Oil Supply, Refining and Decommissioning

Current Oil System Position

The oil sector is often treated as a single number, but the current picture has four moving parts. The first is upstream production on the UK Continental Shelf, which fell to 31 million tonnes in 2024 (the lowest year since 1976), down 8.9 percent on 2023 and 42 percent on 2019, against a 2P reserve base of 2.9 billion barrels of oil equivalent and a 2C contingent resource of 6.2 billion boe.¹ The trajectory is a depleting-resource curve rather than a policy outcome: as fields mature, pressure falls, water cut rises, and per-well rates trend down. The 33rd Offshore Licensing Round (awarded between October 2023 and May 2024 in three tranches: 82 offers to 50 companies across 257 blocks) adds about 600 million boe to 2060 at the margin but cannot return UKCS production to even 2010 levels.

The second moving part is downstream refining. The mainland footprint stands at four operating sites in mid-2026: Stanlow on the Mersey, Pembroke in west Wales, Fawley on Southampton Water and Humber on the Humber estuary. Two sites closed in 2025: Grangemouth on the Forth ceased crude refining on 29 April 2025 and is converting to an import terminal under Petroineos's Project Willow (a shortlist that includes hydrogen, eFuels and sustainable aviation fuel), and the neighbouring Lindsey refinery stopped after the insolvency of its owner Prax. Combined capacity of the four operating sites is about 0.96 million barrels per day, down from over 1.8 million in the year 2000 after the Coryton (2012), Milford Haven Murco (2014), Grangemouth (2025) and Lindsey (2025) closures; total UK refinery throughput in 2024 was 50.8 million tonnes, roughly 60 percent of the 2000 level.¹ Phillips 66 completed the acquisition of the Lindsey assets from Prax on 28 April 2026, but is integrating them into the neighbouring Humber refinery rather than restarting crude refining at Lindsey.

The third moving part is the decommissioning pipeline. The North Sea Transition Authority's most recent industry cost estimate runs to 44.5 billion pounds across the UKCS to 2050; 2024 alone saw 2.4 billion pounds of decommissioning spend, the highest annual figure on record. OPRED regulates the abandonment programme under Part IV of the Petroleum Act 1998 and the OSPAR Decision 98/3 derogation regime; every cessation of production triggers a Section 29 notice and an approved decommissioning programme before any disposal of subsea or topsides infrastructure begins. The fourth moving part is forward demand. Future Energy Scenarios 2025, published on 14 July 2025, sets out three net zero pathways (Holistic Transition, Electric Engagement and Hydrogen Evolution) plus a Falling Behind counterfactual; oil demand in road transport falls fastest in Electric Engagement, with residual oil sitting in aviation and marine through to 2050 in every credible scenario.² That residual is the reason aviation and marine sit as separate demand sectors here rather than being folded into the general transport headline.

Connections Reform Gate 2 outcomes in April 2026 progressed 283 gigawatts of generation and storage and 99 gigawatts of demand to firm offers; the demand share matters for the oil page because it includes the early movers on green hydrogen production at scale, which is the upstream feedstock for sustainable aviation fuel through the power-to-liquid route covered on the hydrogen page.⁷ The oil system is therefore neither a single number nor a fixed-shape pyramid in 2026: upstream is in long decline, midstream and downstream are consolidating around four operating refineries after the 2025 closures, the decommissioning pipeline is the only growing line, and the demand side splits between road (falling fast under electrification) and aviation and marine (the residual that anchors the long tail).

The UK Continental Shelf, production decline and remaining reserves

The UK Continental Shelf is the offshore territory across which the Crown holds title to petroleum under section 2 of the Petroleum Act 1998 (consolidating the 1934 Petroleum Production Act). Five productive provinces sit across it: the Northern North Sea (Brent, with the original 1976 production now in late-life decommissioning), the Central North Sea (Forties from 1975, Buzzard from 2007, Captain), the Southern North Sea (predominantly gas; oil production is minor), the West of Shetland (Schiehallion redeveloped under Quad 204 from 2017, Clair and Clair Ridge from 2005 and 2018, and Rosebank with Final Investment Decision in 2023 and first oil expected 2026 to 2027), and the East Irish Sea (Morecambe Bay).

