Coal production and share in primary energy

Before the war began, coal represented a third of global electricity supply. Coal is the largest energy commodity by mass[i], estimated to represent over $500 billion in market value per year[ii]. Coal generates 37% of global carbon emissions, more than oil or gas or land use change, and is the leading cause of deaths from electricity. Coal is still used for 70% of steel production and is even replacing petrochemicals in places like China and South Africa. Despite coal’s decline in Europe and the US, global demand has broken new records in each of the past four years. Often seen as a relic of the industrial era, coal is an integral part of the global 21^st century economy. And as recently as last year, we were still building more.

Global Electricity Production by Source

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Yet we have a blind spot to coal. Our media report on it less than oil or gas. We search for it less on Google. Book mentions of coal peaked in the 1920s, superseded by oil and gas in the following decades. The question is why.

Relative frequency of energy search terms, 2004-2024

One answer is that coal is local. Just ~17 to 22% of coal trades across borders[iii]. Countries with a coal endowment are incentivised to use it for energy security, to reduce imports, and even generate tax revenue and export receipts. The global coal price is not tracked as closely as that of oil or gas and is not relevant in most markets because coal is so costly to export. Even within a country, coal regions are often separated from main population hubs. While petrol is pumped into cars, gas comes out of the stove, and renewables dot the landscapes, coal remains out of sight for most of the population.

Coal, gas, and oil consumption by traded share

A second reason coal might be overlooked is it is perceived to lack the dynamism of other energy sectors. The shiny new tech of renewables and the geopolitical intrigue of oil and gas conflicts are big news. We don’t go to wars over coal, and it’s one of the oldest technologies we still use on the grid. Its health and environmental impacts accumulate over time through chronic illnesses or gradual land degradation, rather than in major disasters like oil spills or explosions.

A third prospect is that coal has become so invisibly embedded in our energy systems that we take its benefits for granted. Coal delivers energy security and independence, and is increasingly important in a world in the midst of conflict. Coal protects industrial jobs in communities without much else. Coal supports billions of dollars of tax revenue and foreign currency management in states as diverse as India, Indonesia and Australia. Perhaps most salient of all, coal represents a culture that many of us admire, of the hard-working, self-sacrificing miner and the strong community which rallied around them. The political price of taking these upsides away is high, especially if people don’t experience the industry’s costs directly.

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Painting in the Coal Museum in Datong

This helps explain why countries have turned to coal in the current crisis, but also puts this upsurge in perspective. Italy has delayed coal retirements by over a decade to 2038, but coal supplies less than 2% of its electricity. It is an expensive energy source, not least because its carbon tax bill is almost double that of gas, but avoiding blackouts might seem worth it for a marginal climate and cost impact. Meanwhile Japan and Korea are temporarily suspending utilisation caps on their coal power plants, but were already in the world’s top ten coal consumers before the Iran War began. Indonesia will likely reverse production caps to profit from this rise in coal demand, but these caps were instated just a few months ago to prop up coal prices.

Similarly, commentary that this resurgence will be short-lived also misses the bigger picture. China, India, and the US are the world’s top coal consumers, and each of them was already indicating a desire to keep using coal before this war. China’s new five-year plan scraps earlier commitments to peak coal use. India has watered down pollution control requirements and started using batteries to allow coal plants to operate when renewables surge, instead of switching off. The US has seen the most dramatic reversal, subsidising ageing coal plants and struggling mines, repealing environmental and worker protections in an attempt to reduce costs, and promoting coal through meme culture. Even if coal use peaks and begins to gradually decline, a long plateau at current demand levels will contribute more emissions in four years than the UK’s coal since 1750.

Cumulative coal emissions in the UK versus annual coal emissions globally

Although we are using more coal than ever before, it has also never been a more replaceable fuel. Like coal, renewables deliver energy that is controllable within a country’s own borders, even if the equipment is initially imported from elsewhere. Coal is no longer cheap compared to renewables, with solar and wind regularly outcompeting coal power in China, Australia, the US, and India, even when taking into account the cost of batteries. Flexibility tech can erode the need for round-the-clock energy availability from coal and add to system resilience. We have barely scratched the surface of using the millions of distributed EV batteries or controllable heating systems to our energy networks’ advantage.

The strangest part about our global reliance on coal is that we don’t seem to know about it. This means we also don’t always know why we still use it and what it really costs us. Coal clearly has benefits like energy security, but it isn’t exactly cheap - not just because of uncompetitive unit costs but from damage to the environment and human health. Governments owe their citizens a clear explanation for why cleaner, cheaper, reliable technologies are not being prioritised instead.

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[i] 8.8 billion tonnes, IEA.

[ii] Implies a market value of ~$60 per tonne. Met coal trades at $130-200, Chinese coal reference prices (half of global supply) are $100+ while domestic coal is significantly cheaper in places like India or the US.

[iii] A higher share trades by energy content (22%) as low-quality coal is not as cost-effective to export. A lower share of coal trades by mass (17%) according to IEA.

When you shop for a mortgage, you can pick a variable rate or fix the rate for up to five years. Usually the interest rate is higher, the longer you lock it in [i]. You choose what you want based on your risk appetite and how much you value predictability. The options for predictable energy bills are more limited, with few providers offering 2-year contracts and none offering longer [ii]. The government sees reducing exposure to “volatile fossil-fuel markets” as part of energy security. If people value predictable bills, then how did British energy customers become so exposed to short-term price swings?

Some energy use is essential, like commuting to work, heating the home in winter or turning the lights on at night, so household energy consumption tends to be ‘inelastic’ to prices. People will pay whatever it takes to meet basic needs. This can mean that during an energy price shock, extra spending on energy eats into discretionary parts of the household budget. It’s also why energy prices rise so much in a physical supply shock, because it takes a dramatic change in costs to drive behaviour to reduce demand.

Because of its importance to voters, energy markets are prone to state intervention. In some countries, governments own their national energy companies, which can reduce the profit-maximising motive to over-charge consumers for energy. In Britain, the energy sector is practically all privatised [iii], which puts us in the global minority for utilities [iv].

The theory in the 1990s was that free markets would bring down energy bills compared to a state-owned enterprise [v]. The government heavily regulated network businesses because as natural monopolies, they wanted to limit investor returns and reduce incentives to overspend on infrastructure. For generators and suppliers, competitive pressure would be enough to keep companies in check.

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How price caps impact long-term planning for energy suppliers

But even with competition, private companies were still perceived to be milking their customers, particularly those on default contracts. Savvy customers were offered good deals if they switched suppliers, while the most loyal and passive customers saw prices go up. This dynamic is not unique to energy – it applies to lots of essential products from savings accounts to phone plans [vi].

Nonetheless, the government intervened to protect energy consumers after a Competition and Markets Authority review in 2016. They set periodic caps for the price of the default energy bills from 2019 onwards [vii], stopping energy suppliers from over-charging customers who stayed on uncontracted tariffs.

