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By

Catherine McBride OBE

David Turver

Brian Monteith

Great British Business Council

March 2026

About the Authors:

Catherine McBride OBE

Catherine McBride is an economist specialising in trade. Catherine received her OBE for her work explaining economics and trade to both politicians and the public. Before working in trade policy, she was a derivatives trader covering global commodity markets from London. Catherine has written several think tank papers on economics, trade, and taxes; writes a Substack, Catherine McBride’s Substack; writes for the websites Briefings for Britain, Global Britain, and The Critic; and regularly appears on TV, radio, and podcasts.

David Turver

David Turver is a retired consultant, project management professional, and engineer who writes about net zero and energy policy. He is the author of the Eigen Values Substack.

Brian Monteith

Brian Monteith is a public relations consultant with over 40 years’ experience working domestically and internationally for both commercial and government clients, including assisting Nigeria with its submission to the Paris Agreement and the Scientific Alliance on challenging Net Zero policies. He has served in the Scottish and European parliaments and writes regular columns for The Daily Telegraph and The Scotsman newspapers.

About the Publisher:

The Great British Business Council

The Great British Business Council was established to enhance public and political understanding of the advantages a thriving business community provides to our security, standard of living and wellbeing. It aims to support British firms and small businesses by promoting well-crafted, practical, evidence-based policy reforms that foster enterprise and innovation. It is independent of any political party, as it hopes that all parties will consider adopting the straightforward, practical policy suggestions it proposes.

The GBBC is funded by private donations from concerned citizens who want the UK to thrive economically as it once did.

If you would like to join us or donate to our cause, please contact us at: [email protected] or follow us on LinkedIn, X, Facebook, YouTube, TikTok, Instagram, and Bluesky.

The 21 takeaways from this paper

1. Despite all the talk about electricity and renewables, almost 80% of UK Energy consumption comes from oil, gas and coal. Gas alone is 40% of total UK energy consumption. Yet we are deliberately replacing secure domestic production with expensive imports due to high taxes, reduced allowances, high carbon charges, and restrictions on finding and developing new oil and gas fields.
2. Gas security remains a real and immediate threat to the UK economy. The current conflict in the Persian Gulf, a recent cyclone in Northwestern Australia, and this summer’s scheduled maintenance of Norway’s pipelines and processing facilities will restrict global supply and push gas prices higher: increasing the UK’s trade deficit.
3. Oil and gas aren’t just fuel—they’re essential feedstocks for chemicals, plastics, pharmaceuticals, and fertilisers. High costs and green dogma are shutting down refineries and downstream industries.
4. Industrial heat for cement, glass, ceramics, aluminium, and steel comes from gas and coal (plus metallurgical coal for steel production). Carbon taxes and sky-high energy prices are driving up construction costs—making homes, infrastructure, data centres, and even wind turbine installation more expensive.
5. Scrap the taxes and regulations that limit UK oil and gas production, such as the Energy Profits Levy (windfall tax), the Oil and Gas Price Mechanism, the Carbon Price Support tax, and the restrictions on fracking, exploration and development of new fields. They are not part of the UK’s Paris Agreement commitments; removing them would reduce costs, revive industries, and boost domestic supply.
6. The UK government should copy Norway: encourage exploration and invest in offshore and onshore fields such as Lincolnshire’s Gainsborough Trough. The Norwegian government owns 67% of Equinor, the oil and gas major, and encourages exploration in the North Sea, enabling companies to continue finding new fields.
7. Coal remains the world’s #1 energy source. The UK has high-quality anthracite and thermal coal—mine it, export it, and build modern, clean coal plants for fast, firm power. Old mine waste holds rare earths and critical minerals—extract them.
8. Extractive industries: oil, gas and coal, as well as their downstream industries: oil refining, chemicals, plastics, and pharmaceuticals, have very high productivity – output per worker. Forcing these industries to close due to high corporate and carbon taxes on their production and necessary inputs has lowered total UK productivity and GVA, and devastated regional employment.
9. Britain’s top exports—fuels, chemicals, pharmaceuticals, vehicles, aircraft parts—rely on imported raw materials. Reducing the supply of North Sea oil and gas, taxing energy, and taxing imported raw materials makes UK goods less competitive in international markets, thus lowering UK exports and increasing the UK’s trade deficit.
10. The UK’s largest goods export sector: vehicles and aircraft parts, relies on large amounts of aluminium, which is produced using electricity and gas. But UK carbon taxes, high industrial electricity costs and environmental regulations have driven 95% of UK primary aluminium production out of the country.

UN emissions accounting treats a 30-year aircraft wing the same as a disposable drink can. This absurd equivalence punishes durable, high-value manufacturing.

• The UK cannot achieve Net Zero with the current technology – and the international accounting system for CO2 emissions excludes imported goods. The UK imported goods with 180 million tonnes of CO2 emissions in 2024, making a nonsense of the UK’s claims to have cut its emissions by 300 million tonnes.
• Imported goods may have higher emissions than UK-made equivalents, but are not counted as UK emissions under the UN system. As a result, shortsighted UK politicians focus only on territorial CO2 emissions and favour imports over domestically produced goods, ignoring employment, tax revenue, and export income.
• The EU’s Carbon Border Adjustment Mechanism (CBAM) will increase the cost of inputs for the UK’s complex goods, such as chemicals, plastics, pharmaceuticals, glass, ceramics, and vehicle and aircraft manufacturing. The EU’s CBAM only covers simple input products: iron and steel, aluminium, fertilisers, cement, hydrogen, and electricity. The UK is reliant on imported supplies of all of them.
• There is no single global oil price. Oil prices vary by grade, supply and demand, delivery cost, and insurance. North Sea Brent Crude is highly valued because it is a light, sweet oil, particularly suited to the production of petrol, diesel, jet fuel, and chemicals. We should not be leaving it under the North Sea.
• Natural gas prices vary with its composition, location and transport costs. North Sea gas fields connected to the UK via pipeline ensure dependable supplies. Converting gas to a liquid and transporting it is expensive, energy-intensive, and requires specialist plant. The UK does not have any plants to convert gas to LNG.
• Scrap the ZEV mandate, EV subsidies and fines imposed on car manufacturers for selling people the ICE cars they want to buy. Stop the time-consuming task of enforcing EV sales, focus on supplying urban chargers and let the market decide.
• Both major parties have deindustrialised Britain through energy taxes and environmental red tape. Reversing this may require exiting the Paris Agreement, the ECHR, and similar agreements. The US is moving that way—the UK should too.
• Financial and insurance rules should focus on real risk/reward—not hypothetical 100-year climate scenarios—unless the investment literally lasts 100 years. Company reports should focus on company results, not on Net Zero commitments.
• Award government and council contracts on ability to deliver—not Net Zero virtue-signalling. Scrap the requirements that demand contractors produce carbon-reduction plans, Net Zero commitments, and low-carbon specifications.
• Hydrocarbons are not going away. Data centres and AI will drive UK gas demand for dispatchable power from about 8 TWh to 26 TWh by 2030 (Oxford Economics). Demand for cement and steel needed to build data centres will explode too—production of both requires gas and coal. Leaving the UK’s oil, gas and coal resources in the ground is a self-inflicted economic disaster.

Executive Summary

The long day’s journey into darkness

• Britain’s journey towards Net Zero began with Margaret Thatcher warning of the danger of global warming in 1990, following which John Major signed the Rio Declaration in 1992. By 1997, the Blair Government adopted the Kyoto Protocol in 1997 and Gordon Brown passed the Climate Change Act in 2008.
• In 2019, Theresa May’s Government replaced the 80% CO2 reduction target with a 100% reduction by 2050. Irrespective of party colour, every government and regulatory authority has taken us further down the path of economic self-harm.

Accounting for dummies to justify catastrophic restrictions

• The internationally accepted way of calculating man-made emissions is nonsensical, and only by the adoption of technology not yet invented could the UK ever reach Net Zero emissions.
• The taxes applied to the oil, gas, and coal sector are draconian and Pigouvian in their obvious attempt to close down an industry that underpinned the entire UK economy.
• UK financial regulations are also devised to limit investment in, capital for and insurance of new oil and gas developments.
• UK Net Zero planning is imposed on all UK companies, adding to their costs, limiting their production and preventing them from applying for UK government contracts.

Futile self-harm on a massive scale

• Despite all the additional taxes and regulations on hydrocarbons over the last twenty years, 78% of the UK’s energy needs are still met by oil, gas and coal. Electricity accounts for only 22% of final energy consumption in the UK, and 31% of that was generated using gas in 2025.
• It is unfortunate that successive UK governments have chosen to encourage companies to import just under half of the oil the UK uses, half of the gas it uses, and almost 90% of the coal (mostly used for industrial processes).
• The UK also imports approximately 10% of its electricity. The UK is dependent on imports for more than 40% of its total energy, including 10% of its electricity, even though it has ample reserves of coal, oil and gas. This outcome also negatively impacts the UK’s balance of payments.
• The sum total of the UK’s pursuit of Net Zero CO2 emissions has been to offshore
• energy-intensive industrial production at the cost of 100s of thousands of jobs, billions of tax revenues, higher imports and lower exports.

Whistling against the wind

• Global CO2 emissions continue to rise by more than the UK’s total emissions, making the Net Zero imposition a futile act of self-harm.
• Global emissions are rising overall while UK emissions have remained nearly constant since 2022, resulting in the UK‘s share of global emissions falling from 1% in 2019 to 0.8% now. In short, the UK’s frugality is not affecting global emissions. It is just killing our industry, reducing high-paying jobs, with the country and its people all the poorer for it.
• Because Net Zero calculations do not include emissions used in making imported goods or the supply of imported hydrocarbons, there is a perverse incentive to shift the UK’s industrial production and supplies overseas. Successive governments have relied on offshoring to meet their CO2 emissions targets, without recognising the devastation it has caused to UK industry.

Abandoning our natural resources but burning everyone else’s

• Of 195 countries, Britain is one of only 40 with ample hydrocarbon reserves of coal, oil and gas – while over 100 have no hydrocarbons and the remainder have very small reserves.
• Oil and Gas is a significant but dwindling source of tax revenue, delivering £4.5 billion in taxes in 2024/25 – down 27% from £6.1 billion in 2023/24. Tax revenue is declining because tax rates are too high and allowance for exploration and development costs has been reduced. So producers are bringing forward decommissioning, lowering tax revenue even more.
• Offshore oil and gas are taxed at 78%: comprising 30% ring-fenced Corporation Tax (set separately from the main rate of Corporation Tax at 25%), 10% Supplementary Charge, and 38% Energy Profits Levy.
• 200,000 UK direct or indirect jobs provide an estimated gross value added (GVA) of £25bn/yr, with PAYE/NIC contributions likely to exceed an additional £1bn/yr.
• It is also estimated that unlocking additional resources from Britain’s coastal waters could add £150bn of gross value on top of the £200bn of economic value expected from current plans.
• While this resource is being left in the ground, the UK endures higher taxes and annual trade deficits. Meanwhile, we import the coal, oil, and gas we need while exporting industries and jobs to countries that are happy to let their manufacturers use them.

Norway profits while Britain pays

• In stark contrast to the UK, where new exploration and development have ceased, Norway has made two new discoveries in 2026 (thus far) that will deliver its energy and wealth.
• Norway’s Equinor announced a new find with preliminary estimates of recoverable oil equivalent amounting to 0.95–12.6 million barrels of oil equivalent.
• Although oil and gas companies in both the UK and Norway face a marginal tax rate of 78% and assess Scope 3 emissions, developers are not leaving Norway because it has created a predictable environment that rewards investment.
• Norway allows companies to deduct 100% of investment costs upfront (including exploration, R&D, financing, operations and decommissioning) and consolidate revenue, investment and losses between fields. Companies with no taxable income can receive cash refunds for losses, helping new and small operators to get started.
• Most importantly, Norway continues to issue new licences and encourage drilling: 2024 saw 42 exploration wells completed, resulting in 16 new discoveries; while 2025 saw 49 exploration wells bring 21 discoveries with 67 million standard cubic metres of recoverable oil equivalents.
• In 2025 alone, Aker BP found one of the largest commercial oil discoveries on the Norwegian Continental Shelf, while Equinor made two new discoveries of gas and condensate in Norway’s Sleipner area of the North Sea. There is no reason to believe that exploration on the UK side of the invisible border would not result in major new finds for Britain.

Onshore gas abundance and fracking dismissed – but imports welcomed

• As well as North Sea oil and gas, the UK has abundant conventionally drilled onshore oil and gas, including a giant Lincolnshire gas field, Gainsborough, that could fuel the UK’s entire needs for a decade, reducing dependence on imports and generating thousands of jobs.
• Deloitte estimated the Gainsborough Trough field could add up to £112bn to UK GDP, yielding £27bn in direct taxation and creating tens of thousands of jobs.
• Interestingly, using domestic UK gas would also reduce the UK’s CO2 emissions by 218 million tonnes compared with imported LNG.
• Separately, the British Geological Survey’s early assessment of fracking opportunities suggested UK shale formations might contain enough gas to supply up to 50 years of current UK demand – while a University of Nottingham study put the realistically recoverable resource at 10 years of current demand.
• It is inconsistent with environmental principles for the UK to leave its gas in the ground while importing LNG that has been fracked, purified, frozen, transported thousands of miles by oil-fuelled carriers, and regasified, or importing goods produced using coal in China or India.
• Before the US fracked shale boom resulted in its gas price falling by at least half, UK natural gas was cheaper. That advantage has not existed since 2010.
• US fracking caused gas production to increase by 36%, and prices fell. In the UK, production is restricted by limiting new well development, preventing fracking, and imposing massive additional taxes on oil and gas companies.
• Lower priced US gas not only reduced costs for US households and manufacturing but also fuelled economic growth. Cheap gas is credited with creating 725,000 jobs by 2014 and a 0.7% increase in US GDP by 2015.
• Cheaper fracked gas lowered US electricity prices; encouraged a shift from coal to gas production that cut the associated CO2 emissions in half; and helped the US trade deficit by turning the US from a net gas importer (Canadian gas and LNG from Qatar), to becoming the world’s largest exporter by 2023.
• Meanwhile, China, which depends on imported natural gas by pipeline and LNG shipping, has made major new shale gas discoveries in Xinjiang, adding to its reserves in Sichuan.
• Although these new finds are important, they will not significantly reduce China’s dependence on imported gas, as gas demand is growing faster than domestic supply. China consumes over 400 bn m3 of natural gas per year, of which 230-240 bn m3 is produced domestically, and 160-180 bn m3 is imported.

Endless restrictions, laws and legal challenges

• Even though Rosebank, the UK’s largest undeveloped oil field, was discovered in 2004, it took nearly two decades to receive government approval and its operation is still caught in legal planning challenges preventing its production some 22 years later. In the 1970s, oil and gas fields entered production within 5 years of discovery.
• Fracking for gas has endured repeated obstructions: the Johnson Government introduced a moratorium in 2019 (adding to existing moratoriums in Scotland and Wales); the Truss Government lifted it in September 2022; the Sunak Government reintroduced it in October 2022; now the Starmer Government intends to ban all oil and gas licences by law despite evidence of a gas field in Lincolnshire that would last for a decade.
• Some UK Ministers have claimed the Ministerial Code prevents them from breaking international treaties such as the Paris Agreement. The ministerial code is not a statute, however, and does not impose legal penalties. The Government removed the Code’s explicit reference to international law in 2015, which has weakened the obligation to comply with it.
• Most County Councils in England have declared a Climate Emergency and require that business tenders for council work include carbon-reduction plans, Net Zero Commitments, emissions reports, and low-carbon specifications. The Central Government also applies these requirements for major contracts worth over £5 million per year.

Petrochemical decline

• In the 1970s, the UK had 18 refineries; now it has only 4. Refining is a high-volume, low-margin industry that is vital to national energy security and to supplying petrochemical feedstocks to the chemical, pharmaceutical, and plastics industries – contributing £3.7 billion in direct GVA to the UK economy in 2019.
• Refining is highly productive – with only 12,000 direct employees in 2019, it supported over 100,000 supply-chain and related employment, and generated £5-£7bn billion in tax revenues.
• Since 2019, two of the UK’s six refineries at Grangemouth and Lindsey have closed, with the loss of 820 direct jobs. The closure of the Scottish refinery led directly to the closure of the nearby Mossmorran Ethylene plant and the loss of a further 180 direct jobs, as its feedstock had come from Grangemouth.
• The separate petrochemical and plastics site at Grangemouth remains open after £120m of support from the UK Government and £30m from the owner INEOS, but relies on imported ethane from US LNG, which is cheaper than UK naphtha.

Steel: priced out of existence

• The decline of British steel plants is not about Brexit. The closure of SSI Redcar in 2015, the reduction in production at Tata’s plants in Scunthorpe and Scotland since 2015, the mothballing and then closure of Liberty Steel, and Tata’s closure of its blast furnaces at Port Talbot in 2024 are all due to high UK energy costs, carbon charges, global competition from cheaper imports, financial instability, and the transition costs of moving from coal-based blast furnaces to electric arc furnaces (EAFs) have led to production closures in the UK.
• Scunthorpe’s blast furnaces survive with subsidies while the Government looks for a buyer.
• The UK is planning to replace its blast furnaces with electric arc furnaces (EAFs), but its high industrial electricity and Emission Trading Scheme (ETS) costs will make this technology uneconomic. Only UK Electric Arc Furnaces that receive government subsidies or have a contract to supply steel to the UK’s defence department are currently in business. As the UK has the most expensive industrial electricity in the world due to our carbon taxes, we should not be surprised if the EAFs replacing the UK’s blast furnaces also close in the UK.

Threatened aluminium and steel are at the heart of industrial exports

• The UK’s largest export industry, measured by value, is the production of Machinery and transport equipment.
• The UK has almost no primary aluminium smelting capacity left and produces only 5% of the aluminium it uses domestically. UK aluminium imports are used primarily in the manufacture of vehicle and aircraft parts. The UK government plans to implement a Carbon Border Adjustment Mechanism (CBAM) on imported aluminium in 2027, increasing the cost for downstream producers of vehicles and aircraft parts.
• Yet these products must remain competitive in global markets – 80% of UK-produced cars and almost all UK-produced aircraft parts are exported – or they too will join the UK’s industrial graveyard.
• The UK is the world’s largest supplier of aircraft parts, exporting 40% more than the second largest exporter, Germany, and almost twice as much as the US. The country cannot afford to lose this industry.

Rejecting our coal but exporting it to competitors

• The UK still has approximately 77 million tonnes of proven, economically recoverable coal reserves that could be profitably mined and a further 4 billion tonnes of known hard coal deposits, although not all are currently economically viable.
• Britain’s only remaining operational colliery is at Aberpergwm near Port Talbot, where a large proportion of its high-grade anthracite is exported.
• Another Welsh mine with workable reserves, Ffos-y-fran at Merthyr Tydfil, was recently closed following campaigning by anti-coal activists.
• A new metallurgical coal mine in Whitehaven, Cumbria, was approved in 2022 to supply the steel industry’s blast furnaces. Still, the High Court overturned its planning permission in September 2024, preventing it from proceeding.
• Coal is a vital component of industrial processes that require temperatures above 1,400°C: the UK consumed 2.1 million tonnes of coal in 2024 to produce cement, glass and ceramics.

There is a case for new coal-fired power stations

• Our gas power stations are ageing, and the last coal power plant was shut down in 2024.
• Using data from the Digest of UK Energy Statistics and assuming a 35-year life for our gas fleet, we can see that firm power capacity starts to fall from 43.5GW in 2027 to just 25.5GW in 2035 (or 28.8GW if Hinkley Point C is online by then).
• The National Energy System Operator expects both total electricity demand and peak demand to rise over the period to 2030 and beyond. We will become increasingly reliant on intermittent renewables, but their output can fall to almost zero at night or during calm periods. This means we will need reliable baseload capacity available to meet the shortfall.
• The UK will become increasingly short of reliable baseload unless new firm capacity is built quickly. New gas-fired power plants have an eight-year lead time, so even if we started building today, we would not get new capacity online before 2034. Thus, coal becomes a viable alternative, as it can be built quickly: construction times in China are under 2 years.
• Coal-fired generation is also cheaper than gas and intermittent renewables – if carbon costs through the Emissions Trading Scheme and Carbon Price Support mechanism are removed.
• Coal-fired generation is secure, especially if domestic coal is used. As recent events in the Middle East remind us, the security of LNG supply is subject to international politics, while the security of supply of intermittent renewables is subject to the whims of the weather.
• Coal-fired generation is reliable and flexible. Most coal is used as a constant baseload power source; however, newer plants can operate at lower minimum loads and flex up and down in response to changes in demand and the output of intermittent renewables.
• Storage of coal is cheap and easy. Sometimes intermittent renewables produce more power than demand, and at other times they produce less. While this problem can be partially solved by battery storage, it is very expensive. By contrast, coal can be stored in stockpiles near the power plant at very low cost – acting like a battery.
• The main objections to new coal power plants relate to emissions. If CO2 emissions are discounted due to the US removal of the greenhouse gas endangerment finding, that leaves real pollutants such as particulates, SOx and NOx to deal with. Fortunately, modern super-critical (SC) and ultra-super-critical (USC) plants in China have proven very effective at removing these pollutants.
• The benefits of coal-fired power plants are obvious, and the downsides of coal have been largely eliminated through technological enhancements. The case for coal is becoming increasingly hard to ignore.

Obtaining geostrategic security from domestic oil, gas and coal

• With UK import dependency rising from 40.3% in 2023 to 43.8% in 2024, energy security became central for the UK, especially after Russia’s invasion of Ukraine. Now, the US and Israel’s conflict with Iran has again made energy security front-page news.
• Some commentators correctly argue that reliance on imports exposes the UK to geopolitical and economic risks. They call on the government to balance energy security from domestic production with environmental sustainability and climate concerns.
• International economic theory assumes imports will always be available, and so it is economically rational to replace domestic production with cheaper imports, but this theory falls apart during an international supply squeeze, or when imported products are no longer available due to conflict (Qatari LNG), cyclones (Australian LNG), plant maintenance (Norway’s pipelines), or countries choosing to ban exports to ensure their own domestic supplies (the US 1975 to 2015).
• During the 2022 hydrocarbon price spike, following Russia’s invasion of Ukraine, the price of UK and EU gas rose to 10 times the US price. The Conservative government’s response was to add an additional 25% Energy Profits Levy (the windfall tax) on the UK oil and gas industry. The government claimed the levy would raise £15bn to subsidise UK gas consumers; this was entirely the wrong response.
• The only effective cure for high prices is to allow the price to encourage increased supply and lower demand. Instead, subsidising demand by taxing supply led to the opposite: people continued to use gas while suppliers produced less to avoid the extra tax.
• Consequently, UK production has continued to fall since the EPL (Windfall Tax) has been in place, and both the Conservative and Labour governments responded to the lower production by increasing the rate further from 25% to 35% and then to 38% – and extending the period over which the levy would be applied to 2030.
• To add to the absurdity of the UK’s windfall tax, the EU’s sanctions on Russian oil and gas never fully materialised; only some of the supply chains shifted. Russia continues to produce oil and gas, and the EU continues to import it, only sometimes indirectly.
• There would have been a massive geostrategic benefit if the UK had done the exact opposite to the Windfall Tax and instead lowered its taxes on UK oil and gas producers, encouraging them to increase production for domestic use or to sell to the EU, as most EU members have very little or no domestic oil and gas production.
• Germany did not even have an LNG terminal in 2022. It had to build some so it could import LNG from the US, while the UK, which is connected to the EU’s gas pipelines, acted as a land bridge for US LNG rather than selling our own UK gas to the EU.
• The Centre for European Studies identified that the Russian government invested £72 million in NGOs campaigning against shale gas. The former Secretary General of NATO, Anders Fogh Rasmussen, said the Russians, as part of a sophisticated disinformation operation, engaged actively with environmental organisations working against shale gas to maintain Europe’s dependence on imported Russian gas.
• The UK must take seriously the risk that Russia could stop selling hydrocarbons to its adversaries. Russia has supplied about 10% of the UK’s total oil and gas product imports. Norway, our largest supplier, provides about 37%, and the US supplies just over 10%.
• In 2021, we imported 5.7 million tonnes of petroleum oils from Russia. Over the 5 years before its invasion of Ukraine, Russia supplied between 15% and 26% of the UK’s refined oil imports.
• There is a valid reason for the UK to continue producing virgin steel to ensure supply for the UK’s defence, construction and transport industries. With Houthi rebels able to prevent cargo ships from passing through the Suez Canal with a handful of cheap drones and Russia unlikely to rest on its laurels if it defeats Ukraine, this is not a hypothetical threat.
• Closing the Suez Canal disrupts the supply of finished steel from China and India, as well as the supply of iron ore and coking coal from Australia. A permanent closure of the Suez Canal would raise the cost of supplies from North America and Brazil, as all European buyers would divert their purchases to the Americas. The only ways to avoid a shortage are to reopen the UK’s coking coal mines and import iron ore from Brazil or Canada.
• Recycling steel in the UK is not viable while UK industrial electricity is so expensive. This will be made worse by adding more wind turbines to the grid.
• Adding more gas-fired and coal-fired power stations will help, while we increase conventional nuclear production and deploy Small Modular Reactors or Thorium Molten Salt Reactors. These latter options will, however, take time to develop, so we should begin this process now.

New industries the UK will miss out on due to high energy costs

• The Labour government has placed significant faith in the development of green jobs in the AI and data centre industries. However, these industries require dispatchable power from gas, biomass, and nuclear sources. And they need it now.
• Unfortunately, the UK plans to add another 50 GW of intermittent offshore wind by 2030 and 70 GW of intermittent solar and onshore wind; none of these sources will produce the dispatchable, constant power required by AI and Data Centres. The UK will need to increase gas production to meet the required energy demand.
• The Construction of Data Centres requires large amounts of cement and steel. The American Cement Association predicts the US will need 1 million tonnes of cement by 2028 just for AI data centres. While a single hyperscale AI data centre requires up to 20,000 tonnes of Steel.
• The full deployment of pledged AI investment in the UK hinges on critical infrastructure upgrades, especially in energy supply, energy costs, and energy connections.
• The UK AI Energy Council projects a 20-fold increase in compute capacity over the next 5 years. Typical data centres can consume up to 100 MW per site, equivalent to powering 75,000 homes. Microsoft’s planned supercomputer alone will use 23,000 NVIDIA GPUs, requiring hundreds of megawatts of sustained power.
• In March 2024, Amazon bought a 960MW data centre powered by an adjacent nuclear station. Microsoft made a deal with US utility Constellation to restart the 835MW Three Mile Island plant to power its data centres. In late 2024, Sam Altman of ChatGPT proposed building massive 5GW AI data centres—each consuming about 1.5 times the output of the Hinkley Point C nuclear power plant under construction.
• Jensen Huang, President, Co-Founder, and CEO of Nvidia, has warned that UK electricity prices are the highest in Europe and that natural gas turbines will be required alongside nuclear power to meet AI and Data centre energy demand.
• The UK must upgrade its grid connection process to enable the rapid onboarding of high-demand data centres and reform planning laws and grid access rules to accelerate deployment. Microsoft cited the UK’s stable and open regulatory environment as a key factor in its investment decision, but also warned that planning and energy reforms, as well as regulatory stability in the oil and gas sector, are needed to increase investment in this area.
• Investment in AI and Data Centres is occurring as the UK mandates all new car purchases be electric and requires electric heat pumps for domestic heating. Meanwhile, grid connection bottlenecks are delaying critical infrastructure: more than 600 GW of proposed renewable energy generation projects are awaiting grid connection.
• The National Energy System Operator believes this backlog can be reduced to viable projects aligned with national priorities, including data centres, EV charging hubs, and heat pumps.
• The National Grid also requires an annual investment of £18.4 billion for infrastructure expansion, transmission, distribution, new interconnectors, substations, and digital grid upgrades, along with planning reforms for new nuclear and, possibly, new gas turbines.
• Instead of EVs, the UK could invest in Synthetic hyperdense hydrocarbon-based fuels and ultra-efficient ICE engines, which aim to improve fuel efficiency and reduce emissions.
• Ultra-efficient ICE engines are next-generation internal combustion engines designed to use all the energy in a litre of fuel by targeting very high thermal efficiency, advanced combustion strategies, and sophisticated turbo/supercharging. They are optimised for specific fuels made from hydrogen, ammonia blends, or tailored high-octane / high-cetane liquids.
• Considering the importance of vehicle, aircraft and defence manufacturing in the UK, it would be unwise for the UK to go all in on EV technologies when it lacks commercial battery production, while ignoring other developments such as ultra-efficient ICE engines and hyperdense fuels. Developing synthetic fuels plays to the UK’s strengths in Chemical manufacturing as well as vehicle and aircraft manufacturing.

Activists add to the cost of production and hold back UK GDP

• The Rosebank field was discovered in 2004, and it took nearly two decades to receive government approval in 2023. Environmental groups, such as Greenpeace and Uplift, played a pivotal role in challenging the approval.
• Drilling has been delayed because the Supreme Court’s 2024 Finch v Surrey County Council ruling required that all new UK oil developments take their emissions into account when assessing their environmental impact. The Scottish Court of Session upheld this ruling as affecting the Rosebank application retrospectively in January 2025. This ruling was upheld by the Scottish Court of Sessions in January 2026.
• Meantime, the Rosebank site had resubmitted its application, including emissions, in October 2025. The government has yet to make a final decision on whether to grant fresh approval for the projects, but has stated it is consulting on updated environmental guidance.
• Activist groups such as Stop Rosebank urged the public to inundate the earlier consultation with messages demanding that the project be halted, arguing that approving the field is incompatible with the UK’s legally binding climate goals and a liveable future.
• Incredibly, some activist groups are complaining that the delay will allow Rosebank to produce oil after the UK’s additional Energy Profits Levy of 38% has expired, thereby avoiding an exorbitant tax bill. But this is the result of the activists’ attempts to block the development.
• A group of activists worked to force the closure of the Ffos-y-fran coal mine. The group wants to ‘end coal use in power generation and steel production, coal extraction, and coal imports in the UK.’ Their website complains about CO2 emissions from ‘global steel production’ without noting that almost all virgin steel production is outside the UK.
• The closure of the Ffos-y-fran mine illustrates how Britain was de-industrialised by ‘all-purpose’ activists pressuring politicians. Neither the politicians nor the activists intend to live without the goods made from coal or steel, but they still want the mine closed for ideological reasons and don’t care if 180 miners lose their jobs.