Production fell to 31 million tonnes in 2024, down 8.9 percent on 2023 and the lowest annual total since 1976. Expressed in barrels per day, the trajectory runs from the 1999 peak of about 2.9 million bpd through 1.6 million in 2008, 0.85 million in 2014, 0.95 million during the pandemic year 2020, and 0.6 million in 2024.¹ The shape of the curve is set by the underlying physics of mature basins: as reservoir pressure falls, recoverable rates fall, water cut rises, and per-well economics deteriorate. New small fields and infill wells slow the decline; the 33rd Offshore Licensing Round (awarded between October 2023 and May 2024 in three tranches: 27 offers in Tranche 1 across the Southern North Sea priority cluster blocks, 24 offers in Tranche 2 across the West of Shetland, Northern North Sea and Central North Sea, and 31 offers in Tranche 3 across the Central North Sea, East Irish Sea and Southern North Sea) added about 600 million boe to 2060 at the margin, but cannot reverse the trajectory.

The reserves and resources position at end-2024 reflects the same story from the resource-base side: 2P reserves (proved plus probable) sit at 2.9 billion barrels of oil equivalent, 2C contingent resources at 6.2 billion boe, and 2024 production at 401 million boe combined oil and gas. At 2024 production rates, the 2P base represents roughly seven years of output; the 2C base depends on further appraisal and Field Development Plan consent before it can move into the 2P category. The Strategic Spatial Energy Plan being prepared by NESO with DESNZ (Methodology v1 published May 2025, pathway options to the Secretary of State in summer 2026, public consultation in early 2027 and final SSEP in autumn 2027) covers the 2030 to 2050 horizon and will set the spatial planning frame within which residual UKCS production sits alongside the build-out of offshore wind and hydrogen production.³

UKCS reserves and resources at end-2024

Four operating refineries serving road, marine and aviation fuel demand

The mainland refining footprint in mid-2026 is four operating sites, after Grangemouth and Lindsey both ceased crude refining in 2025. The footprint serves three primary demand sectors: road transport (petrol, diesel), aviation (Jet A-1 jet kerosene) and marine bunkers (Very Low Sulphur Fuel Oil and Marine Gas Oil), plus petrochemical and non-energy product slates. Combined capacity of the four operating sites is about 0.96 million barrels per day, against total UK refinery throughput in 2024 of 50.8 million tonnes. Throughputs typically sit at 70 to 90 percent of nameplate in steady operation, governed by the refinery margin (crack spreads), planned turnaround windows and seasonal demand pattern.¹

The mainland refinery footprint

The mix of products from each refinery is set by the configuration (catalytic reformer, fluid catalytic cracker, hydrocracker, alkylation unit) and the crude slate it processes. Fawley is particularly important for aviation because its jet fuel feeds the airfield-pipeline network that supplies Heathrow and Gatwick; Humber is the largest source of needle coke (used in steel-mill electrodes) in Europe. Pembroke and Stanlow between them carry the largest share of road fuel into the south-west and north-west road networks respectively. The Phillips 66 acquisition of the Lindsey assets closed on 28 April 2026 after Prax Petroleum's insolvency; Phillips 66 is integrating those assets into the neighbouring Humber refinery rather than restarting crude refining at Lindsey, so the Humber estuary now has one operating refinery rather than two.