This price cap could be contributing to instability in energy prices. It uses prices that are up to 4.5 months out of date by the time they come into effect [viii]. Under this methodology, the price cap from July to September 2026 will be based on prices observed from February to May. The cap also assumes prices will be smoothed over the following 12 months. Meanwhile, the ~60% of customers who have the default tariff can switch at any time without a penalty [ix]. One in ten households switched suppliers in 2025.

Capping prices solved a problem for disengaged customers but seems to disincentivise long-term planning and stability. Suppliers [x] face asymmetric downside risk when locking in their electricity supply agreements for longer than the three-month price cap period. If prices go up on average, suppliers can always raise prices along with competitors. If prices go down, they risk being locked into costly supply contracts for the customers which stay, and their are on the hook for supply contracts for households they no longer serve if they switch to another provider. The lag between price observation and price changes adds to the difficulty in hedging customer demand. When the Ukraine War broke out, many suppliers were not sufficiently hedged, leading to bankruptcies because their costs became too high for their expected revenues [xi].

Contracts are not attractive at the top of the market but nobody knows exactly when the peak will be. The proportion of customers on fixed tariffs peaked at the dawn of the 2022 energy crisis, at around 40% of UK households. This fell to a low of just 9% in the summer of 2023, suggesting people were unwilling to hedge while prices were high. Switching collapsed around this time as well, as suppliers were bound to charge no more than the cap and could not find ways to make energy any cheaper.

Almost 40% of British households are now on fixed tariffs again. That means 60% of customers [xii] will be exposed to price cap changes if it goes up in response to the Iran War supply shocks, now forecast to increase electricity bills by 11% in July according to Cornwall Insight [xiii]. This is an expensive time to lock in new contracts, but it could get a lot worse.

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What about customers who aren’t on default tariffs?

Households are just over a third of final electricity consumption in the UK [xiv]. ~80% of demand across households and businesses is not covered by the price cap [xv], but they are exposed to volatility too.

For households, the costs of switching aren’t particularly high [xvi] even on contracts. Coming back to the mortgage analogy, if interest rates go up, you’re happy you have your fixed contract. If they go down, you can’t switch to a better deal until your contract expires, but at least you agreed to the mortgage based on what you could afford. For energy bills, the same incentives are at play for staying on a good deal as prices rise, but the penalties for ending the contract may not fully reflect the cost for the supplier to get out of their agreements [xvii].

Collateral is another reason why fixed prices aren’t more widely available for longer. When you take out a mortgage, whether fixed or variable, the bank can repossess your house if you aren’t able to pay your bills. For energy, there is no such guarantee for a household, and providing those guarantees as a business is not usually the best use of capital. If the retailer doesn’t match customer contracts with their hedges, they will incur costs to carry that hedge.

While household demand can be predictable year-to-year, businesses may also not have clear line of sight on how their energy demand will shape up. Businesses can procure energy using a power purchase agreement (PPA), but entering into a fixed price contract for a certain amount of volume is a liability if the business closes or energy use declines. Energy generators also typically require credit-worthy counterparties to enter into offtake agreements and smaller businesses are not able to provide this assurance as easily. Hedges also require counterparties willing to bet on the energy price, and beyond a certain timeframe, these prices are difficult to forecast without adding extra costs due to uncertainty.

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Does the UK need to ensure long-term, stable prices?

Locking in more of the UK’s energy costs via contracts is an appealing solution for managing price volatility. The government is uniquely placed to do this because of its strength as a counterparty and its ability to agree to pay contracts beyond a few years. The government’s Contract for Difference (CfD) scheme effectively plays this function. Initially conceived as renewable energy support to subsidise and drive down the capital cost of new generation projects, the scheme also serves as a long-term hedge for price stability. 16% of the UK’s electricity generation is covered under the scheme, which could rise to as much as 44% by 2031 [xviii].

The government looks smart if traded power prices go up compared to the CfD contract price, as is happening now with its recently signed offshore wind CfDs [xix], but risks looking like it got a bad deal if prices fall. Either way, the government has bought predictable prices for a share of the energy supply and would expect to pay more than the going wholesale rate for the privilege. This is akin to longer fixed mortgage terms costing more because they price in future uncertainty.

If people value stability, the government could extend contracts to other types of generation, like older renewable facilities or gas [xx]. The government would act as a financial intermediary, absorbing uncertainty that private markets are unwilling to price. It could also sell its hedges back to the market on shorter term horizons to get them off government balance sheets down the line.

The trade-off of government-backed stability is it creates moral hazard and dampens price signals in the short term, which can hinder innovation. If the government is underwriting the cost risk for the long term, there is a lower incentive to be cost-efficient or to pay for one’s own “energy cost insurance”. When more supply is contracted, the cheapest technology for meeting demand in that moment will be unable to compete as effectively to bring down costs, whether it is gas, new renewables, or flexible tech. Contracting in an emergency is also the worst time to sign new deals, but the pressure to do so is lower when the market has recovered from a shock. With the status quo, customers on the price cap struggle when prices go up in a quarter but can benefit immediately when prices come down.

But the price cap was initially designed to protect consumers and is now driving behaviour that exposes them to more volatility. The rest of the market also faces barriers to long-term contracting because financial collateral requirements for fixed prices over long time periods are unaffordable for most customers. The government is the only party which can take on long-dated price risk to provide a form of energy price insurance, and we already socialise other forms of insurance like healthcare. The cost is an energy system that is less responsive to short-term price signals, but this may be worth it to avoid the next cost-of-living crisis outside of anyone’s control.

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[i] This reflects uncertainty and an insurance-like premium or opportunity cost for the bank. When a downturn is coming or some other trigger of an interest rate drop, the forward curve can invert and signing up to a fixed-rate mortgage for longer can be cheaper.

[ii] Money Super Market comparison website, April 2026.

[iii] The National Electricity System Operator (NESO) is the only state-owned entity in the utility value chain, making decisions on market operations and dispatch. The government owns companies like Great British Energy, and has launched similar state-owned enterprises in the past.

[iv] World Bank Global Power Market Structures database, 2024.

[v] In practice, the UK has ended up with some of the highest electricity costs in the world.

[vi] The UK government is consulting on how to avoid the traps of recurring revenue that tech companies have set, very interested in how this plays out in the UK.

[vii] The initial design was every 6 months, this was changed when the Ukraine War meant that prices were changing too fast to be manageable for suppliers under the price cap.

[viii] The price cap is based on observing 12-month ‘forward’ prices for 3 months, then waiting 1.5 months to apply them. Ben James has a helpful explainer on this here.

[ix] The penalties for customers on contracts aren’t particularly high, either.

[x] Retailers are called ‘suppliers’ in the UK, but they are the last point of supply – suppliers have their own suppliers of energy.