Reversing Net Zero

• It is imperative we change course in energy policy if we are to preserve what remains of our oil, gas, and energy-intensive industries. Unfortunately, a wide array of legislation has embedded misguided climate and energy policies into law. All this legislation must be unwound, starting with regulations and taxes that reduce supply.
• The Energy Profits Levy: Priority must be given to the abolition of the EPL (Windfall Tax), as it was a temporary tax introduced to tax extraordinary profits resulting from the Russian invasion of Ukraine, and is not connected to the Climate Change Act, the UK’s Paris Agreement targets, nor any of the UK’s trade agreements.
• Oil and Gas Price Mechanism: The EPL was meant to be a temporary tax that ended in 2030. The Labour government intends to replace it with a permanent Oil and Gas Price Mechanism of 35% whenever oil and gas prices exceed $90 per barrel or 90p per therm. This tax is in addition to the 40% corporation tax levied on oil and gas producers, bringing their total tax rate to 75%. The OGPM ignores the fact that price spikes are generally caused by international shortages, and that encouraging increased production by lowering taxes could alleviate shortages for UK manufacturers and consumers.
• North Sea Future Plan: introduced in November 2025, these regulations effectively ended new offshore exploration licences and new onshore oil and gas licences in England. This policy must be reversed to enable the UK operators to find more oil and gas resources onshore and offshore, as Norway has done.
• Credit risk assessments, lending and investing: Removing the financial services requirement to integrate climate risks into credit risk assessments will lower funding and insurance costs for the energy sector. Bank lending, insurance, and pension fund investments should be based on a financial risk/reward basis over the life of the investment.
• Restart exploration and extraction licences: The UK should continue to issue exploration and extraction licences, requiring renewal at least every 5 years; unused extraction licences should expire, as current planning permissions for construction do.
• Simplify royalty charges on oil and gas extraction: High oil and gas taxation should be replaced with a simple royalty charge on extracted oil and gas on a volume or energy basis. Oil and gas company taxes and allowances should then be the same as those of all other industries, with exploration costs and other plant and equipment expensed immediately.
• Fracking moratorium / Petroleum Exploration and Development Licence (PEDL): Fracking is not tied to the UK’s international Climate Commitments or trade agreements. Reversal of the ban on onshore petroleum exploration and development licences could increase the UK’s gas supply and lower prices, as it has in the US. A new energy policy would lift the fracking moratorium and repeal any legislation introduced to prevent fracking.
• Encourage coal production for exports: Coal remains the world’s most used source of energy. The UK has large reserves of high-carbon anthracite and thermal coal, which should be used or exported. Domestic coal could also be used for back-up power stations for windfarms, as they are in China. The UK also has significant amounts of coal waste that should be processed to recover critical minerals.
• Simplify Environmental Impact Assessments: The EIA regulations, which require extensive analysis, consultation and mitigation before drilling can begin, should be reformed to make it easier to restart onshore and offshore exploration and development. Inclusion of Scope three emissions from new UK oil and gas production should be compared to the Scope 1, 2 and 3 emissions from imported oil and gas, given that the UK will continue to use imported oil and gas, which has a higher carbon footprint than that of domestically produced gas.
• Prevent Activists from blocking approved wells and fields. Other supply-side reforms would include making it more difficult for activists to block oil and gas fields that have been granted permission by the UK government
• Abandon the EV mandate. The UK should abandon its EV mandate for producers and its fines for the sale of excess ICE vehicles. The UK should stop subsidising EVs, but could continue to install charging access in street lighting for city dwellers without driveways. If people want to buy an EV, they can, but without subsidies or market-distorting fines. Removing the EV mandate will stop the decline in demand for petrol and diesel.
• Abandon the heat pump mandate: The majority of UK housing is too old to retrofit a heat pump without extensive and expensive additional insulation. If people wish to install a heat pump and their homes are sufficiently insulated for it to work, let them install and pay for it.
• Encourage Data Centres to build their own electricity supply using gas, coal or nuclear. Data centres transfer information at the speed of light and can be sited anywhere with cheap electricity. About 40%-50% of a data centre’s energy use is for cooling. Scotland or the Orkney Islands would be ideal locations – if they could generate electricity with North Sea gas.
• Carbon emission calculations: If the next government intends to continue with CO2 emission charges and taxes, then all emissions associated with goods production should be divided by the product’s life expectancy.
• Carbon Price Support Mechanism: The Carbon Price Support (CPS) Mechanism should be abolished. The CPS was introduced to discourage the use of coal in electricity generation; however, the last coal-fired power station closed in September 2024. This is an additional UK tax that is not applied by the EU and makes UK products uncompetitive in the EU. As the UK government plans to join the EU’s ETS, it would be unfair and anti-competitive for UK industries to continue paying both the UK’s CPS tax and the EU’s carbon tax.
• Abolish the Climate Change Levy: The levy is a tax on UK business use of electricity, gas and solid fuels designed to incentivise energy efficiency and is not tied to the UK’s Paris Agreement commitments or used to subsidise renewable electricity. CCL adds about 5%-7% to a typical non-domestic electricity bill and increases the electricity price by £7.75 per MWh. If carbon costs were removed, wholesale electricity prices would fall from December’s £78.45/MWh to just under £49/MWh, giving popular relief to businesses and households.
• Simplify Discounts for energy-intensive industries: Abolition of the CCL will remove the requirement for Energy Intensive Industries (EIIs) to apply for discounts by entering a Climate Change Agreement, reducing industry compliance costs and increase their profitability.
• Reduce curtailment payments: Curtailment payments are not embedded in renewable contracts and are not guaranteed revenue streams through their CfD or RO contracts. The new government should redesign the system to make new generators responsible for co-located storage and firm power obligations, as there is no contractual barrier preventing this.
• Carbon Reduction Plan: The requirement for government contractors to have a Carbon Reduction Plan before they can apply for government contracts should be dropped. Contracts should be awarded based on the ability to provide the services at an appropriate price.
• The long Run: the UK must leave the Paris Agreement, and the ECHR (for environmental reasons), as well as abolish the Climate Change Act, the Emission Trading Scheme, and cut renewable subsidies and curtailment payments

Chapter 1: The long day’s journey into darkness

Oil, gas and coal are the keystones of all industrial economies and the basis of the UK’s wealth. Closing these industries before there is a plentiful, inexpensive alternative source of industrial heat, transport fuel, electricity and hydrocarbon inputs for chemical processes is economically debilitating.

Even Dieter Helm, a former adviser to Boris Johnson on Net Zero, argues that the energy transition from reliable, cheap hydrocarbons to expensive, unreliable renewables is undoubtedly leading to ‘permanently high energy costs and diminished industrial competitiveness’.

Similarly, Sir Jim Ratcliffe, Chairman of INEOS, the UK’s largest chemicals business, adds that deindustrialising Britain is not reducing global emissions: “De-industrialising Britain achieves nothing for the environment. It merely shifts production and emissions elsewhere. The UK, and particularly the North, needs high-quality manufacturing and the associated manufacturing jobs. We are witnessing the extinction of one of our major industries as chemical manufacturing has the life squeezed out of it.”

The UK economy remains dependent on hydrocarbons, as acknowledged by the Department for Energy Security and Net Zero (DESNZ) in its 2025 Energy Brief. This paper examines how 78% of the UK’s energy needs are met by oil, gas and coal. Electricity accounts for only 22% of final energy consumption in the UK, and 31% of that was generated using gas in 2025, according to National Grid statistics. Unfortunately, successive UK governments have chosen to encourage companies to import just under half of the oil the UK uses, half of the gas, and almost 90% of the coal. The UK also imports approximately 10% of its electricity. The UK relies on imports for 43.8% of its total energy, even though it has ample reserves of coal, oil and gas.

All that the UK’s pursuit of Net Zero CO2 emissions has achieved is a fall in energy-intensive industries to the lowest level in 35 years, according to the ONS (see Figure 1). Industrial production, exports, economic productivity, and employment have all fallen as a result.

Figure 1: Output from UK energy-intensive manufacturing industries is at its lowest in 35 years

Source: ONS, GDP output approach – low-level aggregates from the ONS ()

Global emissions

In 2024, global emissions from man-made sources, hydrocarbons, and industry reached 38.6 billion tonnes, up from 38.09 billion tonnes in 2023. The year-over-year increase was 510 million tonnes, surpassing the UK’s total CO2 emissions from these sources, which were 312.91 million tonnes in 2024. Despite this, UK politicians believe that achieving Net Zero in the UK will impact global emissions and continue their quest to reach Net Zero by 2050.

In 2019, the UK accounted for 1% of global emissions; by 2021, this had decreased to 0.9%, and it currently stands at 0.8%. The reason? Global emissions are rising overall. UK emissions have remained nearly constant since 2022, whereas global emissions increased by 3% from 2022 to 2024. In short, the UK’s frugality is not affecting global emissions. It is just destroying our industry.

Figure 2: Annual CO2 emissions by region, Our World in Data

Figure 2 above shows that reducing UK emissions by closing extractive and downstream industries has not affected global emissions. Emissions have shifted from Europe and North America to Asia and continue to increase in line with manufacturing output.

As UK total emissions currently exceed 300 million tonnes and global emissions increased by over 500 million tonnes last year, the futility of the UK’s Net Zero exercise is becoming apparent to everyone. UK per capita emissions of 4.53 tonnes of CO2 per person are now just over half those of China (8.6 tonnes of CO2 per person) and below the global average of 4.73 tonnes of CO2 per person. See Figure 3, below.

Figure 3: CO2 emissions per capita for China, the UK and the World

Net Zero calculations for dummies

First, what does Net Zero mean?

The UK is trying to reach Net Zero CO2 emissions. It calculates net emissions as its production of CO2 equivalent emissions (CO2e) from electricity, heating, transport, industry, agriculture, waste, buildings, aviation and shipping, less the CO2 it removes from the atmosphere in forests, soils, peatlands, and engineered removals from carbon capture and storage and bioenergy with carbon capture and storage.

Unfortunately, the UK currently removes no CO2 from engineered processes such as carbon capture and storage (CCS), nor are there any other countries operating commercially sized direct capture of carbon dioxide from the atmosphere. There are systems for capturing and storing CO2 emissions from industrial processes and energy production, but only one company, Climeworks, in Iceland, is currently mechanically removing CO2 from the air and storing it in basaltic rock, capturing thousands of tonnes of CO2 per year rather than millions. Direct Carbon Capture and Storage is very energy-intensive and therefore very expensive in the UK, although possibly economic in Iceland, where power comes predominantly from geothermal sources.

Therefore, the only avenue available to the UK to reach Net Zero is to: increase energy costs through taxation, thereby reducing consumption by consumers and industries; encourage UK industry and extractive industries to relocate offshore; or pay farmers to turn productive farmland into forests and to re-waterlog drained peatlands.

Reforesting UK farmland and rewetting drained peatlands won’t be enough to meet the UK’s Net Zero Targets, nor would doing this make a difference to global emissions. UK forests currently sequester only 18 MtCO2/yr, whereas rewetting peatlands could reduce UK emissions by an additional 20 MtCO2/yr, and non-peat soil CO2 absorption could bring the total to 40 MtCO2/yr. Currently, only 13% of the UK’s landmass of 24.5 million hectares is forested. The UK would need twice its total land area, 54.5 million hectares, of only forest to absorb its current CO2 emissions. Short of leasing some land from Australia or Canada to plant forests, reaching Net Zero in the UK by tree somewhere else is a fool’s errand. Ironically, leasing land in Australia and Canada is not a joke, as it may appear. Several companies do this or sponsor other forestry programs in developing nations to claim zero emissions.

The UK government has bet the farm, literally and figuratively, on both outsourcing emissions and developing a mechanical method to capture and store CO2. And UK politicians have made this bet without questioning how the UK population will remain employed, or earn enough to pay for the food, energy and manufactured goods it will need to import.

Winning the UNFCCC’s climate accounting game

National emissions do not include emissions from: imported goods; the UK’s international investments; UK companies’ overseas factories; nor from international shipping and aviation not allocated to the UK. These exemptions have led successive governments trying to win the Net Zero accounting game to promote offshore production and discourage the extraction of UK oil, gas, and coal. Net Zero has become a game of point-scoring among governments that are concentrating solely on reaching their CO2 emissions targets for international recognition, without recognising the devastation they have caused to the UK economy as a whole.

How the UK reduced its emissions: the only things that made a difference

• Replacing coal-fired electricity with gas-fired electricity, as gas has about half the emissions of coal.
• UK methane emissions from the waste management sector decreased by 71% between 1990 and 2019. This was due to improvements in landfilling standards, changes in the types of waste sent to landfills, and increased use of landfill gas for energy. Methane emissions from landfills are one of the leading sources of global methane emissions, not burping cattle.
• Deindustrialising the UK by taxing and regulating emission-intensive industries until they moved their manufacturing out of the UK and then imported the goods they used to make. The UK imported goods, resulting in 180 million tonnes of CO2 emissions in 2023, 180% higher than in 1990. For the UK to claim it has cut its emissions by 300 million tonnes while importing goods that emit 180 million tonnes elsewhere is untenable. (See Figure 4, below)

Since 2019, the UK has lost an estimated 150,000 to 200,000 industrial jobs due to deindustrialisation and high energy prices, with the steepest declines in energy-intensive sectors such as steel, chemicals, ceramics, and paper. Manufacturing’s share of UK GDP has halved since 1990, from 16% to just 8%. Unsurprisingly, UK carbon dioxide emissions have also halved over the same period, not due to a successful Green transition but simple deindustrialisation.

Figure 4: UK imported emissions

Figure 5 below shows UK consumption emissions and UK territorial emissions. Rather than halving UK emissions since 1990, the UK has simply exported them. If we include the emissions associated with imported goods, the UK has reduced its consumption-related emissions (production plus imports) by 27% and its consumption-related emissions relative to its 1990 Paris Agreement emissions baseline by just 19%, not by the 50% that it claims.

Figure 5: UK emissions compared to the UK’s Paris Agreement 1990 baseline

This has made no difference to global emissions, as shown in Figure 6 below, but it has had a devastating effect on UK industry, manufacturing GVA, the UK’s trade deficit and its employment, as shown in Figure 1. In Figure 6 below, the UK’s emission reductions are barely visible relative to the increase in global emissions. UK cumulative emissions reductions since 1990 amount to 0.03% of cumulative global emission increases over the same period. Total UK reductions amount to just 290 million tonnes of territorial emissions since 1990, (excluding imports), while cumulative global emissions have increased by 1.07 trillion tonnes over the same period.

Figure 6: UK cumulative emissions reduction since 1990 compared to the global increase

Who sets the rules for Net Zero Accounting?

The United Nations and the Intergovernmental Panel on Climate Change (IPCC) established the rules for how and what is counted as a country’s emissions. The United Nations Framework Convention on Climate Change (UNFCCC) legally requires countries to produce national greenhouse-gas inventories in accordance with the IPCC Guidelines. This covers the gases that must be counted, which sectors must be included, how to measure emissions and removals, and how to treat land uses, forests, peatlands, agriculture, industry, energy, and waste. All countries must submit their greenhouse gas inventory to the UNFCCC. This is the legal basis for a country’s carbon budget and its Net Zero Accounting.

Although the Paris Agreement is a legally binding treaty under international law, adopted at COP21 and by the United Nations, it only obliges countries to submit a Nationally Determined Contribution (NDC) every five years. National CO2 emission targets are not legally enforceable, and there is no penalty for failing to meet an NDC. Another weakness of the Paris Agreement is that each country sets its own NDC emissions targets. The UK has slavishly adhered to the UN FCCC requirements, regardless of the devastation this has done to its economy, and met its NDC in 2020. However, China’s NDC was to continue increasing its emissions, with a soft target to reach peak emissions ‘around’ 2030. India signed the Paris Agreement without committing to cap its emissions at all. China and India were able to do so by claiming they remain developing economies. Although their per capita emissions may be lower than those of many Western nations, China is now the world’s second-wealthiest economy, and India is the fifth. Together, China and India accounted for 40% of global emissions in 2024, and this share is projected to continue to increase – even as signatories to the Paris Agreement.

To add to the absurdity of Net Zero accounting, the UN requirements do not include the 1kg of CO2 emitted per day by a human. The UK’s 68 million inhabitants exhale about 25 million tonnes of CO2 a year. China and India each have about 1.4 billion people, so human exhalation should add approximately half a billion tonnes of CO2 per year to each country’s total emissions. This exceeds the UK’s total emissions and equals last year’s global increase in emissions, yet it is not counted under the UNFCCC.

It is unsurprising that the United States, during President Trump’s first term, decided to withdraw from the Paris Agreement. The Biden administration rejoined in 2021, but the Trump administration’s State Department published in January 2026 a list of 66 international organisations it intends to leave, entitled ‘Withdrawal from Wasteful, Ineffective or Harmful International Organizations’. On the list are the UN Framework Convention on Climate Change, the Intergovernmental Panel on Climate Change, and the bodies of the Paris Agreement. Any new UK government should consider doing the same. Both President Trump and his Energy Secretary, Chris Wright, urged the UK to abandon its Net Zero program in speeches delivered at the World Economic Forum Annual Meeting in Davos this year.,

On February 12 2026, President Trump revoked the US Environmental Protection Agency (EPA) greenhouse gas endangerment finding, which removed the requirement for the EPA to regulate CO2 and other greenhouse gases, such as methane and water vapour, under the Clean Air Act. Treating CO2 as a pollutant has governed U.S. federal regulatory policy since 2009; the removal of the endangerment finding will reduce restrictions on U.S. power generators, oil and gas producers, heavy-duty trucking, manufacturing, and chemical production. Although some U.S. states have regulations that will prevent a wholesale industrial revival in the U.S., this change is something the U.K. should also be following.

The UK’s journey to industrial destruction

Politically, the UK has been moving toward the dismantling of its hydrocarbon extractive industries for many decades. Almost all post-war UK governments, including those of Harold Wilson and Margaret Thatcher, either closed down, increased regulations, or increased taxes on the industry as a whole or on parts of it. The only exception was the brief government of Liz Truss, which proposed lifting the fracking moratorium, but Rishi Sunak ousted Truss before it could take effect.

• Margaret Thatcher may have inadvertently started the UK’s pursuit of Net Zero when she warned the UN in 1990: ‘The danger of global warming is as yet unseen, but real enough for us to make changes and sacrifices.’ In her 2003 memoir, Thatcher expressed regret for the ‘apocalyptic hyperbole’ she had unleashed and lamented how the climate-change narrative had ossified into a ‘dogma’.
• Thatcher established the Hadley Centre for Climate Prediction and Research in 1990, which to this day produces the primary datasets for the Intergovernmental Panel on Climate Change (IPCC).
• The ‘dash for gas’, which took off in earnest in the early 1990s, was already reducing UK CO2 emissions, at no cost to consumers and long before the Climate Change Act.
• The UK Major Government signed the UN’s 1992 Rio Declaration, which consisted of 27 principles intended to guide countries in future sustainable development.
• The Blair government signed the 1997 Kyoto Protocol, committing the UK to reducing emissions. John Prescott was the UK representative at the 1997 Kyoto Protocol meeting and played a prominent role in negotiating the UK’s commitments within the EU framework.
• The EU introduced its Emission Trading System (ETS) in 2005. This was the world’s first large-scale international carbon market. The ETS requires power generators, heavy industry and intra-EEA aviation to buy allowances for every tonne of CO2 they emit. It also caps total emissions by limiting the number of allowances sold, with zero allowances sold by 2039.
• The Labour Government under Gordon Brown signed the Climate Change Act in 2008. Both the Conservative and the Liberal Democrat opposition parties claimed the target reduction was too low. Only five MPs voted against the bill in its second reading, and only three MPs, Christopher Chope, Peter Lilley and Andrew Tyrie, opposed it in its third reading.
• The Climate Change Act 2008 required the government to:
• reduce greenhouse gas emissions by 80% below 1990 levels by 2050
• reduce carbon dioxide emissions by 26% by 2020
• set out a series of five-year carbon budgets to establish the pathway to 2050
• prepare policies to keep emissions within these budgets
• introduce emissions trading schemes by secondary legislation
• publish regular reports on the risks to the UK from climate change and programmes for adaptation to respond to the risks identified
• The act established the Committee on Climate Change (now called the Climate Change Committee), an independent, expert body to advise the government on the appropriate level for the targets, budgets, and matters relating to mitigation and adaptation. The Committee was required to submit annual reports to parliament on progress towards the targets.
• The Labour government published its Low Carbon Transition Plan in July 2009.
• In April 2013, the Cameron/Clegg coalition introduced the Carbon Price Support tax to discourage the production of coal-fired electricity. This was in addition to the EU’s Emission Trading System.
• From September 2013, all UK-listed companies were required to report their annual greenhouse gas emissions in their directors’ report.
• In 2015, the UK, as part of the EU, signed the Paris Agreement, where the EU had agreed collectively to reduce its net GHG emissions by 55% from their 1990 levels by 2030. This was legally binding under EU law and included national and sector-specific targets.
• The Theresa May Conservative Government in 2019 amended the Climate Change Act by replacing the 80% reduction target with a 100% reduction by 2050. The amendment was debated in the House of Commons for less than 90 minutes and passed without a vote.
• From April 2019, the requirement for listed companies to report their energy use, their Scope 1 and Scope 2 emissions and their energy-efficient actions under the Streamlined Energy and Carbon Reporting (SECR) framework were introduced. It covered large unlisted companies, large Limited Liability Partnerships, and groups with two of either: turnover above £36m; 250 employees; or assets worth more than £18 million.
• Building on May’s policies, in 2019, the Boris Johnson Conservative Government further accelerated the UK’s path to Net Zero with its Ten Point Plan for a Green Industrial Revolution. The plan was slightly delayed by COVID-19 lockdowns, but in general, most of it remains in place and is being implemented, whether voters realise it or not.
• From November 2019, the Johnson Government initiated a moratorium on fracking in England in November 2019. Both Scotland and Wales had already placed moratoria on the process. The moratorium in England was issued by the Department for Business, Energy and Industrial Strategy, then headed by Kwasi Kwarteng, and supported by the Oil and Gas Authority.
• Having left the EU in December 2020, the UK set its own Paris Agreement emissions reduction target of 68% below 1990 levels by 2030. This is an extremely ambitious target, considerably higher than the previous EU target of 55%, and among the highest by any signatories to the Paris Agreement. It was set by Boris Johnson and the Business, Energy and Industrial Strategy Minister following advice from the Climate Change Committee. This target still stands.
• In December 2020, the UK-EU Trade and Cooperation Agreement (TCA) was signed. It included a commitment by the UK and EU to: carbon pricing; not weaken, lower, or reduce its environmental regulations and targets below those in place at the end of the transition period; and to continue to recognise international environmental agreements, including the UNFCCC.
• In January 2021, the FCA introduced the Climate Disclosure Rules for banks listed on the London Stock Exchange (LSE), requiring them to disclose their exposure to carbon-intensive sectors, their climate risk strategy and scenario analysis, including for a 1.5 °C and 2 °C increase in global temperatures. This regulation increased the costs of lending to high-emission companies.
• March 2021, the Johnson Government introduced the North Sea Transition Deal requiring early reductions in Offshore production emissions of 10% by 2025, 25% by 2027 and 50% by 2030 by electrification of offshore platforms, CCUS and Hydrogen.
• In 2021, the PRA introduced the Climate Risk Management Rules, which require banks to identify climate-related financial risks, assess exposure to high-emitting sectors, model transition risks, integrate these risks into their credit decisions and hold capital to cover material risks. This regulation increased the cost of lending to companies deemed to face climate risk.
• From March 2021, UK banks operating in the EU were required to comply with the EU’s Sustainable Finance Disclosure Regulations (SFDR).
• In April 2021, Bank of England Governor Mark Carney established the Glasgow Financial Alliance for Net Zero (GFANZ). The group included Banks (NZBA), Insurers (NZIA), asset managers (NZAM), Asset owners (NZAOA), investment consultants and financial service providers. The group required its members to commit to achieving Net Zero Scope 1, 2, and 3 emissions by 2050, including emissions from their lending, investment, and financing portfolios. Members were expected to phase out financing for unabated coal and new hydrocarbon expansion, and to increase financing for clean energy and transition activities. UK banks: NatWest, HSBC, Barclays, Lloyds and Standard Chartered all joined. UK Asset managers and insurers: Legal and General, Schroders, Aviva, Prudential and M&G also joined the group.
• In June 2021, the Bank of England launched the Climate Biennial Exploratory Scenario (CBES), commonly known as Climate Stress Testing. It required major banks and insurers to model their potential losses from possible climate change. This regulation also increased the cost of lending to high-emitting industries.
• In June 2021, the government introduced the Procurement Policy Note, which requires all applicants for UK government contracts worth more than £5 million to have a Carbon Reduction Plan.
• In December 2021, the FCA Climate Disclosure Rules were extended to cover asset managers, insurance companies, and FCA-regulated pension companies.
• In 2022, the Johnson Government introduced the temporary Energy Profits Levy (Windfall Tax) of 25% until 2025, which was an additional tax on oil and gas companies, bringing their total tax rate to 65%, but the Government continued the investment allowances of 29% to encourage new developments and an 80% decarbonisation investment allowance.
• Since 2022, under FCA Listing Rules LR 9.8.6, all main board LSE-listed companies must include in their annual report: governance of climate risks; climate-related strategy; Scenario analysis; risk management; metrics and targets for Scope 1 and 2 emissions and Scope 3 emissions if material.
• In June 2022, the Basel Committee on Banking Supervision (BCBS) introduced its Principles for the effective management and supervision of climate-related financial risks. These applied to all internationally active banks, which included almost all of the UK’s Banks.
• In September 2022, the then-Prime Minister, Liz Truss, announced that she would lift the fracking moratorium, arguing that a greater supply of domestic gas could improve energy security, despite her Chancellor, Kwasi Kwarteng, having imposed the moratorium three years earlier when he was the Minister for Business, Energy and Industrial Strategy.
• Truss’s replacement, Rishi Sunak, reinstated the fracking moratorium in October 2022.
• Sunak increased the EPL (Windfall Tax) to 35% in November 2022 and extended it to 2028, bringing the total tax rate on oil and gas companies to 75%.
• In May 2023, the UK-New Zealand trade agreement came into force and included extensive environmental compliance requirements and an agreement not to derogate from its environmental laws to encourage trade. The agreement also commits to reducing hydrocarbon use and to removing hydrocarbon subsidies that distort trade.
• In June 2023, Sustainable Finance was formally written into UK financial services regulation when the Financial Services and Markets Act (FSMA 2023) received Royal Assent. The Act introduced the UK’s first statutory sustainability-related duties for financial regulations, including a requirement for the PRA and FCA to support the government’s net zero and environmental objectives when making financial rules.
• In January 2024, the Sunak Government introduced the UK’s Zero Emission Vehicle Mandate with financial penalties for manufacturers who fail to meet EV sales quotas.
• In January 2024, the Sunak Government, under pressure from the industry, released 31 new licences which attracted 115 bids from 76 companies, despite the 75% tax rate. The licences were expected to produce about 545 million barrels of oil equivalent (MMboe) by 2050 and 600 by 2060.
• In February 2024, the Offshore Petroleum Licensing Bill mandates that the oil and gas regulator, the North Sea Transition Authority, hold annual licensing rounds for offshore petroleum production, subject to two tests being met. First, the carbon intensity of domestic natural gas is lower than that of liquefied natural gas imported into the United Kingdom. Second, the UK is expected to remain a net importer of both oil and gas. However, the bill lapsed after failing to pass before the end of the 2023/24 parliamentary session.
• From June 2024, UK companies with large EU operations or EU-listed securities must comply with the EU’s Corporate Sustainability Reporting Directive (CSRD)
• From June 2024, the Economic Regulation Act 2024 extended the duty to regulate for ‘Sustainable economic growth’ as defined in the FSMA 2023 to other regulators: Ofgem (energy), Ofwat (water), Ofcom (communications), ORR (rail and road), CMA (competition), Civil Aviation Authority, and the Payments Systems Regulator.
• In July 2024, the current Labour Government was elected, and in its first fiscal statement, the Chancellor, Rachel Reeves, increased the EPL from 35% to 38%, extended it to 2030 and removed the investment allowance of 29% and reduced the decarbonisation investment allowance to 66%. The Government announcement claimed these changes were not expected to have ‘any significant macroeconomic impacts and no impact on individuals, households or families’.
• In August 2024, the Labour Government ceased to grant new oil and gas licences but agreed to respect those granted by the Conservatives before they left office.
• In August 2024, the government announced that it would not defend the legal challenge brought by Greenpeace and Uplift against the approval of the Rosebank oil field and the Jackdaw gas field.
• In January 2025, GFANZ removed the requirement for its members to align with the Paris Agreement after threats of an antitrust suit by US legislators.
• In June 2025, the government published guidance requiring oil and gas companies to include Scope 3 emissions – those made by their customers while using their product – in their Environmental Impact Statements.
• The current Energy Secretary, Ed Miliband, announced in October 2025 that he would ban fracking by replacing the moratorium with a full legal prohibition. Miliband has committed to introducing legislation to end new onshore oil and gas licensing, including fracking licences.
• In November 2025, Chancellor Rachel Reeves announced that after the EPL expires in 2030, it will be replaced by the Oil and Gas Price Mechanism (OGPM). The OGPM is an additional tax of 35% applied to UK oil and gas firms operating in the UK and the UK Continental Shelf, and will be charged on the realised price a company receives above a threshold of £90 per barrel for oil and 90p per therm for gas.
• In November 2025, under political pressure and amid concerns about job losses, Ed Miliband, the UK Minister for Energy Security and Net Zero (DESNZ), introduced Transitional Energy Certificates, which allow limited new oil and gas developments if they can be connected to existing fields and pipelines.
• In November 2025, the North Sea Future Plan ended new offshore exploration licences and new onshore oil and gas licences in England. This prevents fracking anywhere in England under this policy.

The self-harm of high taxes on oil, gas, coal and electricity

Figure 7: Historic UK government tax revenues from oil and gas production

• The UK benefits from tax revenue from the oil and gas industry and from annual licence fees. The main taxes are:
• Ring-fenced corporation tax (RFCT) of 30%

These taxes are charged on ring-fenced profits from oil and gas produced in the UK and the UK Continental Shelf. Ring-fenced profits are those that cannot be reduced by losses from other parts of the company. This 30% tax rate was intended to ensure the UK government received a fair share of returns from the UK’s natural resources. The standard UK corporate tax rate is currently 25%.

• The Supplementary Charge (SC) of 10%

The 10% Supplementary Charge was introduced in 2016 and is also applied to ringfenced profits, but without a deduction for financing costs. However, the SC permits deductions for the Investment Allowances, Cluster Area Allowance, and Onshore Allowances. The Cluster Area allowance was introduced in the Finance Act 2015 and provides a 62.5% deduction on qualifying expenditure incurred in a designated Cluster area. So far, there is only one cluster area: the Culzean Cluster Area in the North Sea. The Onshore Allowance was introduced in the Finance Act 2014 to support the development of onshore oil and gas projects and allows 75% of capital expenditure to be deducted. The Investment Allowance is currently 62.5% of investment expenditure.