Net crude imports rose to 19.7 million tonnes in 2024, the highest level since 2014. The United States overtook Norway as the largest single supplier for the first time on record, contributing 16.2 million tonnes (36 percent of the mix), with Norway at 13.5 million tonnes (31 percent), Saudi Arabia at about 3.0 million tonnes (7 percent) and Nigeria at about 2.7 million tonnes (6 percent). Russian crude has been zero since the statutory import ban took effect on 5 December 2022. Net finished-product imports cover the remainder of demand: the United Kingdom is structurally short of diesel and middle distillates, and structurally long on petrol after the decline of leaded petrol export markets in the 1990s and the rise of European diesel fleets.¹

The decommissioning pipeline and the OPRED regulatory regime

The Offshore Petroleum Regulator for Environment and Decommissioning is the DESNZ-housed regulator responsible for environmental consent, the abandonment programme and the OSPAR Decision 98/3 derogation regime that governs offshore disposal. The statutory parent is Part IV of the Petroleum Act 1998, which requires every licensee to prepare and submit a decommissioning programme on cessation of production, and to fund the works through Section 29 notices that survive any subsequent change of ownership. The North Sea Transition Authority's most recent industry cost estimate runs to 44.5 billion pounds across the UKCS to 2050; 2024 alone saw 2.4 billion pounds of decommissioning spend, the highest annual figure on record.¹

The shape of the pipeline reflects the maturity of the basin. Northern North Sea fields developed in the 1970s and early 1980s (Brent, Ninian, Magnus, Hutton) are the highest-cost decommissioning candidates because of the size of the topsides and the depth of the steel jackets; West of Shetland fields are dominated by Floating Production Storage and Offloading vessels rather than fixed platforms, so decommissioning routes through removal and redeployment rather than dismantling. Subsea infrastructure (pipelines, manifolds, control umbilicals) is governed by OSPAR derogation rules that allow leave-in-place in defined circumstances where removal would create greater environmental harm than retention.

The NSTA Asset Stewardship function runs alongside the OPRED environmental regime to ensure that decommissioning timing is set by the field rather than by the operator's portfolio convenience: under the Maximising Economic Recovery (MER UK) Strategy that took effect on 18 March 2016 under the Energy Act 2016, the Central Obligation requires relevant persons to take steps necessary to secure that the maximum value of economically recoverable petroleum is recovered from the strata beneath relevant UK waters, and the Asset Stewardship Survey and intervention powers let the NSTA hold operators to that obligation in practice.⁴

Decommissioning pipeline shape, NSTA estimate to 2050

The regulatory layer over decommissioning is denser than the licensing layer for two reasons. The first is that decommissioning interacts directly with the OSPAR Convention, the regional sea protection framework that the United Kingdom signed in 1992 and that constrains permanent disposal at sea. The second is that decommissioning is funded across multiple parties (current licensees, prior licensees under Section 34 notice continuity, and in some cases the Treasury through tax relief on decommissioning expenditure) and the regulator has to ensure that no part of the funding chain becomes structurally exposed if a current licensee is unable to meet its share.

Demand to 2030 and 2050 under the Future Energy Scenarios pathways

The Future Energy Scenarios 2025 publication on 14 July 2025 sets out three net-zero pathways and one counterfactual. Each pathway treats oil demand differently across the road, aviation, marine and petrochemical sectors, but every pathway shares the same direction of travel: road oil demand falls fastest under electrification, aviation falls slowest because the energy-density requirement for long-haul flight is the hardest to replace, and marine bunkers sit between the two anchored by the International Maritime Organization 2050 net-zero target and the European Union FuelEU Maritime fuel-intensity targets that apply to bunkers loaded for voyages to and from EU ports.²

FES 2025 pathway shapes for oil demand

The transformation waves that FES 2025 uses to time the build-out (Foundation through to 2028, Acceleration to 2032, Growth to 2040, Horizon to 2050) line up with the oil-side trajectory as follows. The Foundation wave is dominated by the SAF Mandate that commenced on 1 January 2025 (2 percent SAF by volume in 2025, rising on a fixed schedule), the Energy Profits Levy sunset on 31 March 2030 if not extended, and the completion of the major decommissioning programmes at Brent and a handful of other Northern North Sea fields. The Acceleration wave (2028 to 2032) lines up with the Clean Power 2030 target window for electricity, which removes the dispatchable-margin question from oil and so frees the policy debate to focus on transport and industry. The Growth wave (2032 to 2040) is when the SAF, hydrogen and synthetic fuel routes become decisive for aviation; the Horizon wave (2040 to 2050) is when residual oil demand falls to the low single digits of present-day levels across every credible pathway.