[xi] This was not just due to the price cap design, but it was a factor – the price cap was previously for 6 months, with an ‘observation’ window of 6 months plus a wait period of 2 months before the caps came into effect, leading to a serious lag in price caps versus the real-time market. Firms also were capitalised too thinly to hold hedges, or chose not to for their business model.

[xii] Incidentally, Londoners are less likely to fix their contracts than the rest of the UK (9 percentage points lower than the average proportion of customers on fixed contracts in 2025), which makes this a regional story too.

[xiii] Figures as at 1^st April 2026.

[xiv] DESNZ Table 5.2.

[xv] DESNZ Quarterly Prices Table 2.4.2, assuming the share of household customers on fixed prices is applied to demand.

[xvi] Around £50 to £100 based on my scan of Money Super Market.

[xvii] “Breaking” a hedge incurs costs if your hedge is “out of the money”. This happens if prices go down but you have agreed a higher price. If your hedge is “in the money”, i.e. prices have gone up but you agreed a lower price, then your hedge becomes an asset instead.

[xviii] Using the LCCC estimate of contracted supply from AR 1 to 6 and bespoke contracts, and author’s estimate of supply from the AR7 round based on assumed capacity factors.

[xix] Wholesale market prices are above £110 per MWh as of April 2026, which is higher than the 2025 average price and the agreed offshore wind CfD strike prices in early 2026. LCCC.

[xx] The government does contract with batteries, gas, and other facilities via capacity market mechanisms, but this is more about reliability of supply than guaranteeing a price for consumers.

Several Slow Burn subscribers came in person, but for those who couldn’t make it and for the the majority of my audience who do not live in London, you can watch our launch night here and on Spotify - the perfect Sunday activity while tucking into your tea or flat white.

In a section called “over-hyped / under-hyped / hyped-just-right”, we talked about:

• Enhanced geothermal

• Balcony solar

• Vehicle-to-grid

• Coal phase-out (my favourite topic)

• Copper supply

• Critical minerals geopolitics

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• The grid of the future: who builds it, who pays, and how distributed resources could let us do more with what we already have

• Why hydropower isn’t sexy, and why it should be, from Snowy 2.0 to the Grand Renaissance and Itaipu Dams

• Moonshots: space-based solar generation, beaming energy across time zones, and fusion

• Compromises on the future of the North Sea

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Can you believe the Iran War started just three weeks ago?

Energy costs in Britain have just about doubled in that time. British gas prices jumped within days of the US-Israeli bombing campaign, while oil prices rose more slowly. Prices could rise non-linearly from here as the buffer of oil and gas stocks runs out and governments around the world turn to more extreme measures to manage demand. Much higher prices are likely if the conflict continues, as is a price collapse if the war ends.

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The British government faces a crisis painfully similar to the energy shocks brought on by the Ukraine War in 2022. Physical supply disruption is less acute this time because the UK’s consumption is much less exposed to the Middle East[i]. Electricity prices in March are less than half of the 2022 average and less than a quarter of their 2022 peak at the height of the Ukraine War shock[ii]. But prices have already risen enough to potentially increase energy bills up by 12 to 20% in Q3. Government 10-year borrowing costs are now at pre-2008 levels, eating into government budgets and increasing the cost of any support packages.

This time round, the government has even less fiscal room to manoeuvre. They can learn from their predecessors’ mistakes. Like the last major shock, this is an opportunity to push for secure, cheap energy and to reform electricity markets. Britain shouldn’t let it go to waste.

What has the government done so far?

The government’s initial measures announced between March 6^th to 15^th are not so different from what they were already doing. The assurance on energy bills being protected until the end of June is not an emergency response but just how the quarterly price cap works. Bringing forward the next Contract for Difference (CfD) round, the government’s long-term contracting scheme for renewables, can lock in prices, but can’t help with additional supply as grid capacity is already allocated to 2030 under the recent connections reform. The Fingleton Review reforms for nuclear projects were already ideas on the agenda for renewables, for example cutting environmental assessment duplication, limiting judicial review and consenting projects faster. The Warm Homes Plan announced earlier this year is being fast-tracked in some cities. The government has put companies on alert for price gouging via the Competition and Markets Authority but they cannot do much if companies reflect the market. The UK released a sixth of its emergency oil stockpile, which amounted to just nine days’ worth of domestic demand, and has deferred an increase in fuel tax for drivers by five months.

Its new policies are helpful but unlikely to be sufficient. The government has finally permitted the use of plug-in solar, which saves money on energy bills but only over a multi-year pay-back period and potentially causes unintended price rises for the electricity network[iii]. A newly announced subsidy, £52 million to support 1.5 million households using heating oil, equates to a £35 top-up per home. Oil heating costs that are likely to rise by over 10 to 20 times that amount[iv], though will hopefully be limited by warmer spring weather.

These measures fall far short of the £51 billion support package (2% of GDP) that obliterated government budgets in 2022/23[v] plus a further £11 billion in 2023/24. Only 9% of the 2022/23 cost was offset via energy producer windfall taxes. The announced measures are unlikely to be enough to manage the fall-out that has already happened. Cornwall Insight forecasts that the energy price cap will rise by 12% and 20% from the Q1 and Q2 price caps respectively[vi], and the shock is already affecting food, other consumer products and potentially mortgage payments.

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What can the government do next?

This shock could be an opportunity for the government to make the energy system work better by rebalancing electricity and gas prices, reforming markets, supporting long-term contracting, and unlocking more distributed energy assets.

Price rebalancing

Emergency subsidies could work in the short-term but the budget is limited. They also risk disincentivising demand reduction or the switch to cheaper alternatives by dampening price signals.

A more sustainable approach is rebalancing electricity and gas prices. Making electricity cheaper relative to gas and oil products would help to accelerate electrification of transport and heating. Adding carbon taxes to gas or eliminating them from electricity would help but risk causing more political headaches. Shifting an additional ~5 pence per kilowatt-hour of policy costs off bills and onto general taxation is an easier place to start.

Market reform

Gas dependency is the primary driver cited for persistently high British energy costs. This is partly because gas is imported and uses an international reference price, and partly because it sets the wholesale market price for all other generation. Although the UK has reduced both its electricity import exposure to 29% (down from 49% in 2013) and fossil fuel use over the past decade, the Energy and Climate Intelligence Unit estimated that gas was setting the wholesale market price 85% of the time in 2024.

The UK’s electricity supply has reduced its exposure to imports since 2013, and fossil fuels over the past two decades

The government could start to address this problem by making the market function properly. The UK’s electricity market takes into account delivery time, but not delivery location. All generators are paid a national price based on the most expensive unit that customers were willing to buy. Once it comes time to deliver the power, some generators are unable to dispatch the electricity they have sold because the grid is too constrained. This is exacerbated when contracted assets bid in the market as close to zero as possible to ensure they are chosen to dispatch, even if their location is constrained.