• Petroleum Revenue Tax (PRT)

Previously, a 50% Petroleum revenue tax was imposed. This is a field-based tax charged on profits from oil and gas production in individual fields that received development consent before 16 March 1993. With effect from 1 January 2016, the Petroleum Revenue Tax rate was reduced to 0%. Petroleum Revenue Tax is a deductible expense in computing profits chargeable to Ring Fenced Corporation Tax and Supplementary Charge.

• Energy Profits Levy (EPL) – ‘Windfall Tax’

Introduced following the Russian invasion of Ukraine as a temporary tax on the ‘Windfall profits’ of oil and gas companies. Originally set at 25% for 3 years, the EPL has been increased and extended twice and is now 38% through to 2030. After its expiry in 2030, it will be replaced by a permanent tax. The EPL will expire before 2030 if the 6-month average price for both oil and gas is at or below the Energy Security Investment Mechanism threshold of £71.40 per barrel of oil and £0.54 per therm for gas.

• The Oil and Gas Price Mechanism (OGPM)

The OGPM will be a permanent tax of 35%, applied to UK oil and gas firms operating in the UK and the UK Continental Shelf, and will be charged on the realised price a company receives above a threshold price of £90 per barrel for oil and 90p per therm for gas. The tax will be in addition to the ring-fenced 30% corporate tax and the 10% Supplementary Charge on ring-fenced profits paid by UK oil and gas companies. The threshold prices are not indexed and will be set manually by the government each year. The OGPM will become active if the EPL ends earlier than 2030 due to two consecutive quarters of low oil and gas prices.

• Oil and Gas levy, fees and rents

The UK Government also charges fees for onshore and offshore licences, the Oil and Gas Levy, which are paid annually to the North Sea Transition Authority (NSTA). The levy is paid by offshore licence holders whether the licence is in production or in pre-production. The Licences are granted for a 10 by 20 km offshore block. However, a licence does not confer consent; companies also need to obtain Exploration Well Consent, Field Development Plan approval, Production Consent, and pipeline works authorisation from NSTA before they start drilling. Companies also need to provide Environmental Impact Assessments, obtain Environmental Consents, and obtain Health and Safety approvals. The Government also charges fees for pipeline authorisations, offshore gas storage licences, CO2 storage licences and pollution prevention and control fees. The NSTA also charges fees for licence applications, drilling consents, pipeline works, consent to extend a licence, or amend a work program approval.

Other Carbon taxes

• Emissions Trading Scheme (ETS)

Certain companies must buy allowances to cover their CO2 emissions. Not all industries and activities are covered by ETS schemes. Emissions from energy use and industrial processes are generally covered, whereas emissions from administrative, office, and general business operations are not. For example, power generation from coal, gas, oil and biomass plants is covered by ETS, as are emissions from the production of steel, cement, ceramics, chemicals, pulp and paper, and aluminium.

• Carbon Price Support (CPS) tax.

The UK introduced the CPS in 2013, under the Cameron/Clegg coalition, to discourage the production of coal-fired electricity. This is part of the Climate Change Levy framework and only applies to industrial and commercial electricity users. The last coal-fired power plant closed in September 2024, so why is this additional £18 per tonne of CO2 still being added to industrial and commercial electricity bills? The Chemical Industry Association calculates this adds about £8 per MWh. The Centre for British Progress claims it increased electricity costs by more than £3.50 for every £1 it generates for the Exchequer in 2024.

• Climate Change Levy (CCL)

The CCL is a tax on business, agricultural, and public-sector energy use, but not on domestic energy use. The CCL varies by energy type and is charged on electricity, gas, and solid fuels: the current rates are £0.00775 per kWh for electricity, £0.00775 per kWh for gas, £0.02175 per kWh for LPG, and £0.06064 per kg for other taxable commodities.

• Electricity network balancing and curtailment costs (BSUoS)

UK industrial and commercial energy users typically see balancing, backup, and curtailment‑related charges adding 3–5% to their electricity bills, with BSUoS alone rising sharply and now costing businesses £15.69/MWh (1.569p/kWh) from October 2025 to March 2026. This was a 46% increase from the previous cost of £10.74/MWh. BSUoS is a significant cost for industrial users who may use 10GWh of electricity a year. An energy intensive industry is likely to use 100 GWh per year. Curtailment payments are compensation for energy generators when the grid asks them to reduce or stop electricity production. This is usually for wind energy.

Balancing is the process of ensuring that the energy supply meets demand at all times and that the grid frequency is maintained at 50 Hz. This requires payments to suppliers to increase production or decrease production as necessary.

• Contracts for Differences Levy (CfD)

Contracts for Difference were introduced in 2014 to provide low-carbon generators with stable, predictable revenues for project construction. The CfD sets a guaranteed price per MWh that the generator will receive regardless of the wholesale price. Generally, the CfD strike price is set well above the wholesale price to encourage new low-carbon electricity, but during the brief gas price spike caused by the Russian invasion of Ukraine, the wholesale price of electricity rose above CfD strike prices, forcing generators to pay suppliers. The total cost of CfDs was £2.6bn in calendar year 2025. This adds over £30 to domestic bills and also imposes high costs on non-domestic electricity users. The CfD levy is one of the largest non-commodity charges on commercial energy bills; there are no discounts for small companies, however, Energy Intensive Industries can receive an 85% exemption from the CfD levy. CfDs lower the cost of capital for low-carbon energy suppliers but increase electricity costs for everyone else.

• Capacity market

The Capacity Market is designed to ensure there is always adequate power during peak demand, when the wind drops, during a cold snap, or during an unexpected outage. Capacity agreements pay generators a fixed amount a year for the provision of energy during a ‘Stress event’. Costs are smaller but growing. The Capacity Market cost £1.3bn in calendar year 2024 and has already cost £1.4bn in the year to October 2025. The OBR forecasts the cost will rise to £4.4bn per year in 2030/31. In the price cap for Jan-Mar 2026, the Capacity Market adds about £24 to household electricity bills. Over the year as a whole, Capacity Market charges for businesses are in the £5-15/MWh range, although high users can face much higher seasonal charges during peak times. There are some exemptions for Energy Intensive Industries. A wiser approach would be to allow continuous, reliable gas-fired power, thereby avoiding the need for this charge.

• Transmission Network Use of System (TNUoS)

TNUoS charges are fees that recover the cost of operating, maintaining, and developing Great Britain’s high‑voltage electricity transmission network. This includes both onshore and offshore transmission infrastructure. TNUoS is a major component of electricity network costs, accounting for approximately £4 billion per year. TNUoS is expected to increase by 60% in 2026/27 to fund network extensions to connect Offshore wind and to reflect the new electricity transmission price control, which starts in 2026. The charge is set by the National Grid Electricity Systems Operator (ESO) by zone. The addition of Offshore Wind generators, located far from consumer demand, has increased transmission costs. Consumers, businesses, and households pay about 75% of the charge through their electricity bills, and generators pay the remaining 25%. TNUoS does not apply in Northern Ireland. Again, gas-fired electricity generators located near centres of demand would avoid the need for this charge.

• Distribution Use of System (DUoS)

These are charges for using the local electricity distribution networks — the lower‑voltage networks that take power from the transmission grid and deliver it to homes and businesses. The charges are set by each distribution network in accordance with Ofgem methodologies. Although electricity suppliers pay the DUoS this is then passed on to consumers.

• Renewable Obligations (RO)

The Renewables Obligations added £7.8 billion to UK electricity bills in 2024/5 and is projected by the OBR to cost £8.4 billion in 2026/27. For non-exempt large industrial users, this can equate to around £33/MWh. The RO scheme was designed to support large‑scale renewable electricity generation by requiring electricity suppliers to source a proportion of their electricity from renewable generators. It was introduced in 2002 and closed to new generating stations in 2017, but existing accredited stations still receive support. The Chancellor has now removed 75% of the RO costs from electricity bills and transferred them to general taxation.

• Feed-in tariffs (FiT)

The Feed‑in Tariff (FiT) scheme was a UK government support mechanism designed to encourage small‑scale, low‑carbon electricity generation. It ran from 2010 to 2019 for new applicants, but legacy costs will continue to receive payments for up to 20–25 years. The scheme supported technologies such as: rooftop Solar PV, Small‑scale wind, Hydro, Anaerobic digestion and Micro‑CHP. The £1.8bn annual cost of this scheme is passed on to other energy consumers through their bills.

• Nuclear Levy – Regulated Asset Base (RAB)

RAB is a funding model that allows a nuclear project to receive regulated payments from consumers during construction, thereby lowering financing risk and reducing capital costs. It is being used to fund Sizewell C and has been added to UK electric bills from November 2025. The levy will be applied per unit of electricity used, and the first levy rate has been set at £3.455 per MWh. Although Energy Intensive Industries (EII) are exempt from RAB costs, this increases costs for everyone else, especially non-EII commercial users.

• Tax exemptions and discounts

Energy Intensive Industries (EIIs) such as steel, aluminium, cement, glass, chemicals, fertilisers, chemicals, paper, plastics, ceramics and industrial gases receive partial compensation for the indirect ETS and CPS charges that are passed on in their electricity costs and a 92% discount on the CCL rate on electricity, a 89% discount on the CCL rate on Gas, a 77% discount on the CCL rate on LPG and an 89% discount on other energy commodities through the Climate Change Agreement (CCA) provided they meet certain obligations. But EII status does not exempt companies from paying the ETS, CPS, or CCL for their direct emissions. To apply for compensation, EII companies must demonstrate that they operate in an eligible product sector and that the price impact of the UK ETS and CPS on the business’s electricity costs, as a proportion of its GVA over a five-year average, exceeds 5%.

• Energy Intensive Industries Support Levy (ESL)

The ESL, introduced in April 2025, is designed to fund discounts on Network Charges for Energy-Intensive Industries by imposing additional charges on non-Energy-Intensive customers. The EII SL was introduced by the Labour Government and is designed to fund the Conservatives’ British Industry Supercharger. Network charges cover Transmission Network Use of System (TNUoS) and Distribution Use of System (DUoS) charges. These Network Charging Compensation (NCC) discounts are increasing from 60% to 90%3 from 1st April 2026, and the government is considering expanding eligibility to additional sectors. As more businesses qualify, the cost of the scheme will increase and be passed through to non-EII customers. The policy rationale was to help energy-intensive industries remain competitive internationally. However, shifting the burden to non-energy-intensive industries simply makes them less competitive. A better solution would be to make energy producers pay the Network Charge on a mileage basis.

How regulations choked off investment in oil, gas and coal

While the UK has not introduced any regulation that directly prohibits or caps lending to oil and gas firms, it has implemented a series of prudential, disclosure, and supervisory requirements that materially affect the cost and availability of capital for high-emission sectors.

UK and international financial regulations have led to higher borrowing costs, stricter collateral requirements, limited access to long-term debt, and increased due diligence requirements, thereby deterring new entrants to the UK oil and gas markets. While UK regulations do not explicitly prevent new entrants, the combined effect of prudential, disclosure, and market pressures creates a de facto barrier to entry for new developers. As do higher insurance costs and financial charges due to the Bank of England’s financial stress testing.

These measures – introduced by the Prudential Regulation Authority (PRA), Financial Conduct Authority (FCA), Bank of England (BoE), the Pensions Regulator and international bodies such as the Basel Committee on Banking Supervision (BCBS) – increase the capital intensity, reputational risk, and compliance burden associated with financing hydrocarbon activities. As a result, borrowing costs for new oil and gas developments have risen by an estimated 80–150 basis points, depending on project type and emissions profile. PRA rules require banks to hold additional capital against high-emission borrowers, potential stranded-asset risk, and transition risk. This adds up to 70 basis points to the cost of lending. The FCA’s climate-related financial disclosure requirements have reduced investor interest in long-dated loans to hydrocarbon companies, which is estimated to add 40 basis points to borrowing costs. The Bank of England’s requirement that banks conduct climate stress tests also increases margins and collateral requirements for lending to commodity companies. This adds another 30 to 40 basis points. In all, a new oil and gas development that previously borrowed at 7% may now face rates of 8% to 8.5%.

• Prudential Regulation Authority (PRA)

The PRA’s Supervisory Statement SS3/19 requires UK banks and insurers to manage climate-related financial risks by: Integrating climate risks into governance frameworks; Embedding climate considerations into credit risk assessment; Conducting scenario analysis; and holding capital commensurate with climate-related exposures.

• Bank of England (BoE)

Requires major banks and insurers to stress-test investment and possible portfolio losses under early-transition, late-transition, and no-additional-action scenarios.

• Financial Conduct Authority (FCA)

The FCA introduced mandatory climate-disclosure requirements for listed companies and regulated asset managers. These rules require disclosure of Climate governance, climate mitigation strategy, scenario analysis, and risk management, and the recording of their Scope 1 and 2 emissions, as well as Scope 3 emissions if significant. This last requirement would cover all oil, gas and coal companies in the UK.

• Basel Committee on Banking Supervision (BCBS)

The BCBS issued global principles for the management and supervision of climate-related financial risk requiring internationally active banks to: integrate climate risk into credit underwriting; assess exposure to carbon-intensive sectors; conduct climate scenario analysis; and adjust their capital ratios where risks are material.

• EU Sustainable Finance Regulations (Applicable to UK Banks with EU Operations)

Although the UK left the EU before these regulations took effect, UK banks with EU subsidiaries must comply with: the EU Taxonomy Regulation; the EU’s Sustainable Finance Disclosure Regulation (SFDR); and the EU’s Corporate Sustainability Reporting Directive (CSRD). These frameworks require detailed reporting on exposures to high-emission sectors and stranded-asset risks. The obligation to comply with the CSDR was recently removed by the EU for small and medium-sized enterprises.

• Glasgow Financial Alliance for Net Zero (GFANZ)

GFANZ membership is voluntary; however, its membership includes most of the UK’s major financial services companies. GFANZ required members to: commit to Net Zero by 2050; set interim targets for 2030; publish transition plans; and report annually on progress. Following U.S. antitrust pressure in 2023–2024, GFANZ removed mandatory Paris-alignment requirements in 2025. However, before this, GFANZ reduced investment in the UK’s emission-intensive industries.

• Carbon Reduction Plan for Government contract requirements

All applications for central government contracts worth more than £5 million per year, including VAT, must meet climate-related conditions set out in Procurement Policy Note (PPN) 06/21. Bidders must submit a Carbon Reduction Plan that reports their current greenhouse gas emissions for Scopes 1, 2, and 3, sets out specific carbon reduction measures, commits to reaching Net Zero by 2050, and follows the government’s technical standard for Carbon Reduction Plans. This is a mandatory condition of participation and must be met before the company’s ability to provide the tender requirements is evaluated. This is regardless of whether the tender is for construction work, defence projects or digital services.

• County Council’s environmental contract requirements

Most Country Councils in the UK have declared a Climate Emergency and require that environmental conditions be met in their procurement and contract work. This requires that business tenders for council work include carbon-reduction plans, Net Zero Commitments, emissions reports, and low-carbon specifications. This adds costs and complexity to tender documents, which disproportionately prevent SMEs from bidding. An example is the West London Low Carbon Procurement Policy adopted by eight London Boroughs. In contrast, the Central Government applies these requirements only to major contracts worth over £5 million per year.

• Some respite from the ‘Supercharger Package’

The Conservative government realised it was taxing industry out of the UK and introduced a package of capital allowances and tax incentives to accelerate private sector investment in manufacturing, energy infrastructure, industrial decarbonisation, and R&D and plant upgrades. The scheme was published in April 2025, just months before the election was called. It allowed 100% deductions from taxable profits in year one, full expensing of plant and machinery investments and 50% first-year allowances for long-life assets such as pipelines, energy networks, industrial furnaces and CCS infrastructure. The Current Government has retained full expensing for plant and machinery, manufacturing equipment and industrial upgrades, as well as the 50% first-year allowance for special rate assets such as pipelines and CCS infrastructure. But it has shifted away from CCS, Hydrogen, and energy infrastructure towards green manufacturing, grid build-out, planning reform, and public investment via the National Wealth Fund.

Net Zero nonsense undermines UK growth, employment and revenue

The UK economy still relies heavily on oil and gas, which are used as industrial heat sources and as inputs for chemical, pharmaceutical, and plastics production, domestic heating, transport, and electricity generation.

The constant changes in regulation, taxation, and licensing approvals, as well as increasing financial costs, have caused UK oil production to decline by 40%, from 52.9 million tonnes in 2019 to 30.7 million tonnes in 2024, and UK gas production to decline by 21%, from 436,566 GWh in 2019 to 343,858 GWh in 2024. This significant decline was not due to greater technical difficulty in extraction or scarcer resources – but a change in the political policies. Despite this, according to DUKES, the UK still relied on coal, gas and oil for 75.2% of its primary energy consumption in 2024.

Tax revenue from the sector has declined in tandem with production. The OBR forecast in November 2022, after the EPL was introduced, that government oil and gas revenues from the Ring Fenced Corporate tax, the Supplementary Charge, the Petroleum Revenue Tax and the Energy Profits Levy would be £14.9 billion in 2022/23 and £20.7 billion in 2023/24. Instead, only £9.9 billion was raised in 2022/23 and £5.5 billion in 2023/24. In November 2025, the OBR’s forecasts were much more modest: £2.7 billion in 2025/26, £2.4 billion in 2026/7, £2.0 billion in 2027/8, and £1.6.3 billion in 2028/9, £1.2 billion in 2029/30 and a mere £0.3 billion in 2030/31. But even this estimate is now considered too high by the OBR, who, in their March 2026 Economic and Fiscal Outlook, expect all UK oil and gas production to have ceased by 2030 as the EPL and additional licensing requirements are discouraging new well development. HMRC has published the EPL figures for the financial year 2024/25; they have fallen to just £2.7 billion, a drop of £870 million from 2023/24.

One of the benefits of the OBR’s pessimistic forecasts, that the UK will receive a mere £100 million in tax revenue for all oil and gas production taxes in 2029/30 and 2030/31, is that there can be no possible complaints from HMRC that removing the Energy Profits Levy will reduce Government revenues. Even for 2028/29, the OBR is only forecasting oil and gas tax revenues of £200 million. Scrapping this counterproductive ‘Windfall tax’ will not be a ‘cost’ to the treasury, based on the forecasts shown in Figure 8, below.

Figure 8: OBR forecasts of oil and gas tax revenues, March 2022 to November 2025

Oil and gas companies are scaling back and cancelling investments in the UK. Some companies have announced they will quit the UK North Sea basin completely due to fiscal ‘unpredictability’. According to Offshore Energies UK, the UK is projected to lose £12 billion in tax receipts due to declining output, a figure that will be exacerbated by capital investment falling from £14 billion to just £2 billion between 2025 and 2029. Job losses are expected to be around 35,000.

Also at risk is the oil refining industry, which contributes £3-£4 billion per year to UK GVA and supports over 100,000 jobs directly and indirectly through its supply chain.

Unfortunately, both the Conservative and the Labour governments considered the Energy Profits Levy, or Windfall Tax, a good idea. Under a different tax and regulatory regime, the UK could at least be self-sufficient in fuels and chemicals, or even a net exporter – as it previously was.

Some Ministers have claimed that the Ministerial Code prevents them from breaking international treaties such as the Paris Agreement. However, the Ministerial Code is not a statute and does not impose legal penalties. The UK Ministerial Code is an ethical code of conduct, not a law. It explicitly states that Ministers have an overarching duty to comply with legal obligations arising from domestic and international law. The Government removed the Code’s explicit reference to international law in 2015, which is believed to have weakened the obligation to comply with it.

Chapter 2: The UK’s bountiful natural resources

Britain is one of only 40 countries with ample hydrocarbon reserves: coal, oil and gas. There are over 100 countries with no hydrocarbons and another 75 with very small hydrocarbon reserves. Japan, for instance, is a G7 country with little to no hydrocarbon reserves; its biggest imports are oil, LNG and coal. Germany has some hydrocarbons, mainly low-quality coal, but must import crude oil, natural gas, refined oil, and coal.

Figure 9: UK Production of coal, crude oil and natural gas

Revenue

In 2024/25, the UK government earned £4.5 billion in taxes from the North Sea oil and gas sector: £2.0 billion in Offshore Corporate taxes, £0.4 billion in repayments from the Petroleum Revenue Tax, and £2.9 billion from the Energy Profits Levy (Windfall tax). Total tax revenue from the sector fell from £6.1 billion in 2023 to £ 4.5 billion in 2024, a reduction of £1.6 billion (27%).

Offshore Corporation Tax receipts, comprising Ring Fence Corporation Tax and Supplementary Charge, were down £1.0 billion (34%) from £3.0 billion in 2023/4 while the Energy Profits Levy receipts were down £0.7 billion (20%) from £3.6 billion in 2023/24.

For comparison, Norway will collect NOK 373.1 billion in oil and gas taxes in 2025, equivalent to around £28.8 billion. If we include Norway’s States Direct Financial Interest (SDFI) income, environment fees, and Equinor dividends, the total Net Norwegian government petroleum cash flow in 2025 was NOK 655.8 billion (£50.7 billion). We discuss Norway’s more favourable approach to oil and gas taxation and regulations later in this chapter.

UK Offshore oil and gas is taxed at 78%, comprising 30% ring-fenced Corporation Tax (set separately from the main rate of Corporation Tax at 25%), 10% Supplementary Charge, and 38% Energy Profits Levy. The ring fence prevents taxable profits from oil and gas extraction in the UK and UK Continental Shelf from being reduced by losses from other activities or excessive interest payments.

Gross Value Added (GVA)

Offshore Energies UK estimates the industry adds £25 billion in gross value annually, implying several hundred million pounds in employee-related tax receipts. Unlocking additional resources from waters around the coast of Britain could add £150bn of gross value to the UK economy, on top of the £200bn of economic value expected from current plans. Oil and gas continue to account for over three-quarters of UK energy use, underscoring the industry’s continuing importance even as the transition to alternative sources accelerates.

Employment

According to Offshore Energies UK, in 2024, the offshore oil and gas sector supported 206,000 jobs, with 26,000 direct jobs within the oil and gas sector itself and a further 94,500 indirect jobs and 85,100 induced jobs spread across the country. These 200,000 jobs provide an estimated gross value added (GVA) of £25bn/yr. Based on salaries of between £50,000 and £80,000, their PAYE and NIC contributions were likely to exceed £1 billion annually.

In the third quarter of 2025, the Mining, Energy, and Water Supply workforce was 582,000, representing 1.7% of the total UK workforce of 34,216,000. Although this accounts for less than 2% of the UK workforce, it is one of the most productive sectors of the economy and also provides the raw materials needed by other industries.

The UK oil and gas workforce is forecast to decline sharply to 57,000–71,000 by the early 2030s due to reduced exploration and production. Historically, the sector supported 220,000 jobs across the UK (including direct, indirect, and induced employment), but this figure has been falling steadily since its peak in 2014. It is estimated that the oil and gas mining sector loses 400 jobs every fortnight.

Regional employment

Scotland accounts for the majority of UK oil and gas jobs, particularly in Aberdeen and the Northeast. In 2022, approximately 93,600 jobs in Scotland were supported by the oil and gas industry, including direct and supply-chain roles. More recent estimates suggest 75,000 jobs in 2024, with projections of 45,000–63,000 by the early 2030s if the decline continues.

Exports and Imports

Despite the UK’s devotion to ‘green’ policies, the UK has not stopped using oil and gas; between November 2019, when the fracking moratorium was imposed, and Dec 2025, the UK imported gas worth £125 billion, crude oil worth £136 billion, and refined oil worth £132 billion in refined oil over the same period, according to the ONS. In 2025, the UK had a trade deficit in SITC 3 Fuels of £32.3 billion; prior to 2003, UK fuel trade was in surplus.

SITC 3 Fuels are the UK’s fourth-largest goods exports. However, since 2019, using ONS Chained Volume Measures (CVM) to account for inflation, Fuel exports have fallen by 23%, and the UK trade deficit has continued to grow. The UK’s trade deficit in Fuels continues to grow, now amounting to £32.3 billion. Yet in 2019, the UK’s fuel trade deficit was just £9.4 billion. This fuel deficit is not due to ‘Brexit’, as many commentators claim, but to successive UK Governments’ policies towards oil and gas.

Having once been a net exporter of oil and gas, the UK is now a net importer of both. Net imports of primary oils increased by 12% in 2024, to reach 20 million tonnes, and net imports of natural gas increased by 4.9% to 335 TWh due to declining domestic production. According to the Digest of United Kingdom Energy Statistics (DUKES), UK fuel import dependency in 2024 increased to 43.8%, up from 40.3% in 2023. (DUKES published 31 July)

Decommissioning

In July 2025, the North Sea Transition Authority estimated that total industry costs for decommissioning all UK upstream oil and gas infrastructure from 2023 onwards would be £41 billion at 2021 prices. HMRC estimates it will make £5.8 billion in tax repayments associated with this decommissioning expenditure, in present value terms, as set out in HMRC’s Annual Report and Accounts. In addition, there is an estimated £5.9 billion of foregone Offshore Corporation Tax revenue. This is because decommissioning expenditure reduces company profits, thereby lowering the overall tax take. Combined, the total cost to the Exchequer from this expenditure is estimated to be £11.7 billion in present value terms.

Moreover, significant technical expertise in the exploration and production of oil and gas resources, including drilling techniques, reservoir management, and production optimisation, is being lost. Losing this expertise will disadvantage the United Kingdom and make reopening the North Sea more difficult and expensive in the Future. Additionally, drilling rigs and exploration equipment are being moved to countries with a more welcoming attitude to the industry.

The Energy Profits Levy (Windfall Tax) has prompted many companies to halt investment in the UK and to move or reduce their UK workforce. Harbour Energy, an independent producer, announced in December 2025 that it expects to reduce its UK workforce by another 100, in addition to 600 jobs eliminated since 2023.

According to the World Energy Statistical Review, the United Kingdom produced 778 thousand barrels per day of crude oil in 2022, a decrease of almost 11% from 2021. The primary reasons for this decline are reduced exploration and development in the North Sea due to regulatory, taxation, and other financial costs associated with developing new fields.

The UK oil and gas market is dominated by large multinationals, including Shell PLC, BP PLC, TotalEnergies SE, Chevron Corporation, and Cadent Gas Ltd. These companies have other, less physically and regulatorily onerous fields to develop. Another hurdle the review identifies for new UK oil and gas developments is competition for capital investment from the UK renewables industry.

In 2024, operators spent a record £2.4 billion on decommissioning, with total spending projected at £27 billion between 2023 and 2032. BDO reported that decommissioning expenditures are expected to exceed capital expenditures by 2029, reflecting a structural shift in priorities.

Figure 10: UK Crude Oil Production, Exports and Imports

Offshore oil production

The UK’s remaining proven and probable North Sea oil and gas reserves were estimated at 2.9 billion barrels of oil equivalent (boe) at the end of 2024. This figure represents the combined oil and gas, with approximately 70% oil and 30% gas. Discovered but undeveloped petroleum resources amount to 6.2 bn boe and could be developed through investment.

Working oil and gas sites include:

Abigail Field: This field, located off the east coast of Scotland, was approved by the UK government’s Oil and Gas Authority in January 2022. The field is estimated to contain 5.5m boe, with the oil and gas split evenly. Despite complaints from Uplift and Friends of the Earth Scotland, the field is in production, producing 15.17 million m3/year in 2022 and 0.26-1.1 million bbl/year of oil.

Brent oil field: located east of the Shetland Basin, about 186 km northeast of Lerwick. It was discovered in 1971 and was in production by 1976. It is operated by Shell and was one of the largest hydrocarbon accumulations in the UK North Sea. It has produced around 4 billion barrels of oil equivalent (boe). Many of the platforms have been decommissioned.

Clair: The largest oilfield on the UK Continental Shelf, with an estimated 8 billion barrels of oil-in-place. It is located 75 km west of Shetland and operates in phases, including the Clair Ridge development, which began producing in 2018.

Forties oil field: the UK’s second largest North Sea oil field, located about 110 miles off the coast of Aberdeen. Discovered in 1970, it began production in 1975, and its total estimated resources are 5 billion barrels of oil, with a proven, recoverable reserve of about 175 million barrels. In 2025, current production was about 10,000 boe per day.

Magnus Field: 160 km northeast of the Shetland Islands, is one of the UK’s most northerly and active fields. Run by EnQuest, it produced 16,800 barrels/day in April 2025. Additional infill wells are planned to come on line. It was discovered in 1974, began production in 1983, and is estimated to contain a total of 1.54 billion barrels, of which 869 million are thought to be recoverable.

Kraken: Is a rare North Sea oil field that produces heavy sour crude. It is operated by EnQuest. It began production in 2017, its estimated reserves are 137 million barrels of heavy oil, and it is expected to produce 50,000 barrels/day at its peak. Karen oil is very heavy with an API gravity of 14o to 16o, with high viscosity and high sulphur. Karen has to be exported to Europe, Asia or the US Gulf Coast be refined as the UK’s refineries are set up to handle Light Sweet Brent Crude (API 38o to 40o).

Nelson Field: is in the Central North Sea, 200 km east northeast of Aberdeen. It is operated by Shell, produces a light sweet crude, and is still in production, but is decommissioning some topside equipment.

Ninian Field: is about 100 miles northeast of the Shetland Islands. Operated by Canadian Natural Resources, it produces both oil and gas, with a production of about 3.9 million cubic feet/day in 2019. The field was originally a major oil producer.

Schiehallion Area (Schiehallion, Loyal, Alligin): Located 175 km west of Shetland, this area is redeveloped and serviced by the Glen Lyon floating production, storage, and offloading (FPSO) vessel.

Figure 11: UK Crude Oil Production showing the drop since the Climate Change Act

Oil and gas reserves

Some government advisers and climate activists claim that the UK has run out of oil and gas, but this is not true. The North Sea Transition Authority (NSTA) estimates that the UK has discovered but undeveloped resources of 6.2 billion boe, developed resources of 3.1 billion boe, and prospective resources in mapped leads of about 4.6 billion boe, as well as an additional 11.2 billion boe of prospective unmapped resources. However, oil companies have been deterred from exploring additional sites by the successive UK governments’ extortionate tax rates and irrational attitudes toward new oil and gas developments. The UK’s court system is an additional deterrent, as activist groups have been able to hold up production even after fields have received government approval. The Cambo, Rosebank and Jackdaw sites are examples.