The Review of Electricity Market Arrangements Summer Update 2025 set Reformed National Pricing as the chosen electricity market structure and rejected zonal pricing; that decision interacts with the oil page indirectly through the cost of green hydrogen production at scale, which depends on the day-ahead and intraday electricity price that wind and solar projects achieve, and through the Strategic Spatial Energy Plan which will set the spatial frame for hydrogen production hubs and the SAF facilities that consume them.⁵ Demand-side modelling for oil in 2050 therefore traces back to two things: how fast road transport electrifies (the largest single demand sector today), and how quickly aviation and marine substitute toward SAF, electrofuels and ammonia (the residual that anchors the long tail).

Aviation and marine as the slowest-to-decarbonise demand sectors

Aviation and marine bunkers share three structural features that mark them as the slowest sectors to decarbonise. The first is energy density: jet kerosene at 43 megajoules per kilogram by mass and about 35 megajoules per litre by volume is hard to substitute, because batteries at current and projected energy density cannot lift a passenger aircraft on a long-haul mission. Liquid hydrogen has the mass density but not the volumetric density, which is why hydrogen aviation concepts cluster around regional and short-haul missions rather than the long-haul backbone. The second is fleet turnover: airliners and merchant ships have economic lives of 25 to 40 years, so a new propulsion technology takes a generation to spread across the existing fleet. The third is global pricing: fuel for international aviation and maritime bunkers is exempt from national fuel duty under international convention, which weakens the price signal that pulls the road sector toward electrification.

The policy response on aviation runs through two routes. The SAF Mandate (commencing 1 January 2025 at 2 percent SAF by volume and rising on a schedule that reaches 10 percent by 2030 and 22 percent by 2040) sets a demand obligation on fuel suppliers operating in the United Kingdom; the Revenue Certainty Mechanism that DESNZ consulted on in 2025 sets a supply-side support route for SAF producers, modelled in part on the Contracts for Difference structure that has underwritten offshore wind through Allocation Round 7 (8.4 gigawatts of offshore wind awarded on 14 January 2026 at record-low strike prices for a CfD round).⁶ The two routes together create a market for SAF that producers can finance against, while the SAF Mandate ensures that demand exists when the production capacity comes online.

The sustainable aviation fuel pathway has three main routes: HEFA (Hydroprocessed Esters and Fatty Acids, made from waste oils and fats), AtJ (Alcohol-to-Jet, made from bioethanol or biomethanol), and PtL (Power-to-Liquid synthetic aviation fuel, made from green hydrogen and captured carbon dioxide via Fischer-Tropsch synthesis or methanol-to-jet). HEFA dominates current production globally but is feedstock-constrained; AtJ scales with bioethanol availability and competes with biofuel use in road transport; PtL is the route with the largest theoretical headroom but depends on cheap green hydrogen at scale. The hydrogen page covers the upstream feedstock chain end to end; the cross-link sits at the bottom of this reference.²

Marine bunkers run through a parallel but distinct policy frame. The International Maritime Organization adopted the revised greenhouse-gas strategy in July 2023, with a net-zero target by or around 2050 and indicative checkpoints at 20 percent reduction by 2030 and 70 percent by 2040. The European Union's FuelEU Maritime regulation (in force from 1 January 2025) sets fuel-intensity targets on bunkers loaded for voyages calling at European ports, including United Kingdom calls under transitional arrangements. The substitute fuels available for shipping (LNG as a transition fuel, methanol from biomass or green hydrogen, ammonia from green hydrogen, electrofuels) each carry their own infrastructure and safety implications; container shipping is the leading sector for methanol orders, while bulk carrier and tanker operators are weighing ammonia and dual-fuel diesel options. The Grangemouth conversion to an import terminal under Project Willow includes a shortlist that covers SAF and eFuels, both of which would site at the existing tankage and jetty infrastructure on the Forth estuary.