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These distortions lead to wasting curtailed energy, higher network costs to make up supply from other sources, and exporting power at subsidised prices. To give certainty to investors, the government has so far resisted reforming the market to incorporate geographic constraints. But the current system rewards incumbent generators more than it incentivises new renewables investors, who typically rely on contracts to build projects. Regional pricing would send investment signals to build renewables and demand centres in parts of the country that can absorb it.

It should not go so far as separating renewables and gas markets. This doesn’t help all that much as marginal pricing is a market-making mechanism, not unique to energy. Separating out the markets would still lead to participants guessing at the whole-of-market clearing price, leading to less efficient bidding than a combined market. Nationalising gas assets is an interesting twist on the market separation idea, but it only works if governments are willing to operate them with a long-term security perspective.

Long-term contracts

The government could instead fill the long-term contracting gap without major nationalisations. Another reason the UK energy markets are so prone to shocks is the reliance on spot prices instead of contracts. The UK’s consumer protection policies cap prices each quarter while requiring that customers can switch easily between suppliers. People can sign up to fixed-price agreements when they are nervous about prices going up, but switch to another supplier when they see prices coming down again. This disincentivises suppliers to enter into long-term contracts with energy providers and customers alike, as it significantly increases the cost of hedging. The market liquidity for contracts beyond a year or two is thin and most gas generation ends up trading on short term markets.

CfDs are notable not just for subsidising renewable electricity, but for offering long-term contracts to generators that the market does not provide. Even if the CfD strike prices are higher or similar to historic wholesale prices, they offer predictability for 15 to 20 years. Based on all the CfDs that have been agreed including the latest round in 2026, the UK electricity market will have 44% of supply on fixed price contracts by 2030/31[vii]. The case for bringing forward the next CfD contracting round is more about price stability for projects in the queue rather than getting new projects built. Even if CfD costs go up by inflation every year, the higher share of generation covered by the subsidy will reduce price volatility dramatically.

The government could offer more price security by backstopping long-term contracts beyond CfDs. This is most expensive to do in the midst of a crisis, but once prices subside the government could consider, for example, offering contracts to operating renewables projects at below-market rates, or negotiating affordable long-term domestic contracts for gas as part of a support package for the North Sea. Supporting additional drilling would not necessarily reduce energy prices significantly according to the Oxford Smith School, but this would support domestic industry if the UK continues to use gas.

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Distributed energy tech

The plug-in solar systems that the government has now legalised are the latest evolution in distributed energy, which now includes rooftop solar, home batteries, electric vehicles, heat pumps and demand control for other devices. Controllable loads help to make most use out of renewables by pairing demand and supply at the cheapest times, while distributed generation is currently cheaper than the grid. The problem is that tapping into these benefits is still too difficult for customers and grid operators alike.

70% of households now have a smart meter installed, and aggregators like Axle Energy are enabling some customers to capitalise on flexibility payments. But half-hourly billing directly at the household level is not yet widely available and not all high-demand devices like EVs and heat pumps are required to be dynamically controllable. The government could mandate that more devices have the option for dynamic controls based on electricity price signals from smart meters, enabling more people to benefit. Requiring data sharing from smart meters to the electricity system operator, NESO, would also provide more visibility on behind-the-meter devices when forecasting grid balancing requirements and costs.

Never let a crisis go to waste

The government is so fiscally constrained that the Ukraine War level of support is unlikely to be feasible this time without significantly driving up borrowing costs. Subsidies can also delay much-needed reforms that could prepare Britain to unlock cheaper electricity. The last government didn’t act nearly enough after the last crisis to secure energy supply and deliver infrastructure investment. Heat pumps still have incredibly low installation rates, electric vehicles are not yet the dominant vehicle choice, gas storage is perilously low, and electricity prices remain high particularly compared to gas.

The current government has so far prioritised net zero investment, drumming up interest in large-scale infrastructure nuclear and renewable projects. It has not yet tackled major regulatory reforms. If we are going to experience a painful period of price inflation and high interest rates, then let’s at least use this opportunity for bolder change, like removing policy costs from electricity, reforming markets to include geographical constraints, contracting supply for longer, and supporting the uptake of flexible technologies. You never want a crisis to go to waste[viii].

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[i] 49% of British gas was imported in 2024, of which most comes from Denmark – around 2% of total gas consumption came from Qatar (Parliamentary briefing). Oil is more exposed to the Middle East – less than 2% of primary oil product imports come from the Middle East but 27% of petroleum products for a total of ~12% of all oil imports in 2024 (DUKES 3.7)

[ii] The time-average wholesale price for March is £96 per MWh compared to £205 per MWh for 2022 (LCCC Intermittent Market Reference Price as proxy for wholesale prices).

[iii] Behind-the-meter solar is not visible or controllable for NESO, the electricity system operator, and reduces their ability to plan for energy supply including balancing. Using rooftop solar, whether plug-in or fixed systems, reduces the amount of network electricity purchases, which could spread network charges over fewer units and raise prices.

[iv] Heating oil prices doubled from 65 per litre to over 120p per litre since the start of the Iran War, and households with oil-based heating systems use over 1,500 litres per year. As the pre-war cost is estimated at ~£1,000 per year and looks set to double. The increase is at least 20 times the £35 top-up but potentially much higher. In Northern Ireland, the bill impact is estimated at an additional ~£500, or 14 times the top-up payment.

[v] £200 bill discount to all households, £150 council tax rebates, 5p fuel duty cut, cost-of-living payment to some households, energy price guarantees of £23 billion, bill relief for businesses of £7 billion and more.

[vi] Cornwall Insight as of ‘close of play’, 19^th March 2026. Price cap forecast was £1,972.53 for Q3, against the Q2 2026 price cap of £1,641.

[vii] Author’s calculations using AR7 results project announcement tables and assumed capacity factors, and the LCCC’s estimate of future contracted generation as of March 2025.

[viii] Rahm Emanuel, 2008. Also attributed to Winston Churchill but this is unverified.

Two things were in short supply when I lived in Ethiopia ten years ago: dollars and cars.

Soviet-era Ladas were a common sight at the airport taxi rank, and I daresay that Addis Ababa had the highest concentration of vintage Volkswagen Beetles in the world. A 200% tariff on vehicle imports meant cars were used for far longer than average, and second-hand prices were exorbitant. A 10-year-old Toyota hatchback cost ~$15,000 or more and was unlikely to depreciate much each year. The country was not anti-car in general. This was a policy choice about energy security and macroeconomic stability.

As a country without oil, vehicle restrictions were a way of managing fuel imports and their impact on foreign exchange. Ethiopia decided to overvalue its currency, making imports cheaper but requiring government-mandated exchange rates and capital controls. Black market providers converted massive wads of Ethiopian birr into dollars at more competitive rates, because the government so heavily restricted access to hard currency. Even after high tariffs depressed Ethiopian car ownership to one of the lowest rates in the world – 13 per 1,000 people [1] – Ethiopia still spent over $3 billion of foreign currency on petroleum imports each year from 2022 to 2024. This was around 8% of GDP and over 20% of its imports.