In contrast to the OBR’s pessimistic predictions, a report by Mordor Intelligence estimates the United Kingdom’s oil and gas market at USD 323.83 billion in 2025 and projects it could reach USD 346.29 billion by 2030, at a CAGR of 1.35% over the forecast period (2025-2030).

The report notes that although reserves have declined, they still constitute a substantial resource base that requires ongoing exploration and production. The well-developed infrastructure for offshore exploration and production, including offshore platforms, pipelines, and storage facilities, provides a competitive advantage for upstream companies, enabling efficient extraction and transportation of oil and gas resources.

Unfortunately, when the Labour Government extended the Energy Profits Levy (EPL) to 2030, it also scrapped Investment allowances from the EPL, including the levy’s main 29% investment allowance for qualifying expenditure incurred after November 2024. This reduced the incentive for reinvestment in oil and gas projects. Instead, UK North Sea operators are resorting to mergers and acquisitions rather than new developments. Business groups warned that the EPL is a barrier to investment and growth, accelerating job losses and deterring capital.

Due to the fiscal turmoil in recent years, 2025 was the first year since 1960 without a single exploration well drilled in the UK waters, according to the energy consultancy Wood Mackenzie. 2025 was described as the toughest year for the UK North Sea since the 1960s, with investment collapsing to historic lows. Companies froze or cancelled projects, focusing only on essential maintenance and decommissioning. Field life extension dominated the remaining investment. Offshore Energies UK warned that the government’s decision to maintain the EPL unchanged until 2030 effectively turned down £50 billion of potential investment.

Meanwhile, forecasts suggest capital expenditure will decline by 26% over the forecast period, with production projected to fall by 6–9% annually. The lack of fiscal predictability and a high tax burden have driven companies to redirect investment to more favourable jurisdictions, such as Norway, on the other side of the North Sea. Norway continues to attract exploration capital, unlike the UK, where decommissioning expenditure is rising sharply.

Major UK oil and gas reserves:

Undiscovered, potentially recoverable UK resources are estimated at 4.6 billion boe, reflecting the potential for future exploration. Proven oil reserves alone are approximately 192 million metric tonnes (equivalent to approximately 1.4 billion barrels). However, several projects were ready to start before their approval was withdrawn:

Rosebank: Currently the largest untapped oil field in the UK, located 80 miles west of Shetland. It is estimated to contain 300–500 million barrels of oil. It was discovered in 2004, but it was not granted development approval until September 2023, only for that approval to be ruled unlawful by the Scottish Court of Session in January 2025, because the Government had not considered the climate impact of downstream (Scope 3) emissions from burning the extracted oil and gas.

If the Rosebank oil and gas field had been permitted to commence as planned, it would have employed approximately 1,200 UK jobs at its peak and an average of about 450 ongoing jobs. Rosebank’s estimated contribution to the UK economy in Gross Added Value was expected to be over £24 billion, and the production was expected to account for 8% of the UK’s oil production as well as an average of 21 million standard cubic feet of natural gas.

Cambo: A large field also located northwest of Shetland and 20 miles southwest of Rosebank. Estimated to contain over 150 million barrels of oil. Shell withdrew from the project in 2021, but it remains a significant potential resource. The Licence expired in 2022 and was granted a two-year extension to 2024, followed by another extension to 2026. The field is now owned 100% by Ithica.,

Jackdaw: situated 150 miles off Aberdeen in a water depth of only 78 metres, it is southeast of Shell’s Shearwater platform and will be tied back to this. Jackdaw is a gas-condensate field and is estimated to hold 38 billion cubic metres, with a production capacity of around 5.7 million cubic metres of gas per day. The field was discovered in 2005, approved in the summer of 2022 and was expected to be in production by 2025, but its development has been delayed by the Finch Case ruling that new oil and gas developments must take Scope 3 emissions into consideration. The Jackdaw site could make a significant contribution to UK domestic gas supplies. Global Scope 3 emissions will be the same whether the UK drills its own gas or imports it from Norway, and they will be much higher if imported LNG replaces domestic production. However, UK employment and tax revenue will be much lower.

While the three stalled projects mentioned above are well known, according to the OEUK, there are 51 known new fields in British waters that could be producing oil and gas but are considered unviable under the current government’s tax regime and its ban on new licences. As well as 60 extensions to existing fields that are being held back because of current tax policies.

Energy benefits of using UK natural gas

Besides the obvious financial benefits of using natural gas from the North Sea: increased tax revenue, increased regional employment and an improved Balance of Payments, there is also an energy bonus. The highest Energy Return on Energy Invested (ERoEI) is achieved from a conventional gas field. The ERoEI is between 20:1 and 28:1. That means we get over 20 times as much energy out of a natural gas field as we put in to extract the gas. However, imported LNG has a dramatically lower ERoEI. The liquefaction process consumes about 10% of the gas’s energy, and the shipping fuel and regasification further reduce the energy returned. Imported LNG has an ERoEI of less than 10:1. Importing LNG from the US only makes financial sense because fracking in the US has lowered the US gas prices so much that there is still a financial gain after converting it to LNG and transporting it across the Atlantic.

The oil industry does not regard the UK side of the North Sea as a spent resource, as evidenced by the North Sea Transition Authority (NSTA) offering a further 31 licences in the latest phase of the 33rd oil and gas licensing round in 2024. These licences attracted 115 bids from 76 companies. The licences offered in the round were expected to add an estimated 600 mmboe by 2060, or 545 by 2050.[1]

The first tranche offered 27 licences in October 2023, and the second offered 24 in January 2024. The 31 offers in the final tranche comprise 29 new licences and 2 mergers. Of the 29 new licences, 23 are Initial Term Phase A or B, two are Initial Term Phase C (firm wells), and the remaining four go directly to Second Term, meaning they can theoretically enter production more quickly.

Phase A is a period for carrying out geotechnical studies and geophysical data reprocessing; Phase B is a period for undertaking seismic surveys and acquiring other geophysical data; and Phase C is for drilling.

The number of awards in the current round is broadly similar to that of the most recent predecessors. The 32nd Offshore Licensing Round offered 113 licences over 260 blocks or part-blocks to 65 companies; the 31st Round, which focused on frontier areas, offered 37 areas over 141 blocks or part-blocks to 30 companies; and the 30th Round offered 123 licences over 229 blocks or part-blocks to 61 companies.

Norway profits while the UK pays

The UK is likely to have even greater oil and gas resources in the North Sea as the Norwegians exploring in the same area have continued to find new fields. In 2025, Norwegian exploration activity was slightly higher than in 2024. A total of 49 exploration wells were completed, and 21 discoveries were made on the Norwegian continental shelf. The discoveries have a preliminary total estimate of 67 million standard cubic metres of recoverable oil equivalents.

In 2025, Aker BP found one of the largest commercial oil discoveries on the Norwegian Continental Shelf. In December 2025, Equinor made two new discoveries of gas and condensate in Norway’s Sleipner area of the North Sea. These were Equinor’s largest discoveries in 2025 and can be developed using existing infrastructure. Preliminary estimates indicate that the reservoirs may contain between 5 and 18 million standard cubic meters of recoverable oil equivalents, corresponding to 30 to 110 million barrels. There is no reason to believe that exploration on the UK side of the line would not also result in major new finds, including fields west of Gullfaks within the UK zone. The Norwegians have found another large field near their major Gullfaks oil/gas field, which is just inside Norway’s maritime border.

In contrast to the UK, where few companies are continuing to explore and develop new fields, exploration has continued on the Norwegian side of the North Sea. Two new discoveries have been announced to date in 2026. Equinor, Norway’s majority state-owned energy company, together with its partners – Petoro, ConocoPhillips Skandinavia, and Vår Energi – announced their new find, with preliminary estimates of 0.15-2 million standard cubic meters of recoverable oil equivalent, corresponding to 0.95–12.6 million barrels of recoverable oil equivalent.

On 20th January 2026, the Norwegian Offshore Directorate (NOD) revealed that Equinor and its partner, Orlen, had discovered gas and condensate in the Sissel prospect in production license 1137, which was awarded in 2022 as part of the awards in predefined areas 2021. The preliminary estimate of the size of the discovery is 1–4.5 million standard cubic meters of recoverable oil equivalent, corresponding to 6.3–28.3 million barrels of recoverable oil equivalent. The licensees will consider the opportunities to develop the discovery as a tie-back to existing infrastructure in the area, according to the Norwegian Offshore Directorate. Later this year, Orlen Upstream Norway plans to launch Eirin, another field in this area, to be developed using the Gina Krog and Sleipner infrastructure. President of the Orlen Management Board, Ireneusz Fafara, commented: “The Sissel discovery, from which we expect to obtain approximately 1 billion cubic meters of gas, strengthens our asset portfolio in Norway and represents another step toward achieving the Orlen Group’s strategic objectives. Norwegian gas plays a crucial role in ensuring stable supplies for our customers.

Norway has a stable and predictable attitude towards oil and gas exploration

Although oil and gas companies in both Norway and the UK face a total marginal tax rate of 78%, and new oil and gas developments in Norway must also assess Scope 3 emissions as part of their Environmental Impact Assessments, oil and gas companies are not leaving Norway primarily because Norway’s attitude to oil and gas production is the opposite of the UK’s. Norway’s corporate tax rate is 22% and its 56% special petroleum tax is applied after deducting corporate tax. Both taxes allow deductions for all relevant costs, including exploration, operations, decommissioning and financing. Losses can be carried forward indefinitely, and the tax value of losses is refunded in cash the following year. More importantly, Norway’s tax regime and political attitude toward the industry are considered stable and predictable. This is extremely important for companies investing in capital-intensive, multi-decade projects.

Norway recognises the important contribution oil and gas make to its economy and has created a predictable investment environment. They reward investment with upfront deductions and refunds. They have invested in electrifying offshore platforms to reduce upstream carbon emissions. The Norwegian government owns 67% of Equinor, which operates internationally, including in the UK, and is the largest operator on the Norwegian Continental Shelf. Unsurprisingly, unlike the UK, Norway has maintained a substantial fuel trade surplus since 1989. Fuels make up two-thirds of Norwegian exports, and the United Kingdom is its largest export market, buying a quarter of Norway’s fuel exports.

Norway has fast-track approvals for new fields.

Norway allows new fields to be connected to the existing pipeline and platform network, and the government actively invests in offshore energy, with petroleum accounting for one-fifth of all capital investment in the country. Companies can deduct 100% of the investment costs upfront, including exploration, research and development, financing, operations and decommissioning. Companies can consolidate revenue, investment and losses between fields. Companies with no taxable income can receive cash refunds for losses, helping new and small operators to get started. And most importantly, Norway continues to issue new licences and encourage drilling, with 42 exploration wells completed in 2024, resulting in 16 new discoveries.

The available wealth and prosperity from UK onshore oil and gas potential

As well as North Sea oil and gas, the UK has onshore oil and gas, including a giant gas field discovered under Lincolnshire that could meet the UK’s entire needs for a decade, reducing dependence on imports and generating tens of thousands of jobs. Egdon Resources, the energy company behind the discovery, believes the field, centred on the market town of Gainsborough, is so large that it could benefit the whole UK economy, boosting growth through more jobs, increased tax revenue and cheaper energy.

Deloitte estimated that exploiting the Gainsborough Trough field could add up to $140bn (£112bn) to GDP, yield $34bn in direct taxation and create tens of thousands of jobs. Using domestic UK gas would also reduce the UK’s CO2 emissions by 218 million tonnes compared with imported LNG. The area already supports two dozen small onshore oil wells, but Egdon drilled into different strata, ancient mudstones lying about 2km deep, to find the gas. The field holds at least 480 billion cubic metres of recoverable gas – about seven times the UK’s current annual consumption. However, UK gas usage is expected to decline in the future; the reserve is likely to last a decade. This indicates that the Gainsborough field may be substantially larger than Shell’s North Sea Jackdaw development, which is estimated to hold 38 billion cubic metres, but its development has been delayed by regulations and additional approvals governing Scope 3 emissions.

Hydraulic Fracturing (fracking) and the madness of crowds

The UK also has the potential to frack for gas. The British Geological Survey’s early assessment suggested that UK shale formations might contain enough gas to supply up to 50 years of current UK demand. Another study by the University of Nottingham estimates that the realistically recoverable resource is only enough to meet 10 years of current demand. The British Geological Survey identifies four main shale basins: the Bowland–Hodder Basin (North‑West England, Midlands) – the largest, the Midland Valley (Scotland), the Weald Basin (Southern England), and the Wessex Basin (Southern England).

There are known shale gas fields in the UK, including the Cuadrilla Resources sites in Lancashire. In 2019, INEOS announced successful results from recent tests in the Bowland shale at Tinker Lane, Nottinghamshire. Together with partner iGas, INEOS found very high gas concentrations, comparable to (and in some tests exceeding) the average levels in the Barnett Shale in Texas. The tests found an average level of 60.7 standard cubic feet (scf) per tonne of gas. For comparison, the average for the Barnett shale is 39 scf per tonne.

Fracking should not be viewed as anti-green. Natural gas is a much cleaner fuel than coal. It is inconsistent with environmental principles for the UK to consider leaving its shale gas in the ground while importing LNG that has been frozen and then transported thousands of miles from the US or Qatar, or importing goods produced using coal in China or India.

It is also worth noting that although fracking trials in the UK were shut down because the process caused slight earth tremors with magnitudes between 0.5 and 2.9 on the Local Magnitude (ML) scale. However, there is a geothermal project in Cornwall, United Downs Deep Geothermal Project, that uses fracking techniques to extract hot water from deep granite to generate electricity. This process has caused 232 induced seismic events so far, two of which exceeded 1.5 ML. Yet no one is trying to close the Geothermal Project. Earth tremors caused by fracking for hot water aren’t seen as a problem, unlike those caused by fracking for gas, which could produce the same amount of energy.

Fracking success for the US economy

The US Henry Hub natural gas price has fallen significantly since the fracking boom in the 2010s, due to the massive increase in domestic gas supply from shale gas extraction. Before then, the US natural gas price was between $6 and $8 per MMBtu; now it is about half that amount. In January 2008, immediately before the fracking boom, the US gas price was $7.68 MMBtu; by March 2012, it had dropped to $2.27 MMBtu, as fracking increased production by 36%. The US Producer Price Index for natural gas declined 56.8% from 2007 to 2012.

Before the US shale boom, UK natural gas was cheaper than US Henry Hub gas prices. However, this has not been the case since 2010. As US production increased and prices fell, UK gas production was restricted by limiting new offshore well development, preventing onshore fracking, and imposing massive additional taxes on oil and gas companies.

Lower US gas prices reduced costs for US households and manufacturing industries and fuelled economic growth. Cheap gas is credited with the creation of 725,000 jobs by 2014 and a 0.7% increase in US GDP by 2015. Cheap gas lowered US electricity prices and encouraged a shift from coal to gas, which also cut associated CO2 emissions in half. Fracking also helped the US trade deficit: The US went from being a net gas importer, importing gas from Canada and LNG from Qatar, to becoming the world’s largest exporter in 2023, surpassing Russia, Qatar and Australia with exports of 91.2 million metric tonnes. This is in stark contrast to 2007, when the US imported 4.6 trillion cubic feet, approximately 88.6 million metric tonnes of gas, assuming a standard methane density.

China is also fracking

China has recently made major new shale gas discoveries in Xinjiang, adding to its reserves in Sichuan, and is expanding hydraulic fracturing (fracking), primarily in the Sichuan Basin. Although these new finds are important, they will not significantly reduce China’s dependence on imported gas, as gas demand is growing faster than domestic supply.

China is the world’s largest importer of LNG and a major importer of natural gas by pipeline. China consumes over 400 billion m3 of natural gas per year, of which 230-240 billion m3 is produced domestically and 160-180 billion m3 is imported. Over half of China’s imported natural gas comes via pipelines from Turkmenistan, Russia, Kazakhstan, and Myanmar, and 40%-45% is imported as LNG from Australia, Qatar, the US, and Malaysia.

China’s shale gas reserves are deeper than those in the US and are expected to be more expensive to frack. The reserves are in mountainous regions far from China’s main population centres, so they will need to build a pipeline to transport the gas to the demand centre. China has also signed long-term contracts with its LNG suppliers, but it effectively ceased importing U.S. LNG in retaliation for the U.S. increase in tariffs on Chinese goods.

International pricing of oil and gas

Oil prices vary by grade and location. Refineries usually specialise in refining certain grades of oil. Light sweet crude oil, such as North Sea Brent, is usually more expensive than heavy sour crude as it is easier and cheaper to refine. In general, oil prices move in parallel; however, when there is trouble in the Middle East, such as the current Iranian blockade of oil tankers passing through the Strait of Hormuz, the price of Middle Eastern crudes will increase by more than similar sour crudes from Northwestern and Central America. Transporting oil by tanker is cheaper than purifying, freezing and transporting gas by LNG Carrier, but both require insurance and freight, which adds to the price of imported oil and gas.

The chemical composition of natural gas and its energy content vary from one reservoir to another. Methane content can vary from 65% to over 95%, but natural gases also contain various levels of higher-chain hydrocarbons known as Natural Gas Liquids (NGLs) (ethane, propane, butane and pentane), and various quantities of other gases such as nitrogen, helium, and hydrogen sulphide. However, gas prices vary with demand at the supply location, unless there is a pipeline delivering the gas to a demand point or to a facility that converts the gas into liquid form (LNG) for transport by sea in specially designed tankers.

Converting gas to LNG involves purifying it, cooling it to -162 degrees Celsius, which also reduces its volume by about 600 times, and storing it cryogenically. Cooling the gas is very energy-intensive, consuming approximately 280 kWh to produce one metric tonne of LNG. About 7% to 15% of the gas delivered to an LNG plant is used to power the compressors and refrigeration process. Converting gas to LNG adds about $3.50 per MMBtu to the price, assuming this is done at a large-scale facility on the US Gulf Coast. Shipping the LNG to the UK adds $2, and regasification at a UK terminal incurs $0.8.

Coal production, reserves and potential

Global coal consumption, at 45,850 TWh, is still higher than gas consumption, at 41,278 TWh. Each year, approximately 1.4 billion tonnes of coal are exported internationally. If coal is eventually phased out internationally, leaving UK coal in the ground would represent a missed opportunity to benefit from the export revenue potential of the UK’s natural resource.

The UK has almost entirely phased out coal mining, but one coal mine still operates in Wales: Aberpergwm Colliery near Port Talbot. Another Welsh mine, Ffos-y-fran at Merthyr Tydfil, was recently closed. However, the UK still has approximately 77 million tonnes of proven, economically recoverable coal reserves that could be profitably mined. There are an additional 4 billion tonnes of known hard coal deposits, though not all are currently economically viable.

The UK consumed 2.1 million tonnes of coal in 2024 (2.5 million tonnes of oil equivalent). for industrial processes that require temperatures above 1,400 °C, such as cement, glass, and ceramic production.

Figure 12: Employment in the UK coal industry

Legislation applicable to coal production in the UK

Coal mining is legal in the UK provided the mine has a licence from the Coal Authority, planning permission, environmental permits and complies with strict Health and Safety regulations. Mine Regulations 2014 require mine design and risk assessment, ventilation and dust control, electrical safety, explosives handling, emergency planning, and the provision of escape routes. The Coal Mining Act 1994 created the Coal Authority, which issues coal mining licences, manages coal resources and oversees safety and environmental responsibilities. Obtaining planning permission requires approval for a change of land use, land access and surface rights, an environmental impact assessment, a community impact assessment, and a water management plan. The environment permits covering water pollution, mine water discharge, mine waste management and emissions management. All new mines must now assess their Scope 3 emissions.

All of this is included in this chapter to emphasise that coal mining in the UK is not a fly-by-night activity. It is highly regulated and should be encouraged as an industry. UK coal mining is more tightly regulated than many of the mines that provide the UK’s coal for industrial heat and the mines that provide the inputs and energy for the goods the UK imports from Asia.

Types of coal in the UK

Coal is a dense energy source with considerable uses beyond electricity production. Coal can burn at up to 3,500°F (1,900 °C) and provide industrial heat to produce glass, ceramics, cement and other chemicals. Anthracite contains about 90% carbon and burns at 1,100 to 1,400 °C and typically produces 30 to 33 MJ/kg. Anthracite is the most efficient type of coal; it has the highest carbon content, the lowest moisture content, and burns longer, hotter, and cleaner than other types of coal. Bituminous coal, the most prevalent in the UK, is 45% to 85% carbon, burns at 900 to 1,300 °C, and is generally used for power generation, producing 24 to 30 MJ/kg. Metallurgical (coking) coal is a grade of bituminous coal with low ash, low sulphur, low moisture and high carbon with the ability to liquefy and resolidify into coke when heated in an anaerobic environment (without oxygen). It burns at 900 to 1,300°C but can reach higher temperatures when converted into coke, which burns at 1,500 to 2,000°C. It typically produces 24-30 MJ/kg.

Lignite (Brown coal) is only 25% to 35% Carbon, burns at 600 to 800°C to produce 10-20 MJ/kg and is the least efficient type of coal, releasing the highest CO2 emissions, as well as particulates, sulphur dioxide, nitrogen oxides and ash. Germany currently burns lignite to generate electricity. Reopening UK bituminous coal mines and exporting the coal to German power stations would revive a valuable Welsh industry, create jobs, improve the UK’s balance of trade with the EU and lower global CO2 emissions. Coal is equally essential to UK cement production, supplying approximately 80% of the energy used to produce this critical infrastructure product. Coal’s contributions to the UK economy extend to agriculture through ammonia fertilisers and soil improvers.

There is still a future for UK coal

Material science, critical minerals and Rare Earth elements

Coal is no longer just a fuel; it is becoming a source of critical minerals, rare earths and advanced materials like graphene, carbon fibres, and the building blocks of the next industrial era. The U.S. Department of Energy, China, and several European research groups, including the Universities of Exeter and Nottingham and the British Geological Survey, are actively developing extraction technologies from waste coal tailings because it’s cheaper and cleaner than opening new mines. The UK has hundreds of millions of tonnes of coal spoil heaps and Acid Mine Drainage sites. This could be another growth industry for South Wales and County Durham.

Coal and its by‑products — especially coal ash, coal refuse, and acid‑mine drainage precipitates — contain measurable concentrations of rare earth elements (REEs): Neodymium, Dysprosium, Yttrium, Lanthanum, Critical minerals, Cobalt, Lithium, Germanium, Gallium, Scandium, and Vanadium. These elements are essential for: EV motors, wind turbine magnets, semiconductors, fibre‑optic systems, batteries, and aerospace alloys.

UK coal waste streams are enormous, already mined, and often concentrated by natural processes. For example. Acid mine drainage forms precipitates rich in rare earths. Coal ash can contain REE concentrations comparable to low‑grade conventional ores. Coal seams themselves can be rich in germanium, gallium, and other high‑value elements.

Anthracite can be converted into industrial-grade graphene, which is used for energy storage, composites, coatings and sensors. Carbon fibres are a by-product of coking and are used in aerospace, wind turbine blades, sporting goods and lightweight vehicles. Coal can also be used to produce synthetic graphite and hard carbon for lithium-ion and sodium-ion batteries. The UK should be encouraging the exploitation of this resource.

Aberpergwm – Anthracite

Aberpergwm produces high-grade anthracite used in water filtration, industrial carbon products and high-temperature processes. The mine has a long-term licence allowing extraction of up to 40 million tonnes over 18 years. A large proportion of the anthracite it produces is exported. Aberpergwm is a deep coal mine producing anthracite, owned by Energybuild and employing 100 to 130 workers. Despite being located at Port Talbot, it did not supply the coking coal needed for the nearby blast furnaces. Instead, the metallurgical coal they needed was imported from Australia and the US, and occasionally from Canada and Russia (before its invasion of Ukraine in 2022).

Ffos-y-fran – Thermal Coal

About 25 miles away from Port Talbot, the Ffos-y-fran mine was an opencast thermal coal producer that supplied the Port Talbot steelworks with coal for steam and heat. It employed about 180 workers but is now effectively closed, as its licence expired in 2022. Thermal coal is mainly used to produce heat for cement works, industrial heating and heritage railways.

Whitehaven – Metallurgical coal

There was also a proposal to open a new metallurgical coal mine in Whitehaven, Cumbria, called the Woodhouse Colliery. The mine was approved by the government in 2022 and was expected to produce 2.78 million tonnes of coal annually through to 2049. This would have been used in blast furnaces in the steel industry. Unfortunately, the High Court overturned its planning permission in September 2024, preventing the project from proceeding.

As with opposition to the new offshore oil and gas fields, the removal of planning permission followed the Supreme Court’s Finch judgment, which requires consideration of Scope 3 downstream emissions in environmental impact assessments. The Labour government has also withdrawn its support from the project. This was done by Angela Rayner in July 2024 when she was the minister for local government. The proposed Cumbrian mine would have employed about 500 people directly, with another 100 indirect supply-chain jobs. These would have been skilled, well-paid jobs in a region that could use more high-productivity employment. The largest source of employment in Cumbria is tourism, which is generally low-skilled and low-paid. The area around Workington and Whitehaven had been a major coal-mining area; the first pit was established in 1552, and the last pit in Whitehaven closed in 1986; therefore, the opening of a new coal mine would not have been out of character.

UK Coal imports for steel production and industrial heat

The UK government intervened last year to prevent the closure of the last two blast furnaces in the UK, at Scunthorpe, owned by Chinese steelmakers, Jingye, while at the same time preventing the opening of a new metallurgical coal mine in Cumbria. The UK currently imports metallurgical coal, a key ingredient in steel production, from as far away as Australia.

Figure 13: UK coal supplying countries

Coal fired electricity production and Carbon Capture and Storage (CCS)

The closure of the UK’s last coal-fired electricity plant, Ratcliffe-on-Soar, in Nottinghamshire, in October 2024, ended Britain’s 142-year reliance on coal for generating electricity. The plant was one of the cleanest, extracting all pollutants except for CO2 emissions. But it was still too expensive to continue operating. Coal is a dense store of energy and the cheapest, most reliable way to produce electricity. Coal prices are less variable than oil prices, and, more importantly, the UK has large thermal coal reserves.

Other countries are developing coal-fired electricity plants that also capture CO2 emissions as well as all other particulates. The Canadians (Boundary Dam 3, 2014), the US (Petra Nova, Texas) and China (Zhengning Power Plant) have built coal-fired power stations that also collect CO2 emissions. China’s Zhengning Power Plant was launched in September 2025 and is expected to capture 1.5 million tonnes of CO2 annually. This would have been a preferable solution towards lowering Britain’s CO2 emissions than closing all coal plants. Technology is producing High-Efficiency, Low-Emissions plants that cut CO₂ by up to 40%. Carbon Capture and Storage (CCS) enables reductions above 90%, with Chinese projects targeting 99.9%.

China added 78 GW of new coal-fired power capacity in 2025, including more than 50 large coal units, each producing approximately 1 GW of electricity. This was 87% of the new global coal-fired capacity added in 2025. However, None of China’s new coal plants has Carbon Capture and Storage (CCS).

The International Energy Agency (IEA) calculates that CCS increases the levelized cost of electricity from coal by 70% to 100% and consumes over 20% of the plant’s output. The low cost of coal-fired electricity is one of its main benefits. Ironically, China is building the new coal-fired plants as backup for its renewable electricity production. China’s renewables appear to be a token effort, given that China’s coal-fired electricity production emits 4 billion tonnes of CO2 annually.

China isn’t the only country building new coal-fired power plants, although it accounted for two-thirds of the world’s new coal plants in 2023. Indonesia, India, Vietnam, Japan, Bangladesh, Pakistan and South Korea have also built new coal-fired plants. Developing and industrially competitive countries prefer coal because it is cheap. Both China and India plan to continue building coal plants because they have large coal reserves (as does the UK). 80% of India’s electricity comes from coal.

Germany has been able to restart its coal-fired electricity plants after the destruction of the Nord Stream pipelines. This has been a blessing for German energy security. Unfortunately, the Conservative Energy Minister, Alok Sharma, took delight in blowing up decommissioned coal-fired electricity plants, so the UK does not have this energy security to fall back on, even to provide backup for the UK’s ever-increasing wind turbines.

Building new coal plants as backup dispatchable electricity providers would lower UK electricity costs, as coal is cheaper than gas, and would keep the UK’s coal industry going. However, this would require the UK to abolish its Carbon Support Price tax.

Making the case for new Coal-fired power stations

The case for reopening coal mines is made stronger when the state of our electricity generation system is considered. Our gas fleet is ageing, and, of course, the last coal power plant was shut down in 2024. The typical operational life for a gas plant is 25–30 years. With careful maintenance, this could possibly be extended up to 40 years. However, intermittent operation can also reduce component life. Using plant data from the Digest of UK Energy Statistics (DUKES) and assuming a 35-year life for our gas fleet, we can see in Figure 14, below, that firm power capacity starts to fall in 2028 and by 2035 is down to just 25.5GW (or 28.8GW if Hinkley Point C is online by then).

NESO expects both total electricity demand and peak demand to rise over the period to 2030 and beyond. We will become increasingly reliant on intermittent renewables, and on dark, cold and calm winter evenings, the output from wind and solar can fall to almost zero. This means we will need firm power capacity available to meet the shortfall.

As Figure 14 shows, the UK will become increasingly short of firm power capacity, and it is therefore critical that new firm capacity is built quickly. One answer might be to build new gas-fired generators. However, there is an eight-year lead time on new gas-fired power plants, meaning that if we started building today, we would not get new capacity online until 2034. This leaves coal as a viable alternative because it should be possible to build quicker, with construction times in China as low as 20 months.

Figure 14: UK Firm power capacity to 2035

The other advantages of coal-fired generation are:

• Coal-fired generation is cheap – cheaper than gas and intermittent renewables – if carbon costs through the Emissions Trading Scheme and Carbon Price Support mechanism are removed.
• Coal-fired generation is secure, especially if domestic fuel is used. As recent events in the Middle East remind us, the security of LNG supply is subject to the whims of Middle Eastern politics. Moreover, the security of supply of intermittent renewables is subject to the whims of the weather.
• Coal-fired generation is reliable and flexible. Of course, coal-fired power plants are not subject to the vagaries of the weather, which is why most coal is used as a constant baseload power source. However, newer plants can operate at lower minimum loads and flex up and down in response to changes in demand and the output of intermittent renewables.
• Storage is cheap and easy. One problem with intermittent renewables is that they sometimes produce more power than demand and at other times produce less. This problem can be partially solved by adding battery storage. However, such storage is very expensive. By contrast, coal can be stored in stockpiles near the power plant at very low cost.

The main objections to new coal power plants relate to emissions. If CO2 emissions are discounted due to the US removal of the greenhouse gas endangerment finding, that leaves real pollutants such as particulates, SOx and NOx to deal with. Fortunately, modern super-critical (SC) and ultra-super-critical (USC) plants in China have proven very effective at removing these pollutants.

