally rational response to elevated oil prices is to adjust the tax regime to capture the windfall from existing production — not to subsidise a new round of exploration that cannot stand on its own commercial merits.