Ethiopian annual fuel imports in $b (LHS) and as % of GDP and % of imports (RHS)

The foreign exchange shortage eventually became untenable. From 2016 to now, the Ethiopian birr has lost ~86% of its value. The government managed a gradual devaluation of its currency until it finally defaulted on foreign debt in 2023 and began an IMF restructuring programme including a currency float in 2024.

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Against this backdrop, Ethiopia’s revised car import policies are best understood as supporting currency stability and energy security. Ethiopia led the world in banning internal combustion engine (ICE) vehicle imports and practically eliminating import tariffs on Electric Vehicles (EVs) [2]. Ethiopia’s state minister for transport and logistics confirmed to Bloomberg that this wasn’t necessarily about the climate: “our transition to EVs is aimed at ensuring our energy sovereignty.”

While Ethiopia lacks domestic fossil fuels, it has abundant local, clean generation capacity. The 5.15 gigawatt [3] Grand Ethiopian Renaissance Dam, which I partially funded in an office raffle, was recently completed at great financial and geopolitical expense. By promoting EVs and banning ICE vehicles, Ethiopia can switch its energy demand from imported fossil fuels to domestic electricity generation and provide offtake for the dam [4]. Electricity demand growth is helpful when East Africa seems to have excess generation capacity [5]. While dams have their own risks (e.g. physical concentration, drought, conflict), this move will limit Ethiopia’s reliance on foreign trade routes, reduce price volatility, and improve the country’s balance of payments.

China has been doing this for years

Energy security is also a major driver for why China has invested so heavily in its renewable and electrification supply chains. Climate feels secondary, not least because coal is such a large part of China’s energy system. China produces and consumes more than half of the world’s coal, and just 13% of its coal consumption is imported. In contrast, 68% of oil and 48% of gas demand is met by imports [6]. Coal still supplies ~58% of the electricity demand [7], though its share is declining due to increasing renewable and nuclear installations.

Chinese energy consumption import exposure by commodity, 2024

Electrification helps drive more energy demand to domestic fuel sources. EVs and transport electrification displace imported oil, while electric heating or heat waste from coal plants can displace gas demand. Import substitution with coal is growing beyond the electricity system, by converting it into chemicals that typically use oil and gas as a feedstock. This supports domestic industry and geopolitical independence but is a more carbon intensive process.

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Ethiopia and China’s approach to energy security offers two insights for the UK and Europe.

Electrification helps most when electricity generation is secure too

Calling for electrification alone will not help as much with our energy security unless generation is also ‘secure’. Electrified demand can improve grid reliability, making the system more dynamic and manageable if paired with demand response and smart devices. Distributed batteries in EVs and households will one day help to weather storms and deal with days-long outages if necessary. However, if all vehicles were electric and all households used heat pumps, the UK electricity grid would still be heavily exposed to commodity shocks.

UK electricity supply by import and fossil fuel exposure, 1998-2024

As of 2024, 29% of British electricity relied on imports [8], and a further 23% was linked to fossil fuel commodity prices. In 1998, 72% of the grid relied on fossil fuels, but just 14% electricity supply was imported. Household electricity prices in Britain have risen more than four-fold since 1998, while average consumer prices doubled. Imports and fossil fuels have both fallen as a share of the electricity mix over the past decade, but the globally traded gas price is still a major driver of our energy cost increases. Relying on imports and fossil fuels poses physical availability risk, along with price volatility. More domestic energy supply from renewable and fossil fuel sources has helped other countries reap more benefit from electrifying demand.

The risk of relying on another country’s manufactured products has helped to slow renewable installations in Europe and the US, but this risk is different from relying on commodity imports. Even if countries import solar panels or wind turbines, once these assets are in the ground they can be used for decades. Fossil fuel supply disruptions make waves within days or weeks, even when countries have months’ worth of supply in emergency stockpiles. A disruption to manufacturing supply chains would certainly impact energy investment and growth of renewables but it would not cut off existing resources from generating. Deindustrialisation is a real problem for long-term security and jobs, but this fear in the short term has slowed the deployment of cheap renewables that could have helped bring down energy costs and preserve industrial competitiveness.

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Electrification is not always green

Pairing local production with electrification will not always be a positive climate outcome if domestic resources are carbon intensive. Electrification in China and India has enabled domestic coal to contribute more to the energy mix, while Ethiopia’s transport electrification enables using abundant hydroelectric resources. Switching from petrol to coal-based electricity can still be an emissions savings for cars, but only if they are used for long enough. In war, coal is a substitute for gas and is easier to store and stockpile. Its international price has risen alongside oil and gas over the past 12 days as electricity generators substitute for a cheaper or more readily available feedstock. Coal is almost twice as carbon intensive per unit of electricity generated [9], and worse still for health impacts. It isn’t always cheap, especially after including these externalities, but it is perceived as more dependable than solar and batteries.

Pairing electrification with renewables and domestic fossil fuel generation as an energy security strategy is not novel. China has been laying the ground for this for a decade or more, and many parts of the world have followed. The Ukraine War should have been a wake-up call to drive more electrification and alternative energy development in nations with high import dependency, especially in the UK and Europe.

Instead, we are in a “déjà vu moment” of scrambling to deal with a cost-of-living crisis, after a net zero backlash that has seen some nations pull back on renewable energy growth. We have resisted, partly because of perceived negative impacts like cost, job losses or supply chain dependence on nations they don’t trust. Yet every time there is a fossil fuel supply crisis, these arguments feel insufficient in the face of inflationary shocks. We’ve been taught this many times before, but we aren’t learning the lesson fast enough.

Energy markets aren’t necessarily designed for energy security, perhaps because consumers don’t realise how much they value price stability until a crisis. This is the most expensive time to pay for it. If voters want energy security, the government needs to help bridge the market and perception gap for how much this will cost in the good times. They also need to communicate that clean energy is capable of providing it cost-effectively, and that its exposure to supply chain disruptions is in the order of months or years, not days and weeks.

Renewables and electrification together should be the answer for Europe’s energy security, and possibly even developing local fossil fuel resources and storage if this is cost-effective. Electrification without also investing in local generation will otherwise not be enough for us to be resilient.

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[1] In the US and Britain, this figure is 874 (population of ~340 million) and 602 (population of ~69 million) respectively.

[2] They are between 0 to 15%, which is not nothing, but is much lower than 200%.

[3] Average load of 1.8 gigawatts.

[4] [Check Dan Mark’s point about how this dam isn’t supposed to be run at 100%].

[5] This is my judgment based on current energy consumption per capita, connection rates, affordability, and energy demand growth. East Africa would lack enough supply if everyone had electricity access and used as much energy as higher income countries.