First SC and USC plants operate at higher thermal efficiencies than conventional plants, reducing coal use and raw pollutant emissions per MWh of electricity produced.

• Studies have shown that modern Ultra Low Emissions plants in China remove over 99.9% of all particulate matter and over 99.8% of PM2.5 particulates. Other studies show sulphur dioxide removal rates of 97.8-99.7% in high-efficiency, low-emissions power plants in China. NOx removal efficiencies of 90% can also be achieved.
• The benefits of coal-fired power plants are obvious, and the downsides of coal have been largely eliminated through technological enhancements. The case for coal is becoming increasingly hard to ignore.

Chapter 3: Oil refining and petrochemicals

Refining is a high-volume, low-margin industry that is vital to national energy security and to supplying petrochemical feedstocks to the chemical, pharmaceutical, and plastics industries.

In 2019, the oil refining industry contributed £3.7 billion in direct Gross Value Added to the UK economy, according to the UK Petroleum Industry Association (now the Fuel Industry UK), and up to £8.6 billion when supply chain, logistics, engineering, and distribution are included. The industry is highly productive, with only 12,000 direct employees at the time, but it supported over 100,000 jobs, including supply-chain and related employment, and generates £5-£7 billion annually in corporate, business, and income tax revenues. Unfortunately, since 2019, two of the UK’s six refineries have closed, with the loss of 820 direct jobs. But neither the government nor the Fuel Industry UK has recalculated the GVA of the remaining industry.

Trade

SITC 5 Chemicals are the UK’s second-largest goods export after machinery and transport equipment. Since 2019, using ONS Chained Volume Measures (CVM) to account for inflation, Chemical exports have fallen by 15%. In 2014, the UK had a small trade surplus in SITC Chemicals; in 2025, it has now flipped into a £4.8 billion trade deficit.

The importance of Brent Crude for the refining industry

The refining industry in the UK mostly uses light sweet crudes, such as North Sea Brent Crude (Sulphur content 0.37% and API gravity of 38.3), which is cheaper to refine, as it requires less desulphurisation and has a higher yield of premium products such as petrol, diesel, jet fuel and naphtha. Light sweet crudes sell at a premium to ‘bottom of the (distillation) barrel’ heavy sour fuel oils.

Figure 15: North Sea Brent Crude characteristics are perfect for low-sulphur chemical use.

In addition to petrol, diesel, jet fuel, shipping fuel, heating oil, and kerosene, oil refineries produce the building blocks of industry and metropolitan life: asphalt, plastics, sulphur, ammonia used in fertilisers, rubber, chemicals, pharmaceuticals, bleaching agents, and explosives. However, as UK crude oil production falls, oil refineries and related industries, such as petrochemicals, plastics, and fertiliser production, are also closing.

Figure 16: UK remaining oil refineries, their feed stocks, products and employees

The UK’s four remaining refineries have a combined capacity of approximately 1 million barrels per day, representing about two-thirds of the UK’s 2010 refining capacity. The UK’s average consumption of refined oil in 2024 was around 1.4 million barrels per day, so domestic production accounted for only 70% of that consumption.

Declining demand for products

At the industry’s peak, the UK had 18 refineries, but the recent closures of Grangemouth and the Lindsey refinery in 2025 leaves just four. This is primarily due to overcapacity in Europe, falling domestic demand for refined oil and derived products and increasing environmental regulations and taxes. The drop in demand for oil-derived products is driven by a decline in UK manufacturing. For example, rubber is a derivative of oil refining and is used for hoses, seals, conveyor belts, vibration dampers, tyres, gaskets, washers, electrical insulation for wires, waterproofing membranes, insulation, flooring, medical tubing and gloves, and textiles. Many of these items are used in the production of machinery, appliances, and clothing, which have generally shifted to Asia. For example, the production of household appliances such as washing machines requires hoses, washers, and door seals, but as appliance production has moved to Asia, UK demand for the rubber components has also diminished.

Closed Oil Refineries

The Grangemouth Refinery ceased crude processing in April 2025, and the Lindsey Oil Refinery in Lincolnshire is being sold to Phillips 66 Limited by its administrators, but it will not remain a stand-alone refinery. Together, they refined 260,000 barrels of crude per day, equal to about 22% of the UK’s total refining capacity of 1.2 million barrels. UK Consumption is approximately 1.35 million barrels per day; therefore, imports will need to increase by 260,000 barrels per day to offset the shortfall.

The impact of all this on employment is enormous. Closure of the Lindsey Refinery’s integration into the Humber refinery’s operation will result in 1,000 job losses, including employees, contractors, and suppliers. Utilising data provided by Petroineos, PwC estimates that the Grangemouth Refinery employed 518 people (on an FTE basis) in 2023. Whilst this represents only a small portion (0.5%) of the working-age population in the Falkirk council area (102,021 according to ONS), it comprises a set of relatively well-paid, skilled technical jobs. Refinery workers at Grangemouth earn £53,000 per year on average, significantly above the Scottish average of £35,000 for a full-time worker. Accounting for its supply chain and the spending of its employees in the wider economy, the Grangemouth Refinery supports 2,808 FTE jobs. PwC estimates that, in 2023, the Grangemouth Refinery provided £404 million in total GVA, of which £179 million is direct, £180 million is indirect, and £44 million is induced. Of the refinery’s UK supply chain spend, 85% (i.e., £290 million) was in Scotland.

The Grangemouth refinery was established in 1924 and was among the UK’s first. In April 2025, it closed despite being Scotland’s only remaining oil refinery. The decision was apparently accelerated by the 2035 ban on the sale of petrol and diesel cars, even though oil has many other uses beyond vehicle fuels. Grangemouth was the only refinery connected to North Sea oil production via the Forties Pipeline System.

Although the Grangemouth refinery accounted for about 80% of Scotland’s fuel production and 65% of Scotland’s total oil products, it employed only 400 to 500 on-site workers, making the Grangemouth refinery one of the UK’s most efficient companies. Its closure will lower Scottish productivity.

An executive at Valero Energy Corporation, commenting on the recent closures of two UK refineries, remarked at an energy conference that once refineries have closed, restarting them would be very expensive: a new refinery would cost around $1 billion to build. Valero’s Pembroke refinery makes its own energy but still has to purchase emissions allowances, which are twice its labour costs. The company bought the Welsh refinery because of its access to plentiful supplies of Crude via the deep-water port at Milford Haven, which accommodates super tankers.

Crude oil is the largest input cost for refineries, and they cannot operate efficiently without a consistent, reliable supply. This is also the case for downstream products: ExxonMobil most likely decided to close its Ethylene plant at Mossmorran due to the planned closure of the Petroineos oil refinery at Grangemouth, which supplied Mossmorran’s feedstock.

Petrochemicals

Chemicals are the UK’s second most valuable goods export, after machinery and transport equipment. It is also the UK’s second-largest industry, comprising over 4,000 companies, employing 137,000 direct employees in 2023, generating £62 billion in turnover, £9.8 billion in research and development, and £7.2 billion in capital spending. The industry added over £30 billion to the UK’s GVA in 2023.

The Chemicals employees earn, on average, 27% more than the UK average. It is difficult to imagine why any government would be trying to close this industry. We can only assume that the successive UK governments are doing this by accident rather than by design. Energy costs have not only increased the cost of industrial production in the UK but also the cost of domestic energy, thereby reducing consumers’ discretionary spending.

Brent Crude is a light, sweet oil with low sulphur content of only 0.37%, making it ideal for use in the petrochemical industry. Sulphur makes refining more expensive, as it is considered a contaminant that must be removed prior to processing. High-sulphur oils burn less efficiently and produce more pollution. The NYMEX classifies sweet crude as that with less than 0.5% sulphur. Most oil contains between 1% and 5% sulphur.

The key to lower costs in the petrochemical industry is determined by the cost of its feedstock, energy and the scale of production. The US shale boom has created the world’s cheapest ethane, up to 70% cheaper than European ethane, as well as ample supplies of natural gas. Trinidad and the Middle East also have large amounts of natural gas, often priced below EU and US market prices. While China uses very cheap syngas made from coal. The UK’s last remaining ethane cracker at Grangemouth predominantly uses imported US ethane rather than North Sea ethane or European naphtha. The Ethane is liquefied to -89 °C and transported to the UK on purpose-built very large ethane carriers (VLECs) designed specifically for INEOS. Despite this, it remains dramatically cheaper than European naphtha. INEOS Grangemouth also supplies raw materials to INEOS’ Olefins and Polymers Europe, a petrochemical and plastics plant, whose products range from construction materials to clothing.

The chemical operations at Grangemouth, Britain’s largest chemical plant, were also at serious risk of closure along with the refinery. Its owner, INEOS, has warned that high energy costs and carbon taxes have rendered the site uncompetitive relative to its US operations. In December 2025, the government announced a £120 million support package to keep the facility in operation. Had the INEOS Grangemouth chemical operations closed, it would have resulted in an additional 900 direct job losses, with thousands more jobs lost indirectly. The 1,700-acre refinery, petrochemical, and plastics site, Scotland’s largest industrial complex, directly employs 2,000 people plus up to 5,000 contractors across INEOS’ refinery and other businesses. The oil refinery has closed, but the petrochemical and plastics complex at Grangemouth remains operational thanks to the government support to secure the Grangemouth ethylene cracker. But a better solution may have been to review the government’s decision to prevent any new gas permits in the North Sea and the requirement for the plant to invest in converting North Sea gas into hydrogen

According to a report by the Chemical Industries Association (CIA), 25 sites have closed over the past 5 years, resulting in a 40% reduction in UK chemical production. The CIA survey showed that in the last quarter of 2025, 38% of companies reported a decrease in employee numbers, 37% reported a decrease in sales, and 87% expected weak business in 2026. The Chief Executive of the Association, Steve Elliott, stated that this is a consequence of the UK’s pursuit of Net Zero on a timeline out of step with industry’s international competitors.

Ethylene Production

Ethylene is the largest‑volume petrochemical globally, with over 200 million tonnes produced each year. Ethylene is essentially the “building block” of modern materials. It is the foundation material for plastics, chemicals, and everyday products. Major uses include: Polyethene plastics (bags, films, bottles, pipes); Vinyl chloride used to produce PVC; Ethylene oxide used to produce detergents, antifreeze, and solvents; Polyester precursors used to produce textiles and fibres; Medical supplies and packaging; and Industrial chemicals used across manufacturing.

In November 2025, ExxonMobil announced it would close its Ethylene Plant at Mossmorran in Fife, Scotland, in February 2026. A total of 179 directly employed jobs will be at risk, along with 250 contractor positions, and up to 50 employees will be transferred to the Fawley Petrochemical Complex in Hampshire, approximately 500 miles away.Most people may have shrugged at this news, not knowing what ethylene is or why it matters to their lives.

In the UK, ethylene has been traditionally produced by steam cracking naphtha. Naphtha is extracted during crude oil distillation to produce petrol, diesel and kerosene. Naphtha boils between 30°C and 180°C and is one of the first major fractions removed in crude oil refining. Production is generally continuous to supply inputs to downstream petrochemical plants.

It is cheaper to produce ethylene from steam cracking ethane, a by-product of U.S. shale gas production. The plentiful supply of cheaper ethane from fracking has shifted US ethylene feedstocks from 40% Naphtha and 28% ethane in 2005, to 7% naphtha and 61% ethane in 2015. However, among crude oils, Brent Crude is well-suited to naphtha production because of its low sulphur content and because light crudes produce more naphtha than heavy crudes.

Ethylene supply and use in the UK

The UK had three primary ethylene production centres, but now it has only one: the INEOS Grangemouth Ethylene Plant – which was due to close in February 2026 but received a last-minute support package: £120 million from the government and £30 million from the site’s owner, INEOS, on December 17, 2025. It is now the only ethylene producer left in the UK. The Fife Ethylene Plant at Mossmorran closed in February 2026. While the Wilton plant has been offline since 2020, and its owners, SABIC UK Petrochemicals, announced in June 2025 that it will remain closed.

Ethylene feedstock is used by factories that produce: polyethene plastics used to make containers, packaging films, bottles, and plastic pipes for construction; Ethylene oxide and ethylene glycol used in antifreeze, PET bottles and Polyester fibres; Vinylchloride monomer and PVC which is used in pipes, cable insulation and window frames; Ethylbenzene and styrene used in polystyrene for packaging and ABS plastics; and synthetic Ethanol used in solvents and chemical intermediates.

The UK has an ethylene pipeline network, shown in Figure 17 below, which was specifically built to connect ethylene production centres with UK manufacturers that convert ethylene into plastics and other chemicals. The UK’s ethylene pipeline distributes ethylene to manufacturers at Grangemouth, Wilton, Stanlow, Runcorn, Carrington, Saltend, and Hull, and to bulk storage sites at Wilton and Holford. The pipeline is the most effective means of transporting ethylene across the country. It avoids the additional energy required to liquefy it (-103°C), the hazards of road or sea transport, and the hazards of loading and offloading. It was originally constructed by ICI (Imperial Chemical Industries) in 1966/7 and was later extended and upgraded.

Figure 17: Ethylene pipeline across the UK

Ethylene glycol and polymers

The UK still makes a small amount of ethylene glycol. Producing 660,000 kg in 2023, which is expected to increase to 760,000 kg by 2028. Ethylene glycol is made from ethylene oxide, which in turn comes from ethylene. It is used to make polyester (PET), hydraulic fluids, antifreeze, and coolants. The UK still makes some polymers, but it imports most of the monomers needed to make polymers.

The UK’s chemical graveyard

Why can’t the UK compete in chemical production? Primarily, UK Crackers are smaller and older than those in the US, and there is no financial incentive for UK chemical companies to invest in new facilities. The unavoidable fact is that the UK government is doing everything in its power to shut down oil and gas production, thereby making oil and gas derivatives more expensive and globally uncompetitive: it has put a moratorium on fracking in the UK, prevented new North Sea gas fields from going into production, imposed 78% direct taxes on oil and gas company profits, made it difficult to obtain permission for new gas fields, introduced CPS on the use of natural gas, ETS allowances, and environmental permitting, and has not created a surplus of Natural Gas Liquids (NGLs) including ethane, propane, butane, isobutane and pentane.

International competition undermines UK pigment production

Venator Materials UK, a chemical manufacturer operating from Greatham, Wynyard, and Birtley, entered administration in September 2025. A Chinese company, LB Group Co., Ltd., signed an Asset Purchase Agreement with Venator Materials UK Ltd on 16 October 2025 to acquire the Greatham Titanium Dioxide (TiO₂) manufacturing site and associated pigment assets. Completion of the sale still requires regulatory approvals, which are standard for cross‑border industrial asset sales.

Venator’s UK operations at Wynyard and Greatham employed about 800 people. Venator was one of the world’s major producers of TiO₂ used in paints, plastics, coatings and cosmetics. The Greatham site was one of the largest TiO₂ plants in Europe, and Venator was one of Teesside’s largest private-sector employers, having acquired ICI’s pigments business from Huntsman Corporation in 2017 through debt issuance. More than 270 workers at Greatham were made redundant as the plant was mothballed prior to a sale bid, with 232 workers retained to assist with the administration process.

The UK’s high natural gas and energy costs, and carbon-emission allowances, have made UK TiO₂ plants uncompetitive relative to those in the US and Asia. The Greatham plant still uses the Sulphate process to produce TiO₂, which is more polluting and energy-intensive than the alternative Chloride process. However, it can use low-grade ilmenite as a feedstock, unlike the Chloride process, which requires more expensive high-grade rutile.

The Sulphate process is energy-intensive, requiring temperatures above 1000 °C in large rotary kilns for calcination and waste treatment. The Greatham plant has to purchase UK carbon allowances (ETS) for its hydrocarbon combustion, process emissions, and waste-acid treatment. As an Energy-Intensive Industry (EII), it received free allowances for some of these emissions, but the remainder had to be purchased at market rates. As an EII, Greatham also received a 90% discount on the Climate Change Levy (CCL) and was compensated for carbon costs in its electricity costs, but these discounts accounted for only a small share of its total energy costs. The Sulphate process produces about 6 tonnes of CO₂ per tonne of TiO2, from fuel, electricity, process emissions and waste treatment. This is roughly double the Chloride process.

The Graham plant also incurred significant compliance costs of £10 to £20 million per year to obtain water discharge permits; the UK requires continuous emissions monitoring (CEMS) and mandatory reporting. The Sulphate process produces sulphate-rich wastewater that must be neutralised with iron sulphate crystallisation before discharge into local waterways. Water treatment costs £100 to £300 per tonne of TiO2. The company had to comply with the UK’s hazardous waste regulations to dispose of its iron sulphate heptahydrate and acidic sludge. The site was required to comply with the UK’s Control of Major Accident Hazards Regulations because it handled concentrated sulfuric acid. In addition, the plant had to comply with the EU Industrial Emissions Directive (IED), which sets strict limits on emissions to air, water, and land, as well as on other waste.

Chinese TiO₂ producers operate under much weaker carbon-pricing and environmental compliance pressures than UK or EU plants. China’s carbon taxes do not apply to industrial process emissions, and its electricity producers pay less than £10 per tonne of CO₂. This has allowed them to undercut European plants, such as Greatham. Chinese TiO2 capacity and production have expanded substantially in recent years, with domestic output accounting for nearly 70% of the global total by 2024, leading to multiple anti-dumping investigations by the EU, Brazil, and India.

It is unsurprising the LB Group UK Ltd, based in Jiaozuo, China, has signed a purchase agreement for the Greatham plant. LB Group is the world’s largest producer of TiO2 pigment with a 1.5 Mtpy capacity – accounting for 15% of global output. Its market dominance is a result of China’s low energy costs and lax environmental regulations.

The Venator story is illustrative of how Britain’s self-harming high energy cost can not only close businesses and put British industrial capacity at risk but also lead to the loss of vital British intellectual property.

Plastics

The UK plastics industry is a global leader operating at the cutting edge of technology and constitutes an important UK economic strength. It has an annual turnover of over £32.8 billion and employs approximately 160,000 directly, and a further 400,000 through indirect jobs. There are 5,700 companies in the UK plastics industry. Plastics are one of the UK’s largest exports. In 2025, the UK exported Plastics in primary forms worth £3 billion and plastics in non-primary forms with £3.3 billion.

The industry is a dominant player worldwide across the three core sectors of the plastics industry: material and additive manufacturers, material processors, and machinery manufacturers/suppliers. The industry processes 3.5 tonnes of material to produce 1.8 million tonnes of plastic materials.

Hydrocarbon feed stocks, ethane, propane, naphtha and gas oil are heated to 750 to 900ºC in a steam cracker fuelled by natural gas to produce ethylene, propylene, butadiene and benzene. These products are then chemically linked to form polymers such as polyethene, polypropylene, PVC, PET, PS, ABS, SAN and Polyurethane.

Clothing textiles account for 35% to 40% of total global plastic production. Polyester (PET) alone is 59% of all fibres and is used in fleece, for linings, and fast fashion. Elastane (Spandex and Lycra) is used to make sportswear, leggings and tights. While Polyurethane (PU) is used to make shoe soles and synthetic leather, EVA is used to make running shoe midsoles and Flip-flops, Rubber is used to make outsoles, and PVC is used for waterproof footwear. The UK no longer produces textiles for the mass clothing market, but it does produce Nylon fibres used in aerospace composites, defence textiles, and industrial fabrics.

INEOS Acetyls, Hull

In October 2025, INEOS announced it was cutting 20% of the workforce—60 skilled jobs—at its Acetyls plant in Hull. The reason cited was “soaring energy costs and anti-competitive trade practices, as importers ‘dump’ product into the UK and European markets.”

INEOS has invested £30m at the Hull site to switch from natural gas to hydrogen, cutting emissions by 75%, equivalent to taking 160,000 cars off the road. Despite this investment, INEOS now warns that without tariffs to protect sites like Hull, such progress will come at the cost of British jobs.

INEOS is the largest producer of acetic acid, acetic anhydride, and ethyl acetate in the UK and Europe. These chemicals are essential for everything from food preservation and pharmaceuticals, including aspirin and paracetamol, to diagnostic tests, adhesives and industrial coatings. Without them, modern life doesn’t function.

INEOS blamed “dirt-cheap carbon-heavy imports from China, produced using coal and emitting up to eight times more CO₂ than INEOS’s UK operations.”  It has warned that, unless such action is taken, more production facilities will close and thousands more jobs will be lost in Hull and across the UK chemical industry.

Pharmaceutical and healthcare petrochemicals

Petrochemicals are used in the production of many common pharmaceuticals, such as antibiotics and aspirin, as well as in their coatings, capsules, stabilisers, and packaging. The UK still produces some of the key petrochemicals used in pharmaceutical production, including ethylene, propylene, aromatics and other petrochemical intermediates derived from crude oil or natural gas via refineries and crackers. Pharmaceutical plants are heavy users of process heat, steam, and electricity, much of which comes from oil and gas. But the UK imports many other feedstocks, such as Methanol and Ethylene glycol, as well as importing 50% of its gas and 34% of its oil.

Petrochemicals are also used in the production of healthcare equipment, including protective clothing and gloves, syringes, IV bags, tubing, packaging, surgical instruments, sterilisation wraps, blister packs for pills, glues, adhesive tapes and sutures.

The Pharmaceutical and life sciences industry is a massive business for the UK. Adding £17.6 billion in GVA in 2021, according to the Association of the British Pharmaceutical Industry. In 2023/24, there were 6,170 businesses, employing 359,600 people and generating a turnover of £146.9 billion. Biopharmaceuticals account for 40% of companies, 45% of employment, and 67% of turnover.

Although the UK pharmaceutical industry is structurally dependent on oil- and gas-derived feedstocks and energy, it is only marginally reliant on domestic refining capacity. Further closure of UK refineries would increase import dependence but not necessarily halt pharmaceutical production. However, the combination of reduced feedstock supplies, high industrial energy costs, and high UK wages and taxation may be enough to drive the industry out of the UK.

Petrol and Diesel

Finally, petrol and diesel: 45% to 55% of all refined oil in the UK, are turned into road fuels. According to Fuels Industry UK, UK refineries produce more petrol than the UK consumes, but less diesel than the UK requires, so the UK exports petrol and imports Diesel. While only 40% of UK cars run on Diesel, 95% of vans and buses, and 99% of Trucks and machinery do. Despite the subsidies and mandates, at the end of Dec 2024, of the 41.7 million licensed vehicles in the UK, less than 1.4 million were Zero-emission vehicles (ZEV), of which 1.3 million were ZEV cars.

North Sea crudes tend to be light sweet crudes that are more suited to petrol, diesel, jet fuel and naphtha production. UK refineries were mainly built between 1950 and 1970 when most vehicles in the UK ran on petrol. Now, diesel demand is higher as car owners were encouraged to switch to diesel in the early 2000s to lower CO2 emissions, and larger trucks, machinery, and farm equipment all run on diesel. But UK refineries are geared towards producing petrol and jet fuel, while those on the continent produce more diesel, as demand for it is greater there. There is also less demand for naphtha as it is being replaced by cheaper ethane, a byproduct of US shale gas.

Refineries purchase different grades of oil based on price, availability, transport costs, product demand, and their refinery configuration. But that doesn’t mean that once the crude oil reaches a Dutch, German, or Scandinavian refinery, the UK market will never see it again. The UK remains a major customer for European refined oil products, especially diesel. Two of Europe’s largest refineries are in Rotterdam: one is owned by Shell and the other by BP. Neither company has a refinery in the UK. This explains why UK trade with the Netherlands appears disproportionately high given their population sizes: we export crude oil to them and then import refined products, such as diesel, back.

Chapter 4: Gas use in electricity, heating, chemicals and fertilisers

In 2004, UK gas production was equal to UK consumption; by 2024, UK gas production had fallen to about half of UK consumption, even though UK consumption had fallen by 40% over the same period. The biggest falls in consumption have been in industrial consumption and electricity generation, both now about half their 2004 levels. Surprisingly, UK imports account for about two-thirds of UK consumption because the UK acts as a land bridge for Norwegian gas and US LNG to reach Belgium, Ireland and the Netherlands via UK pipelines.

In 2024, the UK consumed 683,947 GWh of methane, of which

• 37% was used for domestic heating,
• 26% for electricity generation,
• 12% for industrial uses,
• 11% in other energy industries and
• 13% for services.

In 2024, UK domestic methane production was 343,858 GWh, of which 118,427 GWh was exported, and 453,301 GWh was imported.

Figure 18: UK Methane production, consumption and trade

Figure 19: UK Methane consumption by type

Electricity production

In 2025, 31% of UK electricity production came from gas. The UK also requires gas-fired electricity to be on standby to step in when wind generation drops, at night, or on cloudy days. Since the UK fracking moratorium in November 2019, UK non-domestic average electricity costs, including CCL, have risen by 68%, from 13.96p/kWh to 23.47p/kWh, while the cost for small companies has increased by 133%. (Calculations from Q4 2019 to Q3 2025.) Average non-domestic gas prices, including CCL, have increased by 101%, from 2.49 p/kWh to 5.0 p/kWh. Very large gas users have experienced a 114% increase in costs. (Again, calculations are from Q4 2019 to Q3 2025.)

Domestic heating

Gas central heating remains the dominant heating system in UK homes, providing heating for 21.2 million UK households, approximately 86% of all homes. This proportion increases to 90% in urban areas.

Fertilisers, ammonia and other gases

In 2025, the UK produces around 1.2–1.3 million tonnes of mineral fertilisers annually, with nitrogen-based products (ammonium nitrate, urea, NPK blends) accounting for most of it. Domestic production of phosphate and potash fertilisers has largely ceased, with the UK now reliant on imports. Domestic production made using imported ingredients now accounts for less than half of the UK fertiliser demand, with the remainder imported from the EU, North Africa, and North America. Fertiliser production is gas-intensive, so fertiliser production has moved to regions with cheaper gas. UK ETS allowances, as well as strict nitrogen-emissions regulations, have made domestic fertiliser production less competitive with imported fertiliser.

Compared to 2000, UK fertiliser output has halved, and the product mix has shifted away from broad-spectrum fertilisers toward nitrogen-only and imported blends, driven by plant closures, energy costs, environmental regulation, and global market restructuring.

Most fertilisers are made from ammonia (NH₃) produced from natural gas. It takes about 0.9 tonnes of natural gas (methane, CH4) to produce 1 tonne of ammonia. The process requires high temperatures (400–500°C) and pressures (>100 bar), typically generated by coal or gas combustion, although it can also be powered by electricity. Conventional production emits about 2–3 tonnes of CO₂ per tonne of nitrogen fertiliser, plus nitrous oxide (N₂O) emissions from nitric acid production, which can add another 0.2–2 tonnes of CO₂-Equivalent (CO2e) per tonne, depending on abatement technology.

UK ammonium nitrate and other nitrogen-based fertilisers are still produced at Billingham, Teesside, by CF Fertilisers UK, which is the only remaining large-scale fertiliser producer in the UK; however, they use imported ammonia. The Billingham plant was the UK’s largest producer of ammonia, ammonium nitrate and CO2. However, the ammonia plant at Billingham was permanently shut in September 2022 due to high gas prices and was not restarted. The company operates entirely on imported ammonia to produce ammonium nitrate and nitric acid. The plant also no longer runs a steam-methane reformer, so it has no use for UK natural gas.

CF Fertilisers also closed its Ince manufacturing facility in Cheshire in 2022, when European gas prices spiked. The CF Fertiliser plant was one of the dominant industries in Ince; its closure resulted in the loss of 283 jobs directly and many more indirectly. CF Fertilisers’ UK Managing Director described the Ince plant as a ‘high cost producer in an intensely competitive global industry’. He also explicitly warned that carbon-related policy costs were among the reasons for the loss of competitiveness of UK ammonia production. The UK’s Emissions Trading Scheme (ETS) applies to ammonia production. Producing one tonne of ammonia requires 28-35 GJ of natural gas.

The Agricultural and Horticultural Development Board (AHDB) estimates that the UK imports about 60% of the fertiliser it uses. This will result in a Carbon Border Adjustment Mechanism (CBAM) of approximately £50 per tonne being added to the price of imported fertiliser from 2027. The government also intends to add a CBAM on imported ammonia, which would increase costs for domestically produced fertilisers. This will be passed on to farmers, raising the price of domestically produced food. Despite current politicians from many parties promising to reverse the ‘cost of living crisis’, they do not address these increased input costs.

In the UK, fertiliser use typically increases arable crop yields by 30–50% and grassland productivity by 40–60% compared to unfertilised systems. Without fertiliser, most soils cannot supply sufficient nitrogen, phosphate, and potash to sustain high yields; therefore, fertiliser is critical for both food security and livestock forage production. Making fertiliser more expensive than it needs to be, through the addition of an ETS or a CBAM, makes UK-produced foods more expensive or discourages farmers from using it, thereby lowering crop yields. This has been the result of higher fertiliser costs as UK fertiliser use has fallen by 19.3% in the ten years up to 2024,

Although CBAMs are intended to equalise the cost of imported and domestically produced goods, this doesn’t work when the majority of the goods are imported, and the ingredients needed to produce them domestically are also imported. In 2024, the UK imported 3.22 million tonnes of the types of fertilisers and fertiliser ingredients covered by the latest update to the UK’s proposed CBAM. Almost all these imports will have a CBAM applied to both their CO2 and their nitrous oxide emissions. This will increase the cost of food production, as there is no alternative domestic supply.

An alternative market-based solution is to remove the additional 38% Energy Profits Levy (EPL) on gas production, thereby lowering the UK’s domestic feedstock cost for fertiliser production. And encourage new oil and gas exploration. There is already an ETS for the energy used in combustion, and an ETS is charged for the production of ammonia and nitric acid. The EPL constitutes a form of triple taxation, making UK fertiliser uncompetitive with imported fertiliser. Removing these costs would also eliminate the need to impose a CBAM on an essential input for food production and food security.

Hydrogen

Hydrogen is used in refining, fertiliser production, ammonia and methanol production, and in some bus transport.

Almost all hydrogen in the UK is produced by combining methane (CH4) with Steam (H2O) at temperatures between 700 °C and 1,100 °C, releasing 3 molecules of hydrogen (H2) and 1 molecule of Carbon dioxide (CO2). The furnaces use natural gas to generate the required heat, thereby producing CO2 that contributes to the total CO2 emissions from the chemical reaction. The CO2 emitted by the Steam methane reforming plant will require the purchase of ETS allowances for the CO2 emitted during hydrogen production.