The North Sea Transition Authority and its statutory remit

The North Sea Transition Authority is the arms-length regulator that took the licensing pen for the UKCS on 1 October 2016 (then as the Oil and Gas Authority) and rebranded as the NSTA on 21 March 2022. Its statutory remit covers production licensing under Part I of the Petroleum Act 1998, the Maximising Economic Recovery strategy under the Energy Act 2016, and carbon-storage licensing under the Energy Act 2008 as amended by the Energy Act 2023. The remit was widened in March 2022 to reflect the carbon-storage role, which is now a substantial part of the regulator's workload: the carbon-storage licensing rounds align with the Track-1 and Track-2 Carbon Capture and Storage cluster sequencing decisions made by DESNZ in October 2023 and July 2024.^{1 4}

The Wood Review published on 24 February 2014 was the analytical foundation of the modern regulator. Sir Ian Wood's central finding was that the United Kingdom was leaving recoverable reserves in the ground because the then-regulator (a directorate of DECC) was structurally too thin to drive the cooperation between operators that mature-basin production requires. The Energy Act 2016 implemented the recommendations: it created the OGA as an arms-length body with statutory powers, commenced the MER UK Strategy on 18 March 2016, and put a Central Obligation on every relevant person to take steps necessary to secure that the maximum value of economically recoverable petroleum is recovered. The Required Actions cover decommissioning planning, asset stewardship, technology adoption, infrastructure access, and operator collaboration.

The North Sea Transition Deal signed on 24 March 2021 sits alongside the MER UK Strategy as the second binding instrument. It set sector emissions targets (10 percent cut by 2025, 25 percent by 2027, 50 percent by 2030 against a 2018 baseline; net-zero basin by 2050), investment commitments of 14 to 16 billion pounds by 2030, and 40,000 jobs by 2030 across the five workstreams (supply decarbonisation, carbon capture and storage, hydrogen, diversification, people and skills). The supply decarbonisation lane is the most quoted but the people-and-skills lane is the largest single financial commitment, recognising that the supply chain that built the UKCS in the 1970s and 1980s is the supply chain that has to build offshore wind, hydrogen and CCS in the 2030s and 2040s.

The Centralised Strategic Network Plan that NESO submitted to Ofgem in January 2026 covers onshore and offshore electricity transmission, cross-border interconnectors, and hydrogen transport and storage; the first CSNP delivery is by end-2028, dependent on the Secretary of State's pathway decision under the SSEP. The CSNP is relevant to the oil page because the hydrogen transport and storage scope brings the gas-network operators and the NSTA into the same planning conversation: the strategic question is whether existing offshore pipelines decommissioned under OPRED can be repurposed for hydrogen transport rather than removed, and whether existing salt-cavern and depleted-reservoir storage can be repurposed for hydrogen storage at scale.¹

Where the oil page hands over to other parts of the workspace

The oil page sits at a hinge point between the upstream regulatory and infrastructure story and several downstream pathways, and a few cross-references are worth setting down explicitly. For the sustainable aviation fuel pathway, the upstream feedstock chain (green hydrogen production, carbon dioxide capture, Fischer-Tropsch synthesis or methanol-to-jet conversion) is covered on the hydrogen page, which sets out the production routes (electrolysis and steam methane reforming with carbon capture), the HAR1 and HAR2 award rounds, the hydrogen transport and storage infrastructure question, and the cost-and-scale assumptions that decide whether PtL SAF reaches commercial deployment in the 2030s.

For the electricity-side counterpart of the demand transition (the build-out that absorbs road transport demand off the oil page and onto the kilowatt-hour), see the electricity page, which covers the Capacity Market clearings for 2029 to 2030, the Allocation Round 7 results, and the 95 percent clean electricity by 2030 target. For the gas-side counterpart (the natural gas system that sits under domestic heating and industrial process loads, and that is partly substitutable by green hydrogen for both), see the gas page. For the regulatory frame (Ofgem, DESNZ, NESO and the licence regime that holds every limit), see the governance page. For the historical context that explains why the offshore industry sits where it does today (from the 1934 Petroleum Production Act through BNOC to the Wood Review), see the history page.