[6] Using Energy Institute Statistical Review of World Energy 2025. Data is for 2024, based on exajoules rather than mass or volumetric measures. Import dependency is even lower for coal on a tonnage basis because imported coal has higher calorie content.

[7] Ember Electricity Data.

[8] See chart. This is calculated using interconnector net imports and the upstream import exposure of coal, gas, oil, and biomass electricity supply. Nuclear is broken out separately in the charts because it is also imported but not a fossil fuel and with different supply chain risks.

[9] Coal power emits around double the per-kWh carbon dioxide as gas.

On the roof of Pleasants Power Station in West Virginia, I could almost hear the sun. The Ohio River glimmered below as coal barges glided past in silence. None of them stopped at the dock, because Pleasants only comes online when demand is high. This 1.3-gigawatt coal plant is idle most days because its electricity is too expensive to compete on wholesale markets, partly due to ramp-up costs.

Coal power is not fundamentally a flexible technology. To generate electricity, a fireball of coal boils an enormous column of water like a giant kettle, until it produces steam to turn turbines[1]. Older conventional plants like Pleasants[2] take at least eight hours to reach their target generation capacity from a cold start[3]. For it to respond to the market, it needs some warning, and a wholesale price that is high enough to justify the fuel costs for the ramp up and the maintenance cost of additional equipment fatigue from continuous cycling.

In practice, most coal plants do not go from 0% to 100% load to participate in the market. They deliver electricity most efficiently when operating continuously, somewhere between a minimum operational load and peak power delivery. In Pleasants’ case, its minimum load of ~600 megawatts is 46% of its peak winter load of 1,300 megawatts[4]. It is used so infrequently that its average utilisation was just 3.5% in 2025[5]. Because of its low operational viability, Pleasants received subsidies to stay operational before the Trump administration made these popular nationwide.

‘Flexible coal’ is a stretch even for modern coal plants. Newer facilities run cheaper and ramp up more efficiently in places like China and India, with average ages of 13 and 15 years respectively compared to 44 years in the US[6]. They still typically operate with a minimum load for plant stability and to reduce emissions, set at a 55% benchmark in India and a 35% target for ~200 gigawatts of Chinese retrofitted capacity between 2021 and 2025[7].

Power plant utilisation is 65-70% in India and 50-55% in China[8] even as coal electricity production fell in both countries in 2025. Unless plants are turned off seasonally like Pleasants, maintaining coal at lower utilisation means continuing to burn billions of tonnes of coal each year for electricity. This not only adds cost relative to cheaper solar and battery generation. This implies carbon emissions and air pollutants from coal will not reduce to near-zero by 2050, a requirement to meet the Paris climate agreement targets.

Flexible coal is part of an energy security and import substitution narrative that justifies continuing to build and use coal power plants when cheaper technologies can do the job. Other measures like capacity payments protect coal power plant revenues if generation declines. Reducing utilisation rather than replacing plants also keeps mine output steady or only gradually declining. India is even piloting flexible technologies like batteries to keep coal plants operational during solar peaks, instead of ramping down production. Flexible coal may reduce overall cost and emissions, but it still locks them in at a high level.

What does using modern flexible tech look like instead?

Flexible technologies are primarily about shifting demand and improving resilience. Demand shifting helps erode baseload power requirements by using electricity when it is cheapest, like during sunny or windy periods. Controllable demand and storage also substitute coal’s reliability benefits with back-up storage and the ability to reduce consumption during short-term system crunch periods.

This really comes to life with specific examples, like hot water heating in Australia. Hot showers and baths can be between 15 to 30% of a household’s electricity consumption, and half of Australian households already use electric water heating[9]. These heaters were once designed with baseload coal power in mind, programmed by default to turn on in the middle of the night when coal was always on and demand was low. Switching electric hot water heaters to activate in the middle of the day during peak solar generation would make heating hot water dramatically cheaper, which is possible for around 50% of heating requirements according to a UNSW study with energy retailer AGL. This requires manually resetting heaters, which can then be hooked up to smart meters. If this heating load could be dynamically controlled, it would be the equivalent of shifting gigawatts of load and 2.3 terawatt-hours of generation, less than the curtailed solar each year. That’s before electrifying more of Australia’s heating.

Another example is electric vehicles (EVs). The operating costs from electrifying transport are already lower than petrol alternatives, and using electricity flexibly brings costs down further and supports grid resilience. BasiGo, a Kenyan electric bus company[10], charges its buses at night-time when round-the-clock geothermal power is under-utilised. Firms like Nuuve support vehicle-to-grid trading to maximise revenues when US school bus fleets are idle outside of morning and afternoon rushes. Companies like Octopus in the UK offer much cheaper tariffs for EVs if they can control when the vehicle charges. Trading electricity from a vehicle’s battery is increasingly common. Customers of firms like Axle and Amber Electric earn revenue from their EV when they aren’t using it, and grid operators can reduce the cost of balancing supply and demand. EVs can now supply electricity to households for up to a week thanks to more models offering bidirectional charging, which reduced the number of people affected by blackouts in recent storms like Storm Fern in the US and Storm Goretti the UK.

Industrial demand is becoming flexible at scale across the grid. Heating and cooling facilities, for example large refrigeration units, can sometimes be turned off or ramped down temporarily without impacting the customer experience of safety. Companies like Voltus aggregate demand from these facilities to deliver a virtual power plant of demand reduction that can temporarily alleviate stress on the grid. Data centres are large loads that could reduce grid strain during demand surges by curbing consumption or switching to back-up power, like recent deals announced by Google.

Battery technology is both a demand shifting and resilience service. In addition to storing electricity when it’s cheapest for use when it’s needed, batteries also deliver the grid stability that coal power provides, like frequency and balancing services, synthetic ‘inertia’ to reduce the impact of shocks, and black starts when the grid goes down.

Flexibility has its limits, like customer fatigue, balancing loads for longer than a single day or being able to create electricity rather than just shift it. Flexibility needs to be automated and almost imperceptible to get its full benefits, rather than continuing current manual models that lead to flexibility fatigue because rewards are not worth the effort. Pleasants’ coal yard stores 30 days of supply before it needs replenishment, and the site requires minimal security and weather protection. This may relegate coal power to be seasonally helpful instead of flexible throughout the day, reducing overall production to ultra-low levels (e.g. 35% utilisation for 3 months of the year is just ~11% utilisation overall). Given the dramatic build-out of coal power alongside expanded cheap renewables production, this could be the reality over time in places like China and India.

Reducing coal’s minimum loads could bring utilisation down and make it more flexible than it is today. That is not the same as making coal a flexible technology. Promoting flexible coal risks keeping more plants online at a permanent lower load, instead of phasing out facilities that are no longer needed. Pleasants Power Plant has received hundreds of millions of dollars in support over the years, and continues to receive capacity payments for a plant that is barely used. This lock-in reduces the incentive to use alternatives. We should instead be prioritising the flexibility of dynamic demand and both distributed and centralised storage. This is what will actually bring down cost and improve the resilience of our modern electricity system.