In 2025, the UK produced approximately 27 TWh, equivalent to about 0.8 million tonnes of Hydrogen. Most of this, 25 TWh, or 0.75 million tonnes, was generated from natural gas using steam methane reforming without emissions capture. The Hydrogen produced is known as Grey hydrogen. The UK also made a small amount, 1-1.5TWh (30 to 40 kt), of hydrogen using electrolysis powered by renewables, which is known as Green hydrogen. And an even smaller amount, 0.5TWh or 15kt, of hydrogen from natural gas, where the CO2 emissions are captured. This is known as Blue hydrogen. There are currently 2 GW of low-carbon hydrogen production under construction, of which 1 GW will be green hydrogen and 1 GW blue hydrogen.

The government plans to develop 10 GW of low-carbon hydrogen capacity by 2030, with at least half of it generated by renewable-powered electrolysis, and several hydrogen plants are under construction. Although several hydrogen projects have also been cancelled: BP’s H2Teesside Blue hydrogen project, a 1-1.2 GW natural gas-based hydrogen plant, has been cancelled due to weak industrial demand for hydrogen. ScottishPower’s Cromarty and Whitelee green hydrogen projects, expected to produce 17.7 MW, were suspended in 2024 despite receiving government support through the Hydrogen Allocation Round 1 (HAR1).

The closure had a knock-on effect on Aberdeen’s two hydrogen refuelling stations at Kittybrewster and Cove. This grounded the 25 hydrogen-fuelled Hydroliner double-decker buses operated by Aberdeen City Council. The Buses were out of service for over a year because they could not be refuelled. Aberdeen City Council has ended its joint venture with BP and decided to sell its entire hydrogen bus fleet and move to battery-electric buses instead. The Buses were funded by the Scottish Government with £15 million for buses, station upgrades and the Aberdeen Hydrogen Hub, the European Commission JIVE programme invested €2 million, and the Council invested £2.5 million. It was hoped that the program would create 700 jobs.

There is a large cost differential in the various ways of producing Hydrogen: Grey Hydrogen H2 made from Methane, CH4, is relatively cheap at around $2/kg; Blue Hydrogen, also made from methane but with the released CO2 captured, is $3/kg; while Green Hydrogen made using electrolysis to split water powered by renewable energy is $6/kg.

Although the closures of the production plants and hydrogen buses have been a setback for the Hydrogen industry, Hydrogen UK believes there will be 30,000 direct jobs in the industry by 2030, with 64,000 direct, indirect and induced jobs, and predicts its Annual GVA will be £7 billion, with direct GVA of £2.9 billion. Hydrogen UK also believes there will be over 100 organisations across the value chain.

Chapter 5: Steel, cement, ceramics and glass require HEAT

The government plans to build 1.5 million new homes, complete infrastructure projects, maintain industrial capacity, and build large numbers of data centres. The building blocks of construction are steel, cement, ceramics and glass. They are essential but require metallurgical coal and high-temperature heat from gas or coal to produce them, and industrial electricity to finish, shape, and later recycle them.

Steel production

UK steel production capacity has fallen from 15 million tonnes to just 6 million over the last 10 years, while actual production has fallen further to only 4 million tonnes in 2024. The 2025 production figures will be even lower following the closure of the Port Talbot blast furnaces.

Crude steel is produced in a blast furnace using the basic oxygen process, with iron ore and coke as feedstocks. Approximately 70% of the world’s steel is produced this way and relies on coking coal. Steel is the backbone of modern infrastructure, including wind turbines.

A tonne of steel requires 1.7 tonnes of iron ore and 0.77 tonnes of coking coal. Coking coal has 60% to 90% carbon, low sulphur and phosphorous content, and is processed by baking in an anaerobic furnace at over 1000 °C to produce coke. That means about 2.5 tonnes of raw materials have to be imported to make one tonne of ‘virgin’ steel.

The UK only produced about 4 million tonnes of steel in 2024, according to the World Steel Association, down from 5.6 million tonnes in 2023. They imported another 4.1 million tonnes of iron or steel, according to COMTrade.

The UK is planning to replace its blast furnaces with electric arc furnaces, but its high industrial electricity and ETS costs will make this technology uneconomic. Only UK Electric Arc Furnaces that receive government subsidies or have a contract to supply steel to the UK’s defence department are currently in business. EAFs do not produce steel; they require steel feedstock, either steel slabs produced in an offshore blast furnace and imported for shaping or, more generally, scrap steel for recycling. Recycled steel can contain residual elements from its previous use, which can alter its durability and strength. There is another problem with the UK’s steel production converting entirely to EAF steel production: global steel demand is approximately 2 billion tonnes per year, whereas the scrap supply is about a third of this, as steel used in vehicles, machinery, and buildings remains in use for many years before it becomes available for recycling. As the UK has the most expensive industrial electricity in the world due to our carbon taxes, we should not be surprised if the EAFs replacing the UK’s blast furnaces also close at the first opportunity, or they will never be built.

Cardiff-based Celsa Steel UK is a small EAF steel recycler that produces about 1.2 million tonnes of mainly rebar for construction. It has survived by focusing on a single product: the domestic rebar market. Finnish-based Outokumpu Stainless – Sheffield is another EAF that produces 0.7 to 1 million tonnes of stainless steel and high-alloy grade steel annually. It survives because it produces high-value stainless products for UK high-tech and high-value engineering firms, as well as for export. The company is part of a large Finnish multinational with diversified operations. Sheffield Forgemasters is another small EAF, producing less than 0.3 million tonnes annually for the UK’s defence and nuclear industries. It is owned by the UK Ministry of Defence, which acquired it in 2021 to secure critical defence supply chains. This state backing shields it from both market forces and energy cost considerations.

The peak of the UK steel industry was in 1971, when it employed 320,000 people and produced approximately 28 million tonnes of steel.[1] By 2019, employment in the industry had fallen by 92.8% to 23,000 people, and production had fallen to about 7 million tonnes. The UK steel industry doesn’t have a divine right to exist, especially if the UK is not supplying either iron ore or coking coal. Had the Woodhouse mine in Cumbria been operational, virgin steel production could have been justified.  However, the decision to close the blast furnaces was as much a political as an economic one.

Steel production is emissions-intensive: new steel made in a Basic Oxygen Furnace produces 2.33 tonnes of CO2 for every tonne of crude steel produced. Recycled scrap steel using an electric arc furnace produces an additional 0.67 tonnes of CO2 per tonne of steel recycled. Why DRI-EAF steel made by reducing Iron ore with gas or hydrogen instead of coking coal (so-called green steel) still produces 1.47 tonnes of CO2 per tonne of steel.

NetZero Watch estimates that UK electricity prices for UK steel producers are £46.60/MWh, of which about 40% are policy costs, such as carbon-emission charges, and about 20% are network costs. France’s wholesale electricity costs are higher than the UK’s, but when the network and policy costs are added, the UK’s prices are 62% higher than France’s. French steel producers pay £28.74/MWh for electricity, and German steel producers pay £25.00/MWh; both have negligible network costs, and their policy costs are about half of the UK’s. (see Figure 20, below)

Figure 20: Comparative industrial energy costs in Germany, France and the UK

Policy costs include carbon prices and other policies to cover renewable subsidies. While network costs include balancing the system, such as paying electricity generators to turn on and off to maintain the grid’s 50 Hz frequency. As the UK has the highest proportion of intermittent renewables in its grid, these network costs are also higher, and we need backup gas and coal-fired generation for when the wind drops. So effectively, the UK is running two electricity systems at once. According to the Global Warming Policy Foundation, the UK Network balancing cost (BSUoS), has increased from £300 million a year in the early 2000s to £2.7 billion a year in 2024/5. As the UK government continues to increase the number of wind turbines in the system, the network balancing cost will rise as well.

CBAM is not a solution

The UK intends to join the EU’s ETS and CBAM scheme and will therefore be forced to add CBAM to iron ore and to virgin steel imports – unless the UK imports them from the EU. This would increase the costs for the Electric Arc Furnaces (EAFs) in the UK that reshape imported steel, as well as the production costs for UK vehicle and machinery manufacturers. SITC 7 machinery and transport equipment is the UK’s largest export sector, accounting for 43% of total UK goods exports in 2025, but it is threatened by increased costs of its input materials from the EU’s ETS and CBAM.

Joining the EU CBAM scheme would add emission taxes to: Agglomerated iron ores and concentrates; all HS72 Iron and Steel, except for some iron-alloy and critical-metal alloys, and scrap iron and steel; and 13 of the 26 HS73 four-digit codes for articles made with iron and steel. This list includes many of the UK’s most imported iron and steel products, such as HS7308: Structures, scaffolding, pit propping, towers, and lattice masts; HS7306: Tubes, pipes, hollow profiles, and cross sections; and HS7318: Threaded screws and bolts.

What remains of UK virgin steel production

Scunthorpe-based British Steel has the capacity to produce 3-4 million tonnes of steel annually but is currently incurring daily losses of about £700,000. British Steel stated in March 2025;

‘The blast furnaces and steelmaking operations are no longer financially sustainable due to highly challenging market conditions, the imposition of tariffs, and higher environmental costs relating to the production of high-carbon steel.’

British Steel’s Chinese owners, Jingye, sought to close Scunthorpe, but it was ‘saved’ and effectively nationalised in April 2025 by the current government to keep the blast furnaces operating. The government sought to sell the company to another operator, but the emissions costs and the need to import both iron ore and coking coal render it highly uncompetitive globally as a steel producer.

Cement production

The UK cement industry is one of the most concentrated heavy industries in the UK. It employs around 4,000 people, including plant workers, quarry operators, and maintenance and technical staff, and supports an additional 16,000 jobs indirectly through logistics, the supply chain, equipment suppliers, contractors, and services. The industry generates £1.8 billion in direct and induced GVA and has a turnover of between £2.2 to £2.5 billion. There are fewer than a dozen major cement companies operating in the UK.

The UK still produces over two-thirds of the cement it uses domestically, approximately 7.3 million tonnes of cement per year (2024); however, this is roughly half the level produced in 1990. Despite the UK’s plentiful limestone supplies, cement production has steadily declined due to high energy costs, environmental regulations, and rising imports, leaving output at its lowest level since the 1950s. UK cement imports have nearly tripled since 2008, rising from 12% of sales to 32% in 2024. The UK imported 4.14 million tonnes of the types of cement products covered by the EU’s proposed CBAM. For context, we exported less than 700,000 tonnes of the same products. 540,000 tonnes of which were HS 25070080 Kaolinic clays (other than Kaolin). This is the UK’s largest Cement export, yet the Government tells us we need to join the EU ETS and CBAM to help UK exporters. This will just make UK cement imports more expensive.

Traditionally, cement producers used coal as the primary fuel in cement kilns to generate the 1,450°C thermal energy required to convert the calcium carbonate found in Limestone to Calcium oxide (CaO), which is then combined with various oxides to make clinker materials; coal has been increasingly replaced by gas, which has lower CO2 emissions per tonne of clinker. However, gas is more expensive than coal, so the savings on emissions allowances are partially offset by the higher gas price. Many producers have turned to Refuse Derived Fuels (RDF) and biomass. The clinkers are then cooled and ground using electricity to make cement powder.

Cement production is highly carbon-intensive, emitting up to 0.9 tonnes of CO2 per tonne of cement and is therefore subject to high carbon taxes. Producers must purchase UK ETS allowances to cover their direct emissions and pay the Climate Change Levy, which is added to their electricity bills. But producers must also pay the indirect Carbon Price Support (CPS) and ETS costs of their power suppliers, which are passed on in higher wholesale electricity prices. Cement production is classified as an electricity-intensive industry (EII), so it receives compensation for indirect CPS costs and partial compensation for indirect ETS costs, and receives a 92% discount on the CCL rate.

Most of the emissions from cement production are intrinsic to the process. Almost two-thirds of the emissions arise from the calcination process, which releases one CO2 molecule for each CaO molecule, regardless of the heating method used, although producers typically use coal, gas, or RDF to provide the required heat input. Approximately 30% of the emissions come from the heat-source fuels, and less than 10% from the electricity used for factory equipment, such as grinders, fans, and conveyor belts.

In addition to the UK Emissions Trading Scheme (ETS), cement producers face several environmental taxes and regulatory obligations: the Climate Change Levy (CCL) on energy use, the Aggregates Levy on rock, sand and gravel used in concrete, the land fill tax on cement plant waste, strict Environmental Permitting Regulations limiting emissions of NOx, SO2, particulates and dust emissions, and compliance with the UK’s Net Zero 2050 targets. The UK industry is highly regulated; however, imported cement may not be subject to the same level of regulation. All of these taxes and regulations are designed to raise costs and push the industry toward decarbonisation, but the proposed CBAM will not compensate producers for these costs; it will only compensate for the differential between domestic and imported ETS costs.

Cement producers are under pressure to adopt Carbon Capture and Storage and to use alternative fuels to meet Net Zero targets. There is currently a CCS project to build a high-pressure CO2 pipeline to transport captured CO2 from cement and lime plants in Derbyshire and Stafford to a geological storage site 121 miles away under the Irish Sea.Backed by the National Wealth Fund and currently in the pre-application planning stage, there are concerns about the pipeline’s safety: it will operate at high pressure, and leaked concentrated CO2 can displace oxygen at ground level, killing humans and animals in the vicinity. This actually happened in Satartia, Mississippi, in 2020, so it is not idle speculation. A pipeline carrying dense-phase CO2 at high pressure ruptured following a landslide, hospitalising 45 people. People couldn’t escape the area as cars and emergency response vehicles couldn’t operate in the oxygen-depleted air.

There are also concerns about whether the UK storage site in the Irish Sea can hold more than 10 million tonnes of CO2 per year. An alternative solution would be to accept that the dilute CO2 released during cement production is less dangerous than high-pressure, concentrated CO2 piped across farmland.

Ceramics production

The UK ceramics industry contributes more than £1.5 billion annually to the economy, generates £600 million in exports, and employs over 20,000 people across more than 150 sites. It is a world leader, combining advanced recognised heritage brands.

Governments overlook the strategic importance of ceramics, which enable the production of steel, glass, and other high-temperature products. Ceramics are also critical to aerospace, defence, IT, national security, housebuilding, and electricity distribution. In 2012, 89% of production consisted of heavy clay construction products, and only 11% comprised refractories, whitewares, and technical ceramics. Refractories, such as heat‑resistant materials for kilns, furnaces, steelmaking, and technical ceramics, are used in electronics, aerospace, and engineering, as well as in ceramic components for industrial processes. Construction products include roof tiles, floor tiles, bricks, sanitary ware and architectural ceramics.

Ceramics is an energy-intensive industry that requires kiln firing and drying. Kilns operate continuously at extremely high temperatures, often around the clock, and energy demand cannot simply be switched off. The energy used is predominantly natural gas, accounting for approximately 86% of the sector’s total energy use. There are also process emissions resulting from chemical changes in the raw materials during firing.

Analysis from Nottingham Trent University suggests that UK ceramics firms spend 70% of their turnover on energy costs and 14% on government and regulatory levies.Energy costs have increased by more than £330 million since 2020, reaching £875 million annually.

Ceramics companies must buy carbon allowances on the ETS market for every tonne of CO₂ emitted. Prices have ranged from £30 to £100 per tonne since 2021. This is an especially high cost for Heavy‑clay ceramics (bricks, tiles, pipes) because firing temperatures are high and firing is continuous. Ceramics companies also pay the Climate Change Levy (CCL) on every unit of energy unless they have a Climate Change Agreement, which can give up to 92% discount on the levy if firms meet energy‑efficiency targets. Reducing energy costs is essential to sustaining these industries and enabling them to thrive.

As energy-intensive industries, they will get discounts on their electricity bills, reducing the cost of contracts for the difference levy, the renewable obligation levy and the feed-in tariff levy. If they sign up for the Ceramics Climate Change Agreement and meet its energy-efficiency targets, they will also receive a 92% discount on the Climate Change Levy for electricity and an 89% discount on the CCL for gas.

However, the ceramics industry’s primary energy source is gas, not electricity, and it must still pay for carbon emissions, comply with carbon reporting obligations (SECR and ESOS), and cover the costs of industrial emissions monitoring for NOx, SOx, and particulates, as well as permitting fees.

The government has proposed shifting some of its carbon taxes, currently applied to electricity, to gas to reduce electricity prices. This would likely be the final straw for the UK ceramics industry and other sectors that rely on high-temperature processes.

Glass production

The UK glass sector contributes over £2 billion to the economy, employs 6,000 directly and provides more than 120,000 jobs across the supply chain. The sector produces around 3 million tonnes of glass, including 2.2 million tonnes for container applications and 0.8 million tonnes for flat glass and wool. In 2024, UK glass exports were worth £1.14bn, down 4% on 2023. The volume of exports was also down 8% to 803 thousand tonnes. The value of glass imports fell 4% to £2.1bn, while the volume rose 3% to 1,215 thousand tonnes. Over a quarter of the UK’s glass imports by value came from China in 2024.

Glass is a highly energy-intensive industry, consuming approximately 6.2 TWh in 2024, with over 5 TWh from natural gas and almost all the rest from electricity. Over the period to 2050, the industry anticipates that overall energy use will decline and the energy mix will change dramatically. By 2050, almost all gas use will be eliminated, with the vast majority of energy coming from electricity and the balance from hydrogen and a small amount of biomethane.

The problem with this approach is that industrial electricity costs far more than industrial gas. In the first quarter of 2025, electricity for very large industrial users cost 22.91p/kWh, whereas gas for large users cost 4.69p/kWh (both including taxes), some five times less. Shifting the energy mix to electricity will substantially increase costs. Consequently, European glass manufacturer Ardagh’s next-generation electric-hybrid furnace, which achieves a 64% reduction in carbon emissions, will be located in Germany rather than the UK. It is hard to believe that this decision was not due to the UK’s higher industrial electricity costs.

The glass industry receives environmental policy reliefs worth about £158m per year, including an exemption from the Climate Change Levy, an ETS allowance and a “supercharger enhanced package”. Effectively, the government recognises that its policies have made energy too expensive and offers partial relief by subsidising heavy industry to offset subsidies for renewable electricity.

Falling Employment

The impact of high energy costs can be seen in the hours worked per week across the ceramics, glass and cement industries, together making up SIC code 23 in ONS statistics. From 1997 to 2024, hours worked per week have declined by 48.8%, while GVA has increased by just 6% in CVM, indicating an industry in decline. However, in 2021, GVA was 20% higher than in 1997. Indicating that when gas prices are low, the industry is competitive.

Figure 21: Annual hours worked, Manufacture of rubber and plastic products, and other non-metallic mineral products, SIC 22 and 23.

Chapter 6: UK car and aircraft production relies on aluminium and steel

The UK’s largest export industry, measured by value, is the production of machinery and transport equipment. Both require large amounts of steel and aluminium. Having addressed the steel sector in the previous chapter on construction, this section primarily covers aluminium. Aluminium production is extremely energy-intensive; approximately 40% of the energy used to make aluminium comes from gas and LPG, with 50% provided from electricity, of which about a third is also produced from gas in the UK. In primary aluminium production, electricity also accounts for approximately 30–40% of total production costs and is the largest single input after alumina or bauxite.

Figure 22: Electricity and gas needed to produce aluminium

The UK has almost no primary aluminium smelting capacity left and produces only 5% of the aluminium it uses domestically. UK aluminium imports were primarily rolled aluminium used in the manufacture of vehicle and aircraft parts. The UK’s aluminium exports consist of 60% scrap and 25% unwrought aluminium. The UK government plans to join the EU’s Carbon Border Adjustment Mechanism (CBAM) on imported aluminium in 2027, increasing the costs of downstream producers of vehicles and aircraft parts; some 80% of UK-produced cars and almost all UK-produced aircraft parts are exported. These products must remain competitive in global markets, or they too will join the UK’s industrial graveyard: The UK is the world’s largest supplier of aircraft parts, exporting 40% more than the second largest exporter, Germany, and almost twice as much as the US. The country cannot afford to lose this industry.

In 2000, the UK produced 320,000 tonnes of aluminium from three smelters. In 2009, the Anglesey Aluminium smelter in Holyhead, which produced 142,000 tonnes of aluminium per year, closed because its cheap electricity contract with the Wylfa nuclear reactor expired, and EU state-aid rules blocked the contract’s renewal. In 2012, Britain’s largest smelter, Lynemouth in Northumberland, which produced 178,000 tonnes of aluminium a year, closed due to rising energy costs and the EU’s environmental directives, including the Large Combustion Plant Directive, which limits emissions from coal-fired power plants. The UK now has one remaining smelter, Lochaber in Fort William, Scotland. It produces just 48,000 tonnes of aluminium a year but has its own dedicated hydroelectric power supply, so it is not subject to ETS or CPS costs.

In 2024, the UK imported 1.2 million tonnes of aluminium and articles of Aluminium, 40% of which (by weight) were plates, sheets, and strips greater than 0.2 mm in thickness, which will be used as raw materials by UK manufacturers. The UK also imports all its bauxite and alumina for the small amount of domestically produced aluminium. Aluminium imports have increased by 44% since 2005. More worrying is the 105% increase in imported structures made from aluminium: bridges and bridge-sections, towers, lattice masts, pillars and columns, roofs, roofing frameworks, doors and windows and their frames and thresholds for doors, shutters, balustrades, of aluminium; and plates, rods, profiles, tubes and the like, prepared for use in structures, of aluminium. These goods could have been produced in the UK if we had not forced the closure of UK smelters by applying the same emissions taxes, regardless of whether the aluminium is used in an aircraft that will last for 30 years or in a drink can that will last for a matter of months before being recycled.

The car industry

The UK car industry is one of the UK’s most valuable export industries, but it relies on imported steel and aluminium, both in raw form and as components. The UK government’s decision to mandate all new car sales to be electric vehicles (EVs) by 2030 has also had a devastating effect on the UK’s Internal Combustion Engine car producers. Smaller producers, such as Aston Martin, do not need to comply with the EV mandate. However, larger manufacturers not only have to convert their factories to produce EVs but also face substantial fines if they sell more than the allowed number of ICE vehicles in any month. In 2026, 33% of all new car sales must be zero-emission vehicles (ZEVs), with hybrids and ICE cars making up the balance. The fine is currently £12,000 for each ICE car exceeding the limit. The proportion of ZEVs that must be sold will increase each year. No solely ICE-powered cars can be sold in the UK after 2030, and no new hybrids may be sold after 2035. Only zero-emission vehicles (ZEVs) and hydrogen fuel-cell powered cars can be sold after that. Unfortunately, this mandate measures only tailpipe emissions, not total manufacturing emissions.

The Aerospace industry

The UK is the world’s largest exporter of aircraft parts: from jet engines to wings, seats, and landing gear. The production of these parts also requires ample aluminium supplies. Unfortunately, as already discussed, the UK’s larger aluminium smelters were forced to close due to their high emissions costs. The UK’s only remaining smelter, located in Lochaber, Scotland, and powered by hydroelectricity, does not produce enough aluminium to meet the needs of the aircraft parts industry.

But the demise of the UK’s aluminium smelters is not solely due to the imposition of an ETS. The UK’s industrial electricity is more than three times as expensive as the average US industrial electricity, and more than five times as expensive as industrial electricity in the US states of Louisiana, New Mexico, Oklahoma and Texas, which have the lowest industrial electricity costs. Without access to bauxite or low-cost power, the UK will remain reliant on imported aluminium for car and aircraft production.

Aluminium production is energy-intensive and produces 15 tonnes of CO2 for every tonne of new aluminium produced. That said, it is readily recyclable, so its emissions should be amortised across multiple product generations, and if used in vehicles and aircraft;; its ETS should be divided by the product’s expected lifespan in Environmental Impact Assessments.

There is a report that the Germans are seeking to encourage one of the UK’s main aircraft firms, Rolls-Royce, to relocate the manufacture of the next-generation Ultrafan jet engine to Germany. If the UK continues to make manufacturing expensive and compliance-laden, it will be no surprise if companies seek more welcoming locations for their factories. While Germany has many of the same Net Zero regulations as the UK, it has not imposed a carbon tax on industrial energy, unlike the UK, but puts the cost of subsidies on general taxation.

UK policy costs include carbon prices and other policies to cover renewable subsidies. Network costs include balancing the system, such as paying electricity generators to turn on and off to maintain the grid’s frequency at 50 Hz. As the UK has the highest proportion of intermittent renewables in its grid, these network costs are also higher, and we need backup gas and coal-fired generation for when the wind drops. So effectively, the UK is running two electricity systems at once. According to the Global Warming Policy Foundation, the UK Network balancing cost (BSUoS) has increased from £300 million a year in the early 2000s to £2.7 billion a year in 2024/5. As the UK government continues to increase the number of wind turbines in the system, the network balancing cost will rise as well.

Chapter 7: Businesses beyond industry

Leisure and sport

It is not just industry that is being devastated by the UK’s self-inflicted high energy costs – sports, leisure and events venues also consume large amounts of energy and have had to consider their viability over the last few years. These businesses generally do not qualify as Energy Intensive Industries for discounted ETS charges, but they will be subsidising the ETS costs of the industries that do qualify.

Ice Rinks and Curling Centres

Ice rinks across the UK are closing, and others are threatened with closure due to massive and “unprecedented” increases in the energy costs of maintaining their ice floors. Ice rinks are heavily energy-intensive due to their size and use of refrigeration, lighting, and dehumidification.

The Plymouth Pavilions Ice Rink, a local fixture for some thirty years, closed on 1 January 2023 after it was branded as “wholly unsustainable” due to high energy costs. The Ayr ice rink – home to 550 skating members and forty curling clubs – closed permanently in September 2023 after 50 years of operation. Its annual energy costs doubled to £ 153,000, with another £150,000 required. Its daily energy bill rose from £419 to £880; finding an additional £461 a day, every day, just couldn’t be done.

Even in London, the ice rink at the Sobell Leisure Centre in Islington did not reopen after being closed during the pandemic. Its high energy costs, which accounted for 70% of the centre’s total electricity consumption, were given as the main reason.

Inverness Ice Centre has had to close its ice rink for three months of the year since 2023 due to spiralling energy costs of refrigerating its ice floor. The cost of operating its refrigeration plant more than doubled, from £12,000 to £30,000 per month. Inverness went ice-free from April to July outside the curling season and instead hosted a whisky festival, boxing, music, and videoed football events to cut costs and raise income.

Other Scottish rinks, such as Aberdeen, Perth, Forfar, and Elgin, have experienced the same difficulties and have had to adjust their annual opening schedules. In 2023, Scottish Ice Rink Association president Mike Ferguson said his Forfar business’s monthly gas bill was set to rise from £2,000 to £14,500, while in April 2025, Curl Aberdeen reported its energy costs had rocketed by £160,000 a year. Perth City Council has recommended merging two leisure centres into a new venue without an ice rink. The cost of energy for ice rinks remains an existential threat to curling and skating, which have traditionally been Team GB’s most successful Winter Olympic sports.

Swimming pools

Rising energy costs have forced many swimming pools to implement drastic measures, including permanent closures, temporary winter shutdowns, and temperature reductions to remain viable.

Over 65 public pools closed in the UK between 2019 and 2022, either temporarily or permanently, due to a combination of rising energy costs, staff shortages, and chemical supply issues. Industry bodies like Community Leisure UK warned in 2023 that up to half of the UK’s community pools could face closure or service cuts without sustained government intervention. Swim Wales also warned that 150 of 500 pools faced a similar threat of closure.

Some leisure operators reported their annual energy bills tripling or more; for example, Freedom Leisure saw its nationwide energy costs rise from £8m to £20m, while individual sites have seen annual costs jump from £180,000 to over £600,000.

To offset costs, approximately 15% of UK councils have permanently or temporarily lowered pool temperatures, typically by about one degree. Other facilities have reduced opening hours or closed energy-intensive features, such as saunas.

Examples include Batley Baths in West Yorkshire, which was permanently closed due to soaring energy and operational costs, and New Forest District Council, which closed saunas across several leisure centres to save on energy costs.

The nationwide problem caused the UK Government to introduce a £63m investment fund to help pools manage immediate energy pressures and transition to ‘more energy-efficient systems’ like heat pumps and solar panels. The Energy Bill Relief Scheme was introduced to provide temporary wholesale price discounts for non-domestic users, including pools.

 

Chapter 8: New industries the UK will miss out on due to high energy costs

Chapter 8: New industries the UK will miss out on due to its high industrial energy costs

AI, Data centres and cloud computing

The Labour government has placed significant faith in the development of green jobs in the AI and data centre industries. However, these industries require dispatchable power from gas, biomass, and nuclear sources. And they need it now. Unfortunately, the UK plans to add another 50 GW of intermittent offshore wind by 2030 and 70 GW of intermittent solar and onshore wind; these will not produce the dispatchable, constant power required by AI and Data Centres. The UK will need to increase gas production to meet the required energy demand.

The Construction of Data Centres also requires large amounts of cement and steel. The American Cement Association predicts the US will need 1 million metric tonnes of cement by 2028 just for AI data centres. While a single hyperscale AI data centre requires up to 20,000 tonnes of Steel.

The full deployment of pledged AI investment in the UK hinges on critical infrastructure upgrades, especially in energy supply, energy costs, and energy connections.

The UK AI Energy Council projects a 20-fold increase in compute capacity over the next 5 years. Typical data centres can consume up to 100 MW per site, equivalent to powering 75,000 homes. Microsoft’s planned supercomputer alone will use 23,000 NVIDIA GPUs, requiring hundreds of megawatts of sustained power. In March 2024, it was announced that Amazon had bought a 960MW data centre that is powered by an adjacent nuclear power station.  Microsoft has also announced that it has struck a deal with US utility Constellation to restart the 835MW Three Mile Island (TMI) Unit 1 nuclear power plant to power its data centres. In late 2024, Sam Altman of ChatGPT proposed building massive 5GW AI data centres. To give an idea of scale, each of these data centres would consume about 1.5 times the output of the Hinkley Point C nuclear power plant under construction.

Tech industry leaders, such as Jensen Huang, President, Co-Founder, and CEO of Nvidia, have warned that UK electricity prices are the highest in Europe and that natural gas turbines will be required alongside nuclear power to meet energy demand. The UK’s ban on fracking, reluctance to develop new oil and gas fields in the North Sea, and reliance on imported gas are likely to constrain short-term energy availability, while the UK’s energy taxes make its industrial electricity the most expensive in the world. The UK must also upgrade its grid connection process to enable the rapid onboarding of high-demand data centres and reform planning laws and grid access rules to accelerate deployment. Microsoft cited the UK’s stable and open regulatory environment as a key factor in its investment decision—but also warned that planning and energy reforms must continue. Regulatory stability in the oil and gas sector is also necessary for investment in this area to increase.

This massive investment in AI and Data Centres is happening at a time when the UK is mandating that all new car purchases be electric and that electric heat pumps are used for domestic heating. Grid connection bottlenecks are delaying critical infrastructure: more than 600 GW of proposed renewable energy generation projects are awaiting grid connection. The National Energy System Operator (NESO) believes this backlog can be reduced to viable projects aligned with the UK’s national priorities, including data centres, EV charging hubs, and heat pump clusters. The National Grid also requires an annual investment of £18.4 billion for infrastructure expansion, transmission, distribution, new interconnectors, substations, and digital grid upgrades, along with planning reforms for new nuclear and, possibly, new gas turbines.

The US-UK Tech Prosperity Deal agreed last year includes: a£150 billion Tech Prosperity Deal; A civil Nuclear Cooperation covering a partnership between the UK’s Centrica and X-energy to build advanced modular reactors in the UK; Defence technology and cybersecurity covering AI command centres, cyber resilience and Quantum Encryption Trials; and an additional £10 billion investment in LNG contracts, semiconductor R&D, fab investment pledges and pharmaceutical licensing and distribution for biotech therapies.

The pledged new investments will require an additional 770 MW of steady, reliable dispatchable electricity, which can only be provided by gas turbines, biomass, or nuclear plants. The annual energy consumption of these projects will be 6.75 TWh, roughly 5.2% of the UK’s 2025 dispatchable electricity output, estimated at around 130 TWh. This represents a significant portion of the UK’s grid’s firm capacity. It highlights why project investors are considering on-site generation, SMRs, and dedicated power purchase agreements to secure their electricity supply.

In addition to the newly announced investments, the projected electricity demand from projects already in planning or under construction exceeds 540 MW, with an annual consumption of 5.6 TWh, representing approximately 4.3% of the UK’s dispatchable electricity production.

Hydrogen-powered equipment and buses

The UK’s Heavy machinery manufacturer, JCB, and the UK bus manufacturer Wrightbus have both invested in the production of hydrogen-powered vehicles. Hydrogen is widely regarded as a superior solution for heavy vehicles than lithium battery technology. While this is commendable, the UK currently produces very little hydrogen, and almost none is low emission.

The UK’s Wrightbus Hydroliner buses run on hydrogen and are in use in London, Belfast, and Birmingham. They were also trialled in Aberdeen, but this trial was recently abandoned, as discussed earlier in this paper. However, only the Aberdeen buses were refuelled with green hydrogen produced using renewable electricity; the others primarily use grey hydrogen made from natural gas. JCB has also developed a hydrogen combustion engine for construction and agricultural equipment.

Hydrogen is generally transported by converting it to Ammonia or Methanol. In 2024, the UK imported just 537 tonnes of hydrogen. Almost all of it is from the Netherlands or other EU countries, with only 5 tonnes imported from the US.

As hydrogen is considered a better fuel source for heavy transportation and equipment, with only water as a tailpipe emission, imposing additional taxes on UK production and a CBAM on imported hydrogen seems counterproductive. Surely, making hydrogen production cheaper by reducing taxes on UK gas production would be better for the environment overall. Otherwise, the UK could miss out on the benefits of an industry championed by two UK companies.

Greenhouse technology for food production

Modern greenhouses enable year-round production of summer vegetables, reduce the amount of product lost to frost and pests, but are also energy intensive. Using greenhouse technology in the UK will be hampered by the UK’s high industrial electricity costs. Greenhouse-intensive agriculture relies heavily on heating, lighting, cooling, irrigation, and environmental controls, with heating and lighting being the dominant energy inputs. Greenhouses can consume up to 10 times as much energy per unit area as open-field farming. Energy audits show that heating and lighting together often account for more than 80% of total energy consumption.

Greenhouses are highly energy-intensive because they maintain controlled environments year-round. Although drier, sunnier countries do use solar electricity, if a country has adequate rainfall and sunlight, the additional requirements of greenhouses seem superfluous. However, growing plants in waist-high troughs makes picking easier, while the greenhouse environment reduces damage from frost, pests, and pestilence.

The key energy-consuming components include:

• Heating is the largest energy input, often accounting for 50–70% of total energy use in temperate climates. This is typically supplied by natural gas, propane, or electricity for boilers and radiant heating systems. In cold climates, heating demand accounts for most energy consumption (e.g., maintaining an indoor temperature of 60–70°F). The CO2 emissions from the gas-fired heating are usually captured and pumped into the Greenhouse to increase the plant growth rate.
• Lighting using High-intensity lamps (HPS or LED) for photosynthesis during low sunlight periods. Lighting can account for 20–30% of total energy use, especially in winter or for crops that require long photoperiods. LEDs are increasingly used for efficiency gains.
• Cooling and Ventilation Fans, evaporative cooling pads, and, in hot climates, air conditioning. Energy demand varies seasonally but is critical for maintaining temperature and humidity.
• Fertilisers, fungicides and pesticides made from hydrocarbons are used to encourage plant growth and limit leaf mould and pests.
• Irrigation, Water Heating, and Pumps for water circulation and, in some cases, for heated water to control root-zone temperature. Energy use depends on crop type and irrigation system design.
• Environmental Control Systems for climate control, CO₂ enrichment, humidity regulation, and shading. These systems consume electricity for sensors, controllers, and actuators. Storage refrigeration adds incremental but necessary energy demand.

Synthetic hyperdense hydrocarbon-based fuels and ultra-efficient ICE engines.

Synthetic hyperdense hydrocarbon-based fuels and ultra-efficient ICE engines are advanced technologies that aim to improve fuel efficiency and reduce emissions. They are made from hydrogen + captured CO₂, or from biogenic sources upgraded to drop-in hydrocarbons. They are designed to have very high energy density per litre—higher than that of conventional petrol, diesel, or jet fuel. This matters most for aviation, shipping, defence, and space, where weight and volume are critical. Chemically similar to oil-based fuels, they can often be used in existing engines, pipelines, and tanks.

Ultra-efficient ICE engines are next-generation internal combustion engines designed to extract all the energy from a litre of fuel by targeting very high thermal efficiency, advanced combustion strategies, and sophisticated turbo- and supercharging. They are optimised for specific fuels made from hydrogen, ammonia blends, or tailored high-octane / high-cetane liquids. Integrated with hybrids: Engines run in narrow, ultra-efficient operating windows, with batteries handling transients.

Considering the importance of vehicle, aircraft and defence manufacturing in the UK, it would be unwise for the UK to go all in on EV technologies when it lacks commercial battery production, while ignoring other developments such as ultra-efficient ICE engines and hyperdense fuels. Developing synthetic fuels plays to the UK’s strengths in Chemical manufacturing as well as vehicle and aircraft manufacturing.

Chapter 9: Geostrategic security from domestic oil, gas and coal

Overall, UK oil and gas trade volumes in 2024 were broadly stable compared with 2023, with imports rising 2 per cent and exports falling 6 per cent, though this masks some variation by fuel. UK Import dependency increased to 43.8% in 2024, up from 40.3% in 2023. (DUKES published 31 July 2025). However, energy security has emerged as a central theme for the UK’s oil and gas industry, particularly in light of Russia’s invasion of Ukraine, its impact on European gas supplies, and political upheaval in Norway, as domestic energy prices have increased due to additional EU demand.

Some commentators – such as Professor John Underhill at the University of Aberdeen – correctly argue that dependence on imports exposes the UK to excessive geopolitical and economic risks, and have called on the government to adopt a policy approach that balances energy security with environmental sustainability and climate concerns. This is now more important than ever.

Now, the US and Israel’s conflict with Iran has again made energy security front-page news. Iranian attacks have damaged Qatari LNG production at Ras Laffan, the world’s largest LNG complex, which exports between 77 and 81 Mtpa, equal to about 20% of Global LNG supplies. The Iranians also damaged Bahrain’s Bapco refinery, which produced between 260,000 and 380,000 barrels per day. This is Bahrain’s most important energy asset. Saudi Arabia’s Petroline (East West pipeline) is able to reroute crude export to Yanbu on the Red Sea to avoid Iranian attacks on tankers in the Straits of Hormuz. But the pipeline currently transports 5 million barrels per day, while Saudi Arabia’s historical seaborne crude exports ranged from 6.1 to 7.5 million bpd. Abu Dhabi National Oil Company’s Hashan-Fujairah oil pipeline can funnel another 1.5 million bpd to the Gulf of Oman, also avoiding the Strait of Hormuz.

Economic theory versus reality

International economic theory assumes that imports will always be available, and so it is economically rational to replace domestic production with cheaper imports, but this theory falls apart when the price of imported products is driven above domestic prices due to an international supply squeeze, or when imported products are not available at all due to war damage or foreign governments banning exports to ensure their own domestic supplies.

Supply squeezes due to war damage have increased oil and gas prices, as well as other hydrocarbons and petrochemicals that UK manufacturers have become accustomed to importing. And although the UK imported about 33.6 million tonnes of HS2711 Gaseous hydrocarbons in 2025, 70% of them came from Norway, and 22% from the US, which technically do not have a supply problem, but countries that were reliant on Qatari LNG will now be trying to move their purchases to US and Norwegian supplies by bidding up their price. This will also be true of countries that rely on crude oil supplies from Iran or Bahrain. Iran exported 67 million tonnes of Crude in 2023 (the most recent figures); one-third was bought by China, with the rest going to unspecified Asian countries.

Qatar supplied less than 2% of the UK’s gas imports in 2025, well below the 12% it supplied in 2022. In 2024 (the most recent trade data), Qatar exported just over 100 million tonnes of gas, with China and India each buying about 20%, South Korea buying 15% and Pakistan and Taiwan each buying about 6%, followed by Singapore, Japan, Bangladesh, and Thailand. The scramble for other suppliers will push up prices for US, Australian, and Malaysian LNG, and potentially for Norwegian natural gas if countries are connected by pipeline.

During the 2022 hydrocarbon price spike, caused by panic buying by UK and German gas companies fearing immediate sanctions on Russian gas supplies. This pushed up the price of UK and EU gas to 10 times the US Henry Hub price. The Conservative government’s response was to add an additional 25% Energy Profits Levy (the windfall tax) on the UK oil and gas industry. This was precisely the wrong response. The government claimed the levy would raise £15bn to subsidise UK gas consumers; however, this was entirely the wrong response. The only effective cure for high prices is to let prices encourage increased supply and lower demand. Subsidising demand by taxing supply led to the opposite: people continued to use gas while suppliers produced less to avoid the extra tax. UK production has continued to fall since the EPL has been in place, and both the Conservative and Labour governments have responded to the lower production by increasing the rate from 25% to 35% and then 38% and extending the period over which the levy would be applied to 2030.

To add to the absurdity of the UK’s windfall tax, the EU’s sanctions on Russian oil and gas never fully materialised; only some of the supply chains shifted. Russia continues to produce oil and gas, and the EU continues to import it. In 2024, the EU imported 54 billion cubic metres of Russian gas and 13 million tonnes of Russian oil directly, as well as refined oil from India, most likely refined from Russian crude. In 2024, India imported 240 million tonnes of crude oil, of which 37% came from Russia. The main result of the price squeeze was that Russian producers were getting higher prices for their oil and gas, which helped Putin pay for his invasion of Ukraine. The current war with Iran will also increase Russia’s oil and gas revenues.

There would have been a massive geostrategic benefit if the UK had done the exact opposite of the Windfall Tax and instead lowered its taxes on UK oil and gas producers, encouraging them to increase production for domestic use or for export to the EU. The EU could not walk away from its Russian oil, gas and coal supplies because it had no alternative suppliers. Most EU countries have very little or no domestic oil and gas resources. Germany did not even have an LNG terminal in 2022. It had to build some so that it could import LNG from the US, while the UK, which is connected to the EU’s gas pipelines, acted as a land bridge for US LNG rather than selling UK gas to the EU.

The sanctions against Russia had a minimal impact on Russian or global oil and gas production. In Figures 23 and 24 below on international oil and gas production, the drop in production during COVID is noticeable, while Russia’s invasion of Ukraine, EU sanctions, and the destruction of the Nord Stream pipelines are not. Global supplies of both oil and gas have increased, despite sanctions on Russia, the world’s second-largest hydrocarbon exporter in 2024, after the US and ahead of Saudi Arabia.

For the benefit of Ed Miliband and other UK politicians: There is no such thing as a Global price for oil or gas; the prices are determined by supply and demand at the source of the oil and gas, the grade of oil, the composition of the gas, and the ability and the cost of transporting and insuring the oil and gas to the place that demands it. Right now, on Monday, 9th March, a week after the US and Israel attacked Iran and Iran responded by attacking the production facilities of other Gulf oil and gas producers: the UK natural gas and the EU TTF gas prices are up by 5%, while the US Henry Hub price is down by 2.5%. The three prices are quoted in different units and currencies, but, converted, the UK and TTF prices are roughly the same, but they are over six times the US price. Similarly, US West Texas Intermediate and UK Brent Crude are both light sweet crudes, but Brent is currently $99.57/barrel (+6.70) while WTI is only $94.05 (+3.47).

Transport and insurance costs add to the cost of imported oil and gas in peacetime but increase considerably during wars, terrorist attacks, and blockades. Not only have oil prices increased by between 35% and 135% since Iran blocked the Strait of Hormuz, but Very Large Crude Carrier (VLCC) rates have quadrupled to $800,000 per day, and war-risk insurance premiums have increased by almost 7 times. Pipeline prices that avoid the Strait of Hormuz by crossing Saudi Arabia, Oman and Turkey have also increased as demand for them has grown.

Pipelines help to reduce these costs by avoiding chokepoints, and there are various transnational pipelines as well as pipelines linking inland wells and fields to export terminals. Russia has pipelines connecting its oil to Belarus, Poland, Germany, Slovakia, Hungary, the Czech Republic and China. Azerbaijan has pipelines connecting it to Georgia and Turkey; Kazakhstan has pipelines connecting it to China and the Black Sea; Iraq has a pipeline to Turkey; and Canada has two pipelines taking its oil to the US.

Pipelines reduce transport costs, secure supply lines for landlocked producers, and unsurprisingly, enforce geopolitical dependencies. For example, the EU remains dependent on Russian oil and gas four years after its invasion of Ukraine. Pipelines can be the cheapest way to transport oil if volumes are steady, the terrain is not extreme, and if the pipeline is already built and amortised.

Pipelines connecting the North Sea gas to the UK and the UK’s lack of gas storage also ensure that North Sea gas cannot be ‘sold to the highest bidder’ and transported ‘elsewhere’, as many commentators claim. The UK does not have an LNG plant and can only supply gas to countries connected to it by pipeline: Ireland, Denmark and the Netherlands.

Weather and maintenance disruption can be as devastating as warfare

Tropical Cyclone Narelle hit north-western Australia on March 26th, damaging Australia’s main LNG production and closing ports. This is incredibly badly timed, coinciding with the conflict in the Persian Gulf. Australia produces 20% of global LNG and is the 3rd-largest LNG exporter after the US and Qatar. Qatar and Australia together provide about 40% of global LNG, and like Qatar, most of Australia’s LNG exports go to Asia: predominantly Japan, China, South Korea and Taiwan.

Most of the disruption has affected Chevron’s Gorgon and Wheatstone plants and Woodside’s North West Shelf Karratha plant, which together provide 8% of global LNG supply. This will lead to intensive competition for flexible cargoes as Asian buyers bid against the UK and the EU for non-Australian and non-Qatari LNG. While this may not disrupt UK supplies, it has definitely increased the price the UK will have to pay for the 20% of its gas that it imports from the US as LNG.

Maintenance by international suppliers

To add to the UK’s energy insecurity, Norway is due to reduce its gas exports by a third during the summer of 2026 while it carries out major maintenance work on its pipeline and processing facility. Norway will cut exports by 50 million M3/day from April to June and 75 million m3/day from August to September. These cuts will be spread across exports to both the EU and the UK; however, the UK should expect about a third of the reductions, as a third of Norway’s combined UK and EU gas exports go to the UK. Norway supplies about three-quarters of UK gas imports.

Figure 23: Global gas production is unaffected by sanctions on Russia after 2022

Figure 24: Global oil production is unaffected by sanctions on Russia after 2022

Fracking and Russian disinformation campaign

It is highly likely that all of the anti-fracking scare stories are either simply basic human fear of innovation (surprisingly common throughout history) or stories spread by vested interests who have the most to lose from an energy-independent UK. The Centre for European Studies found that the Russian government has invested €82 million in NGOs campaigning against shale gas. The former Secretary General of NATO, Anders Fogh Rasmussen, said the Russians, as part of a sophisticated disinformation operation, ‘engaged actively with so-called non-governmental organisations — environmental organisations working against shale gas — to maintain Europe’s dependence on imported Russian gas.’

The UK must also take seriously the problems that would be created if Russia decides to stop selling its hydrocarbons to its enemies – aka The West. Russia has supplied about 10% of the UK’s total oil and gas product imports (5yr average by value). Norway, our largest supplier, provides about 37%, and the US supplies just over 10%.

Russia was also the UK’s largest supplier of refined petroleum. In 2021, we imported 5.7 million tonnes of product code HS 2710, Petroleum oils and oils obtained from bituminous minerals (excluding crude), from Russia. Over the 5 years before its invasion of Ukraine, Russia has supplied between 15% and 26% of the UK’s refined petroleum imports.

So what happens if they embargo sales to the UK – petrol rationing? Probably not for the UK, but for poorer nations, as the UK will be able to outbid poorer countries on international markets. But other Western nations, such as Germany, the Netherlands, Poland, and South Korea, are much more reliant on Russia for their oil, coal and gas. Shortages in these countries will push up prices for everyone.

UK Steel Production and Geopolitics

The only valid reason for the UK to continue producing virgin steel may be to ensure the security of supply for the UK’s defence industry, its construction industry and its most valuable exports: machinery and transport goods. With rebels able to prevent cargo ships from passing through the Suez Canal using a handful of cheap drones and Russia unlikely to rest on its laurels if it defeats Ukraine, this is not a hypothetical threat. Closing the Suez Canal disrupts the supply of finished steel from China and India, as well as the supply of iron ore and coking coal from Australia. A permanent closure of the Suez Canal would raise the cost of supplies from North America and Brazil, as all European buyers would divert their purchases to the Americas. To avoid this choke point, the UK must reopen its metallurgical coal mines.

Additionally, recycling steel in the UK is not viable while UK industrial electricity is so expensive. This will be made worse by adding more wind turbines to the grid, as explained in the first chapter. The substantial installation costs of renewable energy are recouped through subsidies (paid for by consumers), high generation fees, higher network fees and greater grid backup power fees.

Switching from cheap BOS production to expensive EAF will not bode well for UK steelmaking. We must address the price of our industrial electricity. Adding more gas-fired power stations will help, while we increase conventional nuclear production and deploy Small Modular Reactors or Thorium Molten Salt Reactors. However, these latter options will take time to develop, so we should begin this process now. If there is a silver lining to the closure of the blast furnaces at Port Talbot, it must be the wake-up call to lower the price of UK industrial electricity.

Chapter 10: Activists add to the cost of production and limit UK GDP

The Rosebank field was discovered in 2004, and it took nearly two decades to receive government approval. Following extensive evaluations and delays, the UK government granted development consent in 2023. Environmental groups, such as Greenpeace and Uplift, have played a pivotal role in challenging the approval.

Rosebank, the largest undeveloped oil field in the UK, is estimated to contain 300-500 million barrels of oil equivalent, with peak production of about 70,000 barrels of oil and 44 million cubic feet of gas per day. Drilling has been delayed because the Supreme Court’s 2024 Finch v Surrey County Council ruling required that all new UK oil developments account for their Scope 3 emissions when assessing their environmental impact. Scope 3 emissions are those produced by users of the oil and gas produced from the field. The Scottish Court of Session upheld this ruling as affecting the Rosebank application retrospectively in January 2025.

Rosebank activists encourage complaints from unrelated parties (Bots?)

The Rosebank site resubmitted its application, including Scope 3 emissions, in October 2025. This triggered a 30-day public consultation. Activist groups such as Stop Rosebank urged the public to inundate the consultation with messages demanding that the project be halted, arguing that approving the field is incompatible with the UK’s legally binding climate goals and a liveable future. This ruling was upheld by the Scottish Court of Sessions in January 2026. The government has yet to make a final decision on whether to grant fresh approval for the projects but has stated it is consulting on updated environmental guidance.

Critics opposed to the development argued that the UK taxpayer would fund over 80% of the project’s development costs, of about £250 million, while the project’s primary owners, Equinor and Ithaca Energy, stand to gain £1.5 billion in profits assuming an oil price of $70/barrel. This projection appears to ignore that the UK would tax those profits at 78% and that the UK still needs oil. The UK either produces oil and exports some of it, thereby gaining valuable foreign currency, or imports the oil it needs and borrows the funds to pay for it. The projection also ignores downstream industries that use oil as an input, along with the jobs and revenues they generate.

The money that activists describe as a ‘cost to taxpayers’ is not a cost at all. This is a tax incentive designed to encourage investment in the UK, providing tax deductions and allowances for investment expenditure. If the development does not happen, no tax will be paid. The ‘cost’ will not reverse into a profit for the taxpayer. Taxpayers are presently receiving nothing from the undeveloped oil field; if it remains undeveloped, they continue to receive nothing. If the field is developed, taxpayers will eventually realise a substantial return from the site.

The tax allowances and deductions are high because oil companies face a 78% tax rate, making them more valuable. However, the Labour government removed what it described as “unjustifiably generous investment allowances” by abolishing the levy’s 29% investment allowance for qualifying expenditure incurred after November 2024. The government also reduced the extent to which capital allowances, including first-year allowances, can be taken into account in calculating Levy profits. UK Oil and Gas taxes are also ringfenced so that losses from other parts of a business cannot be used to reduce North Sea oil and gas profits. Several companies operating in the UKCS have merged to combine their accrued losses and reduce their tax obligations.

In contrast, the developers of Rosebank, Ithaca Energy, expect the development to require £8.5 billion of total direct investment, with £6.6 billion likely to be invested in UK-based businesses. To date, the joint venture has committed over £2.2bn to the development of Rosebank and has awarded key supply chain contracts. The project is expected to support around 2,000 jobs during the construction phase, and will continue to support approximately 525 UK-based jobs throughout the field’s lifetime. They also expected production to begin in 2026/27. This will have been delayed by the requirement to reapply for permission. Incredibly, some activist groups are complaining that the delay will allow Rosebank to produce oil after the UK’s additional Energy Profits Levy of 38% has expired, thereby avoiding an exorbitant tax bill. But this would be the direct result of the activists’ own attempts to block the development, and also ignores the new tax regime, the Oil and Gas Price Mechanism, that will replace the EPL when it expires.

The developers also claim that the Rosebank development has been optimised to reduce carbon emissions, in line with the North Sea Transition Deal, with the FPSO designed to be electrification-ready when arriving at the field. Material work continues on the redevelopment of the Knarr FPSO, a floating production, storage, and offloading vessel built for the Norwegian Knarr oil field, now being redeployed to Rosebank, where it is docked for refurbishment and electrification. The Rosebank development has the potential to produce at approximately 3kg CO2/boe – a seventh of the UK average well emissions. This may be why the activists are more concerned with the ‘cost to taxpayers’ than with opposing the development on environmental grounds.

Coal – activists for hire?

A group of activists, the Coal Action Network, worked to force the closure of the Ffos-y-fran mine. The group wants to ‘end coal use in power generation and steel production, coal extraction, and coal imports in the UK.’ Their website complains about the CO2 emission of ‘global steel production without mentioning that almost all virgin steel production is outside the UK, as the UK has only 2 operational blast furnaces (discussed earlier in this paper). Nor are these activists interested in coal-fired power stations that use carbon capture. But these ‘all-purpose’ activists also target other major employers in the UK, such as the insurance sector, while also supporting Palestinian liberation and migrant justice; how either of these issues will be affected by the closure of a small mine in Wales, let alone global steel making, is not explained on their website.

‘Our work includes a campaign targeting the insurance sector, which exposes how insurers enable deadly industries through their backing of coal, fossil fuels, and other forms of extractivism. This campaign links climate justice with the struggles for Palestinian liberation and migrant justice, recognising the shared roots of violence in systems of imperialism and racism.’

The closure of the Ffos-y-fran mine illustrates how Britain was de-industrialised by ‘all-purpose’ activists pressuring politicians. Neither the politicians nor the activists intend to live without the goods made from coal or steel, but they still want the mine closed for ideological reasons and don’t care if 180 miners lose their jobs. Nor do the activists seem to care that the waterproof clothing they wear in the photographs on their website is made in China using petrochemicals.

Activists commission research but never publish it in full

Longannet coal-fired power station on the north bank of the Firth of Forth was not only an iconic physical landmark, with 2400MW installed capacity, but it was also Scotland’s largest carbon-based power station and the last to use coal. Construction began in 1964, electricity was generated by 1970, and it was fully operational from 1973. It was the largest power plant in Europe. Its expected lifespan was thirty years, but upgrades kept it legally and economically viable. A carbon capture unit that had access to £1bn of UK government funding was commissioned in 2009, but closed in 2011.

Originally, half of the coal used was Scottish, including coal supplied directly by the neighbouring Longannet Colliery using a conveyor belt – until a flood closed Scotland’s last deep mine in 2002. Imported coal came in at Ayrshire’s deep water ore-handling facility at Hunterston Terminal. The volume of imported coal congested passenger rail routes and contributed to the opening of the new Stirling-Alloa-Kincardine rail link in 2008 at public expense. Yet such was the politicians’ willingness to abandon coal that only ten years later, the power station was already being demolished.

Open-cast coal mining continued in Scotland until the closure in 2020 of the House of Water pit in Ayrshire. Although licensing is a reserved matter for the UK Government, the Scottish National Party (SNP) Scottish Government announced in October 2022 that it would use planning powers to block any new coal developments. Following the closure of the Ffos-y-fran mine in Wales in November 2023, there are no remaining opencast coal mines legally operating in the entire UK.

In 2003, Longannet was named as Scotland’s biggest polluter in a report by the Scottish Environment Protection Agency (SEPA). The station produced up to 4,350 tonnes of ash per day, which was used for land reclamation or recycled into products such as grout.

To reduce emissions, Longannet was fitted with ‘Low-NOx’ burners to limit the formation of oxides of nitrogen, and a ‘gas reburn system’ that used natural gas to convert NOx into nitrogen and water vapour. It burned up to 65,000 tonnes p/a of treated and dried sewage sludge, with a calorific value similar to that of low-quality lignite. In 2005, a judge ruled that burning sludge was illegal, but SEPA allowed Scottish Power to continue burning sludge in an agreement to construct and operate a biomass plant in 2010. All burning of Longannet biomass, including sawdust pellets, ceased in 2012.

In 2007, the WWF named Europe’s 30 most climate polluting power stations in absolute terms; of these, Longannet was ranked 21st most polluting in Europe, although the most polluting in the UK (relative to power output). According to a Greenpeace publication called Silent Killers, research it commissioned from Stuttgart University in 2013 on the health impacts of European coal-burning power plants estimated 33,000 years of life were lost annually in Germany. The research report was not fully published and did not stop Germany and 8 other EU countries that rely upon coal to generate electricity from continuing to burn it.

With mounting pressure from environmental groups such as Greenpeace and WWF, Longannet’s owners, Scottish Power, announced it would close by March 2016 after failing to win a tender to supply electricity to the National Grid. Due to its distance from the South of England, Longannet paid connection charges of £40m p/a to supply the grid, and the SNP claimed this had caused its demise – but it was constantly being criticised by climate activists, and closure was politically expedient.

Some 370 direct jobs were lost, including 40 port workers who handled imported coal at Hunterston Terminal in North Ayrshire, and 20 locomotive drivers. A further 1,000 indirect jobs were estimated to be lost at a cost of £50m p/a to the local economy. A Scottish Government-led task force was established to mitigate direct job losses. It closed in 2019, reporting 99% of former workers were in new employment or training. However, the actual number in full time employment was not revealed.

Scotland’s only other coal power station at Cockenzie in East Lothian closed in 2013 after Scottish Power chose to “opt out” of environmental upgrades required by the EU’s Large Combustion Plant Directive. It had been named in a WWF report of 2005 as the UK’s least carbon-efficient power station in terms of CO2 released per unit of energy generated. When the 1200MW power plant opened in 1967, coal accounted for 72% of British electricity generation, but by 2011 that had fallen to 34%. Cockenzie once employed 500 workers but had only 100 when it closed; about half relocated to Longannet only to lose their jobs again three years later.

While both Longannet and Cockenzie power plants operated beyond their intended lifespan, their pollution mitigating systems allowed them to operate ‘cleaner’ than when they first started up. However, they faced an onslaught of anti-coal campaigns from WWF and Greenpeace that eroded support from politicians. The final demolition of Longannet was conducted with great fanfare by First Minister and EU disciple Nicola Sturgeon, who set off the explosives that brought down the Chimney Stack in 2021. “European directives, eh?” said one Cockenzie worker as his power plant was demolished.

Chapter 11: Economic statistics

The oil, gas, and coal projects involve large capital investment; are highly productive, with large refineries employing a few hundred employees; and produce important materials for the UK export industries. The closure of refineries and the decommissioning of wells have led to lower investment, lower productivity, and significantly lower exports, which many economists conveniently attribute to Brexit without examining which exports have experienced the larger reductions.

GVA and Productivity Section

The importance to the economy of the oil and gas sector and downstream activities of refining, chemical production and pharmaceutical production can be illustrated by examining the Government Gross Value Added (GVA) and productivity statistics by industry sector,.

Figure 25 on page 101, analyses the period from the beginning of the Climate Change Act in 2008 to 2024, comparing the relative growth rates of GVA by industry with those of relative output per hour.

The x-axis shows the relative growth rate of different industry sectors over the period. The midpoint of 100% represents the overall economic growth rate over the period. The y-axis shows the relative productivity of each sector in 2024 on a log scale, with the mid-point of 100% representing the whole economy.

In the white segment, we can see that sectors such as wholesale and retail, agriculture, forestry and fishing, and transport and storage are growing more slowly than the overall economy and have below-average productivity, measured by gross value-added per hour worked.

The yellow segment shows that sectors such as accommodation and food service, health and social care, and arts and entertainment are growing faster than the whole economy but have lower-than-average productivity.

The green segment shows sectors such as real estate and information and telecommunications growing faster than the overall economy and achieving above-average productivity.

The red segment shows sectors with above-average productivity growing more slowly or shrinking in absolute terms compared to the whole economy. Included in this segment are mining and quarrying, which includes oil and gas extraction, where GVA has fallen in absolute terms by 7% over the period, yet productivity is 637% of the whole economy average. The red segment also includes oil refining as well as the chemical and pharmaceutical sectors, both of which have much higher productivity, 384% and 292% of the average, respectively. Both these sectors have grown more slowly than the whole economy, too.