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[1] A very simplified explanation.

[2] Pleasants is 46-47 years old, its first unit was commissioned in 1979 and second in 1980. EIA-860 form.

[3] My guide told me this on a tour of the facility. For more information on ramp-ups, this EPA document is a useful reference.

[4] EIA 860 data.

[5] Jan to November year to date average against its winter nameplate capacity. EIA 860 and EIA 923 data.

[6] Using capacity-weighted average age, GEM coal power database as of Jan 2026.

[7] 200 gigawatts is around 1/6^th of China’s coal capacity. GEM dashboard.

[8] Using Ember statistics for generation from coal, and GEM installed capacity. Indian government reports utilisation at 65% provisionally for 2025/26. CREA and GEM report 10-year average for China as 51%.

[9] From my lived experience, the type of heating solution depends on where you live – Victoria has higher gas penetration than e.g. Queensland which has lower space heating requirements. UNSW, 2024.

[10] Disclosure, I am an investor in BasiGo.

In a rare moment of parental bonding over energy economics, my mum and I both got quotes for rooftop solar this week. Installing ~9 kilowatts of solar on her bungalow in Queensland, Australia, costs £6,324, or £710 per kilowatt[1]. To get ~13 kilowatts onto my apartment building in London costs 33% more per kilowatt[2]. The UK’s national average prices were even worse in FY2025, at 2.6 times Australia’s installation costs. Both countries import solar panels from abroad and Australia’s wages are higher. So what’s driving prices in the UK and what can we do about it?

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Rooftop solar installation cost per kW by year, UK vs Australia and US (with comparability caveats)

The UK’s physical differences

Expensive rooftop solar is not unique to Britain. US rooftop solar costs are even higher. David Roberts’ Volts podcast explored the US’s “paperwork” problem, among other differences between Australia’s solar market. As bureaucratic as the UK’s energy system is, this is only part of the story driving the UK’s high rooftop solar costs.

The weather is the most obvious difference between the UK and other solar markets. Our skies are particularly cloudy, and daylight hours change dramatically between winter and summer. The average capacity factor for solar, a measure of utilisation, is just 10% to 12% in Britain[3] compared to 21% worldwide and higher in sunnier locations like Australia and California. The volume of rooftop installations is much larger in Australia at 28 gigawatts of installed capacity as of 2025, versus the UK’s 8 gigawatts, which reduces procurement cost from scale. Installers also have more volume in their local area, meaning they can cluster visits to homes closer together. Despite its low efficiency, solar is still cheaper than British retail and wholesale electricity[4], but the payback period is longer and uptake is lower.

The UK’s housing stock, too, impacts system sizes. 9% of homes in England and Wales are bungalows, and a further 66% are multi-storey houses, of which less than a quarter are fully detached[5]. 38% of American housing stock is single-storey of which 95% is detached. 70% of Australia’s housing stock is detached and anecdotal evidence suggests that more of Australia’s homes are single-storey, but there is no consistent statistical evidence to support this claim[6].

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Regardless, Britain fits more people into less space[7], which combined with multi-storey housing decreases the rooftop area for systems. The average UK rooftop solar system was just 4.5 kilowatts in 2025 according to MCS, compared with 9.9 kilowatts in Australia[8] and ~7 kilowatts in the US[9]. This reduces economies of scale from each installation, as fixed costs are spread over fewer kilowatts.

Average rooftop solar installation size by year, UK vs Australia and US (with comparability caveats)

The UK’s housing stock also affects installation techniques. UK roofs can be more difficult to access because the housing stock is older, buildings are higher and homes are often connected to other properties. The UK uses scaffolds as a standard safety measure for installations while Australia relies more on harnesses and roof edge protections. Scaffolds can cause delays in getting an installation date, and increase costs per kilowatt for smaller system sizes because scaffolding incurs fixed costs.

“Soft cost” differences

Australia’s real strength is managing “soft costs”. Australia’s process from inquiry to installation is ultra-fast with significant automation. This reduces the customer acquisition cost by bringing down attrition. My mum had a technician onsite to run the assessment within a week, and could get the installation done just as quickly if she could make up her mind about whether she wants proceed. Planning approval is automatic, as is the grid upgrade request. Inspections that slow down installations are kept to a minimum in Australia, instead relying on technician training and spot-checks for quality and safety compliance.

The UK’s procurement, planning, and interconnection processes are navigable, but not as seamless. Price comparison websites don’t actually offer much of a choice between installers. I was only shown two in Kensington on the UK’s largest website, and one has yet to follow up. Planning approval is automatic, unless you live in a conservation area, and although my borough has waived most listed building consents for solar, Kensington still has one of the lowest rooftop solar installation rates in the country[10]. Scaffolding is a constraint to building, and a site inspection is required before works can continue. The distribution connection to export power to the grid is not automatic for systems above a certain size (usually 3.68 kilowatts[11]). This all adds uncertainty and time to the installation.

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How Britain can bring down rooftop solar costs

Rather than accept that Britain’s build costs are structurally higher, the government and industry associations can play a role in bringing them down by unlocking the benefit of scale.

1) Incentivise coordination with neighbours

Despite the UK’s small rooftops, its population density is an asset. Based on my conversations with a solar installer network[12], bundling initial site assessment visits on a street can bring down the assessment cost by ~£250 by reducing the number of call-outs and transport time. Coordinating with neighbours to install systems can decrease costs by a further £300 to £400 per customer by reducing scaffolding set-up time, installation and travel time. When the average system cost is currently over £7,000[13], this could represent material savings per job. It also improves community buy-in for solar projects and reduces street disruption from installations.

Programs like Switch Together[14] facilitate coordination and procurement savings but have supported ~3% of UK households with solar to date[15]. New grant programs should incentivise neighbourhood cooperation and planning to allow government spending to cover more installations.

2) Help small businesses procure in bulk

The government or industry bodies could also support bulk procurement by launching a dedicated buying aggregation platform for smaller installers and potentially covering the group under a guarantee. In Africa, small off-grid solar suppliers coordinated via their industry association to procure equipment in bulk, securing a 24% discount on solar PV. The UK’s fragmented installer network could benefit from economies of scale, while allowing them to remain local and independent operators.

3) Roll out rooftop PV to more government buildings including councils

In addition, the government could drive volume through mandatory installations on state-owned properties. This could expand on Great British Energy’s work supporting solar PV on schools, NHS buildings and military sites to include other departments like Transport and the Home Office, and council-owned properties. Third-party financing could support these installations for capital-constrained councils, or investments from pension funds.