Hours worked per week are down 9% in mining and quarrying, 14% in oil refining, and 2% in chemicals and pharmaceuticals, indicating job losses over the period. While the job losses in the past have been relatively modest, the loss of GVA is much more significant because these industries add so much more value per hour worked.

Now, high taxes on domestic oil and gas producers, coupled with the effective ban on new exploration drilling has led to estimates of 1,000 jobs per month being lost in the oil and gas industry in the North Sea. The economic impact of these job losses is far greater than the headline figure, because this sector generates more than six times the value added per hour worked than the whole economy.

There are also additional impacts further downstream in refining and petrochemicals. Grangemouth oil refinery closed about a year ago, with the loss of 400 jobs. The oil refining sector produces about four times the GVA per hour worked as the whole economy, so again, the economic impact of these job losses is amplified. Although the refinery has closed, INEOS Chemicals Grangemouth continues to produce essential ethylene feedstock for the petrochemicals and plastics industry. The chemicals and pharmaceutical manufacturing industry generates about three times as much value added per hour worked as the whole economy.

The loss of North Sea oil and gas production has a large economic impact in its own right and an even greater impact that extends further along the value chain, hollowing out industries that produce vital building blocks society depends upon. This damages the domestic economy, negatively impacts the balance of trade, and undermines economic and energy security.

Figure 25: Sector productivity and growth

Trade balance

The UK government’s environmental policy has had a detrimental effect on UK exports, forcing the UK to import goods it once produced and leaving it with a Goods trade deficit of £250 billion in 2025. The UK’s most heavily affected export sectors are fuel, chemicals, plastics, steel, and other materials. UK chemical exports have been falling steadily for many years due to the UK’s uncompetitive energy costs, stringent environmental regulations, emissions trading schemes, limited investment in new production facilities, and a shortage of raw materials from oil refineries.

Lower UK oil production, due to restrictions on new wells and field development, along with an excessive 78% tax rate, has caused UK production to fall by 42% since 2019, with a knock-on effect on exports. Fuel exports used to be among the UK’s largest exports. Since 2019, crude oil exports, measured in tonnes to remove price fluctuations, have declined by 37% through 2024. UK oil refinery output was down by 13% between 2019 and 2024, while oil product exports fell by 8%, having already fallen by a third since 2007.

Figure 26: Sector productivity and growth

UK environmental policy has also outpaced the UK manufacturing sector and manufactured goods exports. Lower UK oil production and refining have further reduced UK exports of chemicals and plastics: Using ONS data in Current Prices, organic chemical exports fell by 54% between 2019 and 2024, while plastics exports declined by 17%.

However, the most significant decline is in the UK’s exports of internal combustion engine (ICE) petrol and diesel cars. Car manufacturing is a major UK export industry. However, the UK Electric Vehicle (EV) mandates requiring its car manufacturers to transition to all-EV production have lowered production and exports. Total UK vehicle exports (HS87) were 15% lower in 2024 than in 2017, due to reduced exports of ICE cars. Although exports of hybrid, plug-in hybrid, and EVs have increased from virtually nothing in 2017, they can’t make up for the loss of ICE sales; UK car exports in total remain £6 billion lower than in 2017.

The EU’s EV mandate, coupled with the UK’s lack of a large-scale domestic EV battery manufacturer, has made compliance more difficult and reduced vehicle exports. The UK’s high energy costs have made car production twice as expensive as in Germany or France, while the UK’s aggressive EV mandates have left UK producers struggling to meet even UK domestic requirements. Fortunately, the UK’s ICE car exports to the US have remained strong, and the US’s recent abolition of its EV mandate should help UK vehicle exports going forward.

Figure 27: UK Car exports by engine type

Other exports

After vehicles and aircraft parts, the UK’s second largest export is Chemicals. Using Chain Volume Measures (CVM) to account for inflation, UK SITC 5 Chemical exports fell by 15%.

SITC 5: Chemical exports include organic and inorganic chemicals, fertilisers, plastics, medicinal and pharmaceutical products, dyes, paints and pigments, and cleaning products. The UK used to be a major manufacturer and exporter of all of these products; however, since 2016, several UK chemical plants have closed or relocated production. Ten large chemical complexes have closed in the UK in the past 5 years, and consequently, chemical production has fallen by 40% since 2021. Dow Chemical (Wales) closed in 2023, INEOS’ plant at Grangemouth closed this year, and ExxonMobil’s Fife plant will close next year. The reasons cited for these closures are: high energy costs, rising carbon taxes and global competition, which has made UK production uncompetitive.

SITC 6: Material manufactures exports in CVM have dropped by 22% since 2019, but by 28.6% since 2013. This is not about Brexit, but due to the closure of UK steel works at SSI Redcar in 2015, the reduction in production at Tata’s plants in Scunthorpe and Scotland since 2015, the mothballing and then closure of Liberty Steel, and Tata’s closure of its blast furnaces at Port Talbot in 2024 are the causes of the UK’s lower exports to the EU in this sector. High UK energy costs, global competition from cheaper imports, financial instability, and the transition costs of moving from coal-based blast furnaces to electric arc furnaces have led to production closures in the UK.

Chapter 12: Reversing Net Zero – costs and benefits

It is imperative that we change course in energy policy if we are to preserve what remains of our oil, gas, and energy-intensive industries. Unfortunately, a wide array of legislation has embedded misguided climate and energy policies into law. All this legislation must be unwound, although some regulations will be harder to unwind than others.

Remove regulations and taxes that are reducing supply first

• Energy Profits Levy (Windfall Tax). Priority must be given to the low-hanging fruit with the highest returns to the industry. The easiest regulation to unwind and the one that should have the most impact on supply will be the Energy Profits Levy, as the EPL was a temporary tax introduced to tax extraordinary profits made by oil and gas companies due to the Russian invasion of Ukraine, not for climate reasons. Therefore, the tax is not connected to the UK’s Climate Change Act, it’s not a Paris Agreement target, nor any of the UK’s trade agreements. Although this tax was not intended to reduce UK oil and gas production or emissions, it has had this result. The additional 38% tax disincentivises UK oil and gas production and currently raises very little revenue, as producers have reduced their North Sea Production.
• The combined 78% tax rate has discouraged oil and gas production in the North Sea and raised only a fraction of the revenue originally envisioned by the Conservative Government that introduced it. Removing taxes is likely to boost production and increase tax receipts for the sector, benefiting downstream industries and, in turn, employment and further tax revenues.
• Oil and Gas Price Mechanism. The Energy Profits Levy (the Windfall tax) was meant to be a temporary tax that ended in 2025. Since then, it has been increased and extended twice, and now the Labour government intends to replace it with a permanent, euphemistically named Oil and Gas Price Mechanism. The Price Mechanism is a permanent 35% tax on the operations of oil and gas producers in the UK and its Continental Shelf. It is currently planned to start if oil and gas prices go above $90 per barrel or 90p per therm. This tax is in addition to the 40% ringfenced corporate tax they already pay, which is 15% higher than the standard 25% corporate tax. The replacement of the ‘temporary’ EPL with the Permanent OGPM will be the last nail in the coffin of the UK industry unless this is stopped.
• North Sea Future Plan: introduced in November 2025, these regulations effectively ended new offshore exploration licences and new onshore oil and gas licences in England. This policy must be reversed to enable UK operators to find more oil and gas resources, as Norway has done, and to enable companies to explore for additional onshore oil and gas supplies.
• Fracking moratorium and the onshore Petroleum Exploration and Development Licence (PEDL): A new energy policy would lift the fracking moratorium and repeal any legislation that Ed Miliband has introduced to prevent fracking. Fracking is also not tied to the UK’s international Climate Commitments or trade agreements. This was yet another own goal by the UK. The moratorium on fracking was introduced in 2019, briefly lifted under the Truss administration, and reinstated under Sunak’s administration in 2022. Ed Miliband has pledged to implement a total fracking ban, meaning the gas resources in onshore shale formations will be effectively out of reach unless this is reversed. Reversal of the ban on onshore petroleum exploration and development licences could increase the UK’s gas supply and lower prices, as it has in the US.
• Remove the Financial Services requirement to integrate climate risks into credit risk assessments. This will lower funding and insurance costs for the energy sector, and allowing car manufacturers to produce vehicles that their customers prefer are three supply-side reforms that can be implemented quickly and are likely to yield results.
• Simplify royalty charges on oil and gas extraction. Replacing high oil and gas taxation with a simple royalty charge on extracted oil and gas on a BOE or energy basis. The UK should continue to issue exploration and extraction licences, which need to be renewed annually or, at the latest, every 5 years; unused extraction licences should expire, as current planning permissions for construction do, after 5 years if the project has not started. In the 1970’s, oil and gas fields entered production within about 5 years of discovery – the UK needs to return to this type of efficient development. Oil and gas company taxes and allowances should then be the same as those of all other industries, with exploration costs and other plant and equipment expensed immediately.
• Encourage coal production for exports: coal could also be used for back-up power stations for windfarms, as they are in China, or could be built with CCSU. The UK has large reserves of high-carbon anthracite and thermal coal, which should be used or exported. The UK also has large amounts of coal waste, which should be processed to recover critical minerals.
• Simplify Environmental Impact Assessments. Inclusion of Scope three emissions from new UK oil and gas production should be compared to the Scope 1,2 and 3 emissions from imported oil and gas.
• Drilling for new oil and gas in the North Sea has been made more difficult after the Finch ruling in the Supreme Court that required regulators to consider the impact of burning oil and gas, Scope 3 emissions, in Environmental Impact Assessments (EIA) for new projects. In addition, the Court of Session in Edinburgh has ruled that the planning consent granted to the Jackdaw and Rosebank fields was unlawful for failing to consider the environmental impact of burning the extracted hydrocarbons.
• However, the Finch ruling covered the Horse Hill site in Surrey, which is estimated to contain 3.3 million tonnes or ~24 million barrels of oil equivalent (MMboe). Jackdaw is estimated to contain 120-250MMboe and Rosebank is estimated to contain 300-500 MMboe. All three total 444-774MMboe or 4 to 5 days of global oil and gas consumption: a drop in the ocean. The assessment of Scope 3 emissions ought to be as simple as stating that their global impact will be almost undetectable. Moreover, the UK will continue to use imported oil and gas, and the carbon footprint of imported LNG is much larger than that of domestically produced gas.
• The Environmental Impact Assessment (EIA) regulations require a radical overhaul to make it easier to restart onshore and North Sea exploration and development drilling. The EIA require extensive analysis, consultation and mitigation before drilling can begin. EIA’s are required for seismic surveys, exploratory drilling, production drilling, pipelines, and even decommissioning. The EIA is governed by the Town and Country Planning (Environmental Impact Assessment) Regulations 2017 in England, the Town and Country Planning (Environmental Impact Assessment) (Scotland) Regulations 2017, and the Offshore Petroleum Production and Pipelines (Assessment of Environmental Effects) Regulations 1999 (for offshore oil & gas in UK territorial waters), which implement the EU EIA Directive. It is questionable why the EU would be so concerned about oil and gas production when the UK was, at the time, the only EU country with any sizeable production and Norway, which also follows the Directive as an EEA member, has never been an EU member.
• Prevent Activists from blocking approved wells and fields. Other supply-side reforms would include making it more difficult for activists to block oil and gas fields that have been granted permission by the UK government. These activists are often funded by international groups that are not motivated by promoting the UK’s economic interests. Some, such as the anti-fracking groups, are funded by Russian interests, others are naive ‘Activists for Hire’ that need a cause to justify their existence. Regardless of whether their activism destroys other people’s jobs and livelihoods.

Encourage Demand

• Abandon the EV mandate. The UK should also abandon its EV mandate for producers and its fines for the sale of excess ICE vehicles. The UK should also stop subsidising EVs, but it could continue to install charging access in street lighting for city dwellers without driveways. If people want to buy an EV, they can, but without subsidies or market-distorting fines. Removing the EV mandate will stop the decline in demand for petrol and diesel.
• Abandon the heat pump mandate. Again, if people want to install a heat pump and their homes are sufficiently insulated so it works, let them install one and pay for it. The Majority of UK housing stock is too old to retrofit a heat pump without extensive and expensive additional insulation.
• Encourage Data Centres to build their own electricity supply using gas, coal or nuclear. Data centres transfer information at the speed of light and can be sited anywhere with cheap electricity. While many Gulf countries hope to attract large data centres and AI due to their cheap electricity, they face both political risks and heat-related challenges. About 40% to 50% of a data centre’s energy is used for cooling. Scotland or the Orkney Islands could be ideal locations for data centres – if they could use North Sea gas to generate electricity.

Other energy costs that reduce industrial profitability

• Carbon emission calculations for goods: If the new government intends to continue with CO2 emission charges and taxes, then all emissions associated with goods production should be divided by the product’s life expectancy.
• Carbon Price Support Mechanism: Abolish the Carbon Price Support (CPS) Mechanism. This is an additional UK tax that is not applied by other EU countries and makes UK products uncompetitive in the EU. As the UK government plans to join the EU’s ETS, it would be unfair and anti-competitive for UK industries to continue paying both the UK’s CPS tax and the EU’s carbon tax. The CPS was introduced to discourage the use of coal in electricity generation; however, the last coal-fired power station closed in September 2024. There is no need for this tax. The CPS is currently £18 per tonne of CO2 and adds about £6 to £7/MWh to the cost of gas-fired electricity. Beyond being redundant, the CPS increases costs for businesses, thereby reducing their profitability and their international competitiveness.
• Climate Change Levy: The Climate Change Levy (CCL) is paid by non-domestic energy consumers and is charged on electricity, gas and solid fuels. It is not tied to the UK’s Paris Agreement Commitments, and it is not used to subsidise renewable electricity. The CCL is just a tax on UK business energy use designed to make energy more expensive and incentivise energy efficiency. It has certainly achieved this aim, but mainly by encouraging UK businesses to relocate to countries with lower energy costs. Removing these costs will help the UK’s remaining businesses survive. CCL costs to UK businesses have ranged between £1.8 and £2.2 bn in recent years. per year, adds about 5% to 7% to a typical non-domestic electricity bill and increases the electricity price by £7.75 per MWh.
• In total, carbon costs made up 37.5% of the wholesale price of electricity in December 2025. If carbon costs were removed, wholesale electricity prices would fall from December’s £78.45/MWh to just under £49/MWh, giving welcome and popular relief to both businesses and households.
• Simplify Discounts for energy-intensive industries: The benefit of removing the CCL will be that we can also remove the requirement for Energy Intensive Industries (EIIs) to apply for discounts of 92% for electricity, 86% for gas, 77% discount for LPG and an 86% reduction on coal or solid fuels, by entering a Climate Change Agreement. EII also gets an 85% discount on the Renewable Obligations and Contracts for Difference levy. This will reduce industry compliance costs and increase their profitability.
• Curtail Curtailment payments: Curtailment payments are not embedded in renewable contracts, and they are not guaranteed revenue streams. Wind generators are paid for curtailment only through the balancing mechanism, not through their CfD or RO contracts. The new government should redesign the system to make new generators responsible for co-located storage and firm power obligations, as there is no contractual barrier preventing this. A new government should also introduce Locational Marginal Pricing that varies by location and reflects local demand and supply, transmission congestion and network losses. Generators currently pay a Transmission Network Use of System charge, but it is a fixed price that does not vary with real-time grid conditions.

Other regulations to that lower UK productivity and increase costs

• Carbon Reduction Plan. Remove the requirement for government contractors to have a Carbon Reduction Plan before they can apply for government contracts. Contracts should be awarded based on the ability to provide the services at an appropriate price. The Contract may require the company to manage the waste generated by the Contract in accordance with the law, but it should not require the company to have a Net Zero plan before it can even apply for the contract.
• Sustainability requirements in financial service regulations. The Government should remove the sustainability requirements from financial service regulations. Bank lending, insurance, and pension fund investments should be based on a financial risk/reward basis over the life of the investment, not on what will happen if the investment is still in business in 100 years. (The average age of a UK-registered company is just 8.6 years.) The UK is a global financial services centre and cannot restrict its services to companies subject to arbitrary regulations.
• Remove the ‘sustainable economic growth’ duty from regulators. The Enterprise Act 2016 was revised in 2023 to replace the ‘Growth Duty’: having regard to the desirability of promoting economic growth, with the ‘Sustainable Growth Duty’, which explicitly requires all major UK regulators, including Ofwat, Ofcom, Ofgem, ORR, CAA, etc., to have a sustainability-aligned growth obligation. The statutory guidance on sustainable economic growth explicitly emphasises environmental impact, long-term environmental sustainability and supporting Net Zero-aligned investment. The ‘sustainable’ requirement should be removed from the regulator’s obligations. Some regulators already had sector-specific sustainability obligations, such as Ofgem, the energy regulator, which had a duty to reduce greenhouse gas emissions; this should be replaced by a duty to ensure there is always ample, affordable energy to meet the demands of current and future industry and domestic users.
• Introduce anti-trust regulation to prevent collusion between financial service providers. Although the GFANZ group of financial organisations has been predominantly discredited, this was due to the US Congress, Senators, State Governors, and US pension managers threatening it with an antitrust suit. GFANZ started in the UK and was the brainchild of the then Governor of the Bank of England, Mark Carney, even though it undermined the UK’s main extractive industry and all the industries that flowed from it. Unfortunately, the UK government appeared powerless to stop, or even supportive of, the debanking and de-insuring of the UK’s most important industry. The New government needs to introduce financial services regulations to prevent this type of collusion in the future, as well as prevent the de-banking of individuals for political reasons.

International agreements, ETS and renewable subsidies to renegotiate or repeal

Unfortunately, reversing other regulations will be trickier, as much of it is embedded in international agreements that will also need to be reversed, and this could require primary legislation. Additionally, reducing or eliminating renewable subsidies will be met with aggressive legal action from the beneficiaries of these contracts.

Paris Agreement and the UK’s ‘ambitious’ Nationally Determined Target

Boris Johnson increased the UK’s Nationally Determined Commitment (NDC) Paris Agreement target from 55% reduction from 1990 emissions to an extremely ambitious 68% reduction by 2030. Although the Paris Agreement requires procedural duties of submitting a national climate plan, calculating, and reporting emissions, there is, luckily, no punishment for failing to meet the NDC.

Even though the UK has halved its production emissions since 1990, if we ignore its imported emissions, the Climate Change Committee believes the UK is unlikely to meet its 68% reduction target by 2030. A large proportion of the UK’s emissions reduction was due to deindustrialisation and the conversion of coal-fired electricity to gas. But to cut emissions by another 18% will require the population to lower its standard of living by greatly increasing electricity demand without increasing the supply of dispatchable power.

The solution would be to lower the UK’s commitment back to the EU level of 55%, accept that we will fail to meet the lower target, or follow the US out of the Paris Agreement. The Agreement was always nonsensical, as China and India were not required to reduce their emissions, and so they now dominate global production and supply of high-emission goods that were once made in the UK, the EU and the US. If the UK wants to revive its industry, it should consider both options, with the latter being the most comprehensive. The only sticking point will be the UK’s trade agreements with the EU and New Zealand, which both stipulate continued commitment to the Paris Agreement, even though both are reconsidering their positions on oil, gas and coal use. As the UK is one of the EU’s largest export markets, it would be very unlikely to walk away from the TCA if the UK left the Paris Agreement.

The ECHR

Although it was established for entirely different reasons, the European Court of Human Rights has interpreted inaction on climate change as a potential human rights violation. The next UK government may well leave the ECHR to remove the requirement to accept illegal immigrants, but it would also avoid activist groups claiming that leaving the Paris Agreement or encouraging new oil and gas developments is somehow affecting their human rights. The ECHR can pressure states to align with the Paris goals even though the Paris Agreement is not enforceable.

Emissions Trading Scheme:

The UK’s Emissions Trading Scheme is part of the UK’s Paris Agreement commitment delivery program. Although it is a domestic policy instrument designed to help the UK meet its Legally Binding Carbon Budget as defined in the UK’s Paris Agreement Nationally Determined Contribution (NDC).

The UK’s Emissions Trading Scheme (ETS) is levied on energy-intensive industries, the power generation sector and aviation. According to the ONS, the ETS cost £4,069m in 2024. The cost of this is set to rise as the Government has pledged to align the UK and EU trading schemes, and EU carbon prices are even higher than ours.

However, the UK-EU Trade and Cooperation Agreement (TCA) and the UK-New Zealand Free Trade Agreement require the UK to maintain a carbon tax. Removing the ETS entirely could create problems for UK exporters to the EU and New Zealand if the EU or New Zealand can prove that it gives UK exports an unfair advantage. However, trade with the US and China, the UK’s largest individual trading partners, would not be affected, nor would the UK’s service industry exports, which are now more than half of all UK exports. However, the ETS is a drain on the much larger domestic economy, and removing it could increase tax revenue for other jurisdictions, as the UK would be a more competitive environment for establishing new businesses.

The Climate Change Act

The Climate Change Act 2008 (CCA) should be repealed, but this will take time and may require primary legislation. Fortunately, there are safeguards in the legislation that may allow the CCA’s effects to be defanged more quickly, enabling a twin-track approach to reform before eventual abolition.

Section 2 of the Act makes provision for changing the percentage reduction in emissions if there are significant developments in the scientific knowledge about climate change.

Section 10(2) sets out the matters to be considered when setting or amending carbon budgets. These matters include scientific knowledge about climate change; technology relevant to climate change; economic circumstances; social circumstances; and the impact of carbon budgets on energy policy.

Section 21 covers the rules for amending carbon budgets after they have been set. Carbon budgets can only be amended if “there have been significant changes affecting the basis on which the previous decision was made.”

The latest science is less alarming than previously thought and this ought to be grounds for reducing the emissions targets. The direct and indirect costs of renewables are far higher than estimated by the Climate Change Committee which means the technical and economic basis for setting carbon budgets has changed since the decisions were made, and there ought to be grounds for amending carbon budgets too.

Downgrading the onerous emissions targets and revising the carbon budgets should pave the way to reducing energy costs by focusing on measures that will deliver the maximum return for the least legal pain.

Cutting renewable subsidies

This will be controversial, and we should expect the contract counterparties to fight any attempt to change their contracts; however, there are ways to mitigate the costs:

• The most expensive subsidy scheme is Renewables Obligations (ROCs), which cost £7.8bn in 2024/25 according to the OBR. This is a subsidy paid to renewables generators in addition to the market price they receive for the electricity they generate. This scheme has been closed to new entrants since 2017, so all beneficiaries have had plenty of time to recoup their initial capital. A range of measures should be considered to cut costs.
• The softest measure would be to stop indexing certificate values in line with inflation, or to index them in line with CPI rather than RPI. The Government has already announced this latter measure, which will begin in April 2026. This would at least cap costs until the scheme decays naturally as generators reach the 20-year subsidy limit.
• A more dramatic measure would be to effectively end the scheme altogether by repealing or amending the Renewables Obligation Order 2015 , which is used to set the number of certificates licensed electricity suppliers are obliged to purchase. The annual obligation level is set by the government, and each ROC is worth one Megawatt-hour. Electricity suppliers must purchase ROCs to cover all electricity purchases, whether renewable or not, unless the renewable generator sells the electricity with the ROC attached. Renewable generators can also sell their ROCs on the open market, where the government’s buyout price serves as a floor. If this were set to zero, the certificates would have no value, and the cost of the scheme would collapse, removing £7.8bn from electricity bills – potentially another popular measure.
• Contracts for Difference (CfDs) are more difficult to tackle. The total CfD scheme cost £2.6bn in 2025, with most of the subsidy going to offshore wind. This is a relatively modest sum in the grand scheme of things, but there are large additional costs in the pipeline from contracts awarded but not yet activated. The existing CfD contracts include clauses that provide compensation for Qualifying Changes in the Law (QCiL). It will therefore be difficult to change existing CfDs without breaching contract law. The Reform Party has committed to striking down the contracts awarded in Allocation Round 7 (AR7).
• Feed-in-Tariffs (FiTs) cost about £1.9bn per year. The cost of these could be mitigated by stopping further inflation indexing and ceasing payments once the subsidies received exceed the installation’s capital cost. The Government has announced that FiTs will be indexed in line with CPI, not RPI, from April 2026. Again, the scorched earth approach would be to end the scheme altogether.

Cut or eliminate curtailment payments and require renewable generators to install batteries or pumped-hydro storage to store power until it is needed.

Wind farm decommissioning

Cutting carbon taxes would have the greatest impact on ROC-funded generators and on merchant-based renewable generators. There will be no impact on FiT- and CfD-funded generators, as they receive index-linked fixed prices for their output. However, CfD units would receive a larger share of their income from subsidies than from the market.

Eliminating ROC subsidies would have an even larger impact on these generators. It is likely that the revenue cuts would be large enough to push many offshore wind and some onshore wind units into bankruptcy. This will lead to two second-order effects. On the positive side, if there is less operable wind capacity, there will be fewer instances when wind exceeds the grid’s capacity, so curtailment charges should fall, which would be a further benefit.

On the other hand, cutting carbon costs and ending the ROC scheme early risks these windfarms becoming financially unviable overnight. It is likely these companies do not have enough cash on hand to fund decommissioning liabilities so the cost could fall onto the taxpayer.

To mitigate this risk, any new Government could, upon taking office, immediately tighten the rules governing decommissioning. All windfarms would need to hold ring-fenced cash in the operating company to cover the present value of the liability in the expected decommissioning year. They should set a rule that no dividends or other cash can be paid to owners until the decommissioning liability is covered. If the cash generated by the windfarms is not enough to cover the liability in, say, two years, then the owners should be forced to inject cash into the operating companies.

The biggest financial loss for ROC-funded generators will be the loss of their ROC certificates, so perhaps the Government could implement the cut to carbon costs immediately and then end the ROC scheme slightly later to give consumers an immediate benefit and time for decommissioning cash to build up.

Further legal barriers to change

The CCA is far from the only legal barrier to unwinding Net Zero.

The Energy Charter Treaty is a multilateral investment treaty designed to protect foreign investors in the energy sector, particularly in former soviet countries. Several EU countries have withdrawn from the treaty because it was being used by investors to prevent coal phase-outs and bans on offshore oil drilling. The EU sees the treaty as incompatible with the Paris Agreement. The Conservative Government withdrew the UK from the treaty in February 2024, but it has a 20-year sunset clause, so UK investor protection will remain in place until 2045. Setting the Renewables Obligation to zero might lead to a legal challenge under Article 10 of the Treaty’s Fair and Equitable Treatment provisions. Article 13 may provide grounds for challenge under indirect expropriation rules if the change renders investments uneconomic. However, there may be valid defence mechanisms that justify the change on public-interest grounds. Clearly, there is legal risk in such a move, and it will be a political decision, as the benefit of removing ROCs may outweigh the risk of having to award compensation.

The non-regression clauses in the UK-EU Trade and Cooperation Agreement (TCA) do not act as an obstacle to ending Net Zero unless the changes made by the UK specifically benefit UK trade with the EU. The TCA does not freeze specific Net Zero policies or targets set after 2020 (e.g., the UK’s tightening of its Paris Commitments to 68% reduction by 2030 from 1990 levels, or the 2050 Net Zero goal itself). The UK can adjust, relax, or replace domestic policies as long as overall levels of protection do not fall below the 2020 benchmark in a trade-affecting way.

Article 764 of the TCA also contains provisions to respect the Paris Agreement and refrain from acts or omissions that would materially defeat the object and purpose of the Paris Agreement. In addition, Article 392 commits the UK and the EU to having effective carbon-pricing systems, such as the ETS. Taken together, the provisions in the TCA act as a barrier to backsliding on Net Zero commitments if this gives the UK or the EU a trade advantage. However, there are signs that EU member states are beginning to oppose draconian climate targets so it may be possible to agree jointly to resile from Net Zero commitments.

The UK-New Zealand Trade Agreement has environmental provisions similar to those in the UK-EU TCA. The Parties cannot deliberately lower environmental standards to gain a trade advantage. The provisions cover pollution, biodiversity, environmental impact assessments, climate mitigation, carbon pricing and conservation. The agreement requires the UK to maintain carbon pricing, but the UK’s ETS would be sufficient; the CPS could be abandoned without breaking the agreement. The agreement also contains an unusually strong explicit commitment to the Paris Agreement: to implement it, maintain their NDCs, and not withdraw from it. If either country were to withdraw from the Paris Agreement, it would be considered a breach of the FTA. This is one of the strongest climate‑related obligations in any UK trade deal. Unlike most trade agreements, the environmental chapters are fully binding, subject to dispute settlement and could lead to sanctions or penalties.

Conclusion

The evidence presented in this paper demonstrates that a pragmatic reset of the UK’s oil and gas strategy offers substantial economic, industrial, and fiscal benefits. Increasing domestic production — both offshore and onshore — strengthens national energy security, reduces exposure to volatile global markets, and keeps value within the UK economy rather than exporting it through rising import dependency. Allowing new exploration, accelerating licensing, and enabling technologies such as hydraulic fracturing where geologically appropriate would materially increase domestic supply, stabilise prices, and support the resilience of the UK’s energy system during the transition to net zero.

The benefits extend far beyond the extraction sector itself. Oil and gas underpin a vast industrial ecosystem that remains essential to the UK’s economic base. Across upstream operations, refining, petrochemicals, plastics, pharmaceuticals, cement, ceramics, glass, steel, and aluminium, these industries collectively support hundreds of thousands of high-skilled, high-productivity jobs. Many of these sectors cannot operate without secure supplies of hydrocarbons, and they face international competition from jurisdictions with lower energy costs and fewer regulatory burdens. A competitive domestic energy supply is therefore not optional — it is foundational to the survival of the UK’s industrial core.

Reforming or removing carbon-related taxes and levies on energy-intensive industries would further strengthen this foundation. Current carbon cost burdens often exceed those faced by competitors in the EU, the US, the Middle East, and parts of Asia, undermining UK competitiveness and accelerating industrial decline. A more proportionate, investment-friendly framework would help retain strategic industries, safeguard employment, and support long-term decarbonisation through innovation rather than deindustrialisation.

The fiscal benefits are equally significant. Higher domestic production increases tax revenues from corporation tax, supplementary charges, and employment taxes, while reducing the UK’s reliance on imported oil and gas. Every additional barrel produced domestically reduces the trade deficit, improves the balance of payments, and keeps more economic value circulating within the UK. In a period of persistent fiscal pressure, these revenues provide a critical buffer for public services and national investment priorities.

Taken together, these measures form a coherent strategy for strengthening the UK’s economic resilience. By producing more of its own energy, supporting the industries that depend on it, and ensuring a competitive fiscal and regulatory environment, the UK can secure jobs, enhance tax revenues, reduce its trade deficit, and maintain the industrial capabilities essential for economic strength.