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4) Review installation practices and DNO connection rules

Beyond scale, the UK could also review its solar installation practices. Scaffolding for safety purposes is a major driver of cost and scheduling friction. Australian installations typically use roof edge protection and harnesses to work from height without erecting a full scaffold. This may not be appropriate for the UK but is worth a review if the safety outcomes are similar. Offering guaranteed and automatic connections for larger system sizes to export to the distribution network would also remove a friction at the end of commissioning.

5) Develop revenue-share products so landlords can benefit alongside renters

Novel financing mechanisms with landlords could drive further adoption among private renters, particularly in London. Owner-occupied dwellings are unsurprisingly over-represented as they have the power to make upgrades to their home and benefit from energy bill reductions. If I wanted to pitch rooftop solar to my landlord to save money on my energy bill, I could offer them a small share of my bill savings, and they would retain this asset for future tenants. Energy suppliers could offer this explicit split-revenue product to allow both renters and landlords to benefit from cheaper electricity.

Installations and Housing Stock by Tenure, latest available

6) Pair solar with batteries

Batteries are increasingly cost effective, and could help the distribution network to manage the cost of upgrades to homes, reducing the need for grid export capabilities. Enabling real-time prices would allow customers to benefit from electricity trading on wholesale markets to generate income. Batteries would also increase system resilience during extreme weather events and outages, potentially bringing down system costs. This trend has already started, with tens of thousands of battery installations alongside solar as of 2025.

Britain’s high energy bills have made rooftop solar a surprising success. Even at current installation costs, my quoted system would break even after nine years. But there is certainly room for cost improvement through increasing scale and reducing other frictions, without necessarily impacting the quality of the system or its installation. As the government fleshes out its Warm Homes and Local Power Plans, it could make grant money go further. By paying attention to reducing installation costs for rooftop solar, more people around the UK could benefit from cheaper energy.

This is part of a series on UK energy policy. Other ideas include repurposing coal assets and small ways to make cumulatively big cuts to energy bills.

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[1] A$9,718 for a Solahart 8.9 kW system and 9.9 kW inverter. Quoted after a 45-minute site survey. Quote includes government rebate of A$2,480 for 9kW solar systems.

[2] £12,276 for a 12.96 kW system, quoted using an online estimation tool of my roof size. I am a tenant in an apartment building, so need to approach the landlord with this pitch if I wanted to get rooftop solar installed.

[3] Depending on sources (DESNZ actuals vs Arup estimates).

[4] Recent AR7a results show solar beating offshore wind, onshore wind and wholesale prices based on unit electricity costs – wholesale prices were ~£85/MWh (volume-weighted) in 2025. Retail prices are ~£350/MWh as of the Q1 2026 price cap.

[5] Council Tax records, 2024. The remainder are apartments/flats.

[6] 2021 census, no storeys are provided.

[7] 287.5 people per square kilometre in the UK, versus 38 in the US and 3.5 in Australia. However, vaste swathes of the US and Australia are uninhabited, including lots of desert. UK homes tend to be smaller than American and Australian homes by floorspace, and may be situated across more storeys, reducing rooftop space.

[8] Admittedly, the comparison is not like-for-like – Australian averages include systems up to 100kW, while Britain’s includes only up to 50kW systems and the highest and lowest 5% of installation costs are excluded from MCS analysis. However, systems 40kW+ make up just 2% of Australia’s installations so are unlikely to skew the results significantly.

[9] 2024 figure, median, residential only.

[10] Partially due to a higher share of people living in flats than the national average.

[11] If a home has a 16A connection and the solar installation won’t exceed that, it can ‘connect then notify’. If the solar installation exceeds this, or the property already has other load e.g. an EV charger, it must apply for a connection. For single-phase connection homes, this equates to a limit of 3.68kW of generation capacity to export to the grid before approvals are required. More here.

[12] Kevin Holland, CEO of Solar Nation, plus several installers who offered smaller anecdotes.

[13] Data as of 2026 - £7,384 average installation cost. Cost per kW is £1,582, implying average system size of 4.7kW in 2026. This data excludes extreme cost profiles (top and bottom 5%) so is not a true average.

[14] Formerly Solar Together.

[15] ~40,000 households supported as of 15^th Feb 2026, and at least 1.5 million homes with solar.

With 500 acres of land, a former grid connection of over 1.5 gigawatts, and proximity to local ports, this site is an infrastructure developer’s dream. Making it a reality faster will require a recognition of former industrial sites as strategic national assets. Governments need more accountability to create value from these sites, and more national-level support for local officials to develop their vision and execute it.

Solar and wind get so much attention for disrupting our landscapes while most people never see the scale behind the coal power industry[i]. Around the world, there are 2,200 gigawatts of operating coal power plants, 8.9 billion tonnes per year of coal mine capacity, 369 coal terminals with a capacity of 6 billion tonnes, and thousands of kilometres of rail networks[ii].

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While coal is gone in the UK, it still produces over a third of the world’s electricity. In absolute terms, consumption reached a new peak in 2025. If renewable energy, storage, and flexible power accelerate the decline of coal[iii], there is a staggering amount of infrastructure to decommission. That’s before considering 20 terminals, 296 mines, and over 240 gigawatts of generation capacity currently under construction, and more potentially in the pipeline. Instead of letting this industrial infrastructure go to waste, giving more thought to coal assets’ second life before it closes would help to defray the cost of early retirements and remediation liabilities.

Retiring coal assets is not a new problem. The industry has been decommissioning sites for hundreds of years. Mines run out of resources that are profitable to extract[iv], and coal power plants are built to last for decades, not forever. Over 500 gigawatts of coal capacity has been retired since the year 2000, of which 60% was in the US and China, two of the world’s largest coal consuming countries in 2025[v]. Almost 1,500 mines were closed between 2015 to 2024 alone, 80% of which were in the US.

Installed capacity of coal power globally by year, net of annual additions and retirements

The scale of the retirement challenge has grown, but what’s new is the scarcity value of what these sites can be used for instead. Data centres, decarbonisation, electrification, and re-building a manufacturing base closer to home are all driving up demand for land and grid connections. Former coal sites could meet the moment, if they were seen as an asset to be monetised rather than a remediation liability.

Data centres are a particularly hot opportunity for former coal power plants, as the AI boom has developers in a frenzy to search for grid access, industrially zoned land, and access to water for cooling. Again, this conversion trend is not necessarily new. Google announced a coal power plant redevelopment into a data centre over ten years ago in the US, but the idea has taken time to spread. In the UK, Blackstone is developing a gigawatt-scale data centre campus on Blyth power station’s former coal stocking yard[vi], while Start Campus, backed by Davison Kempner and Pioneer Point is building at a former coal plant by the sea in Portugal. Keppel announced just last month that it would invest A$10 billion in a data centre in the Latrobe Valley, home to Victoria’s brown coal industry in Australia.

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British coal power plants have also been converted into gas or biomass facilities like Drax, or demolished and used for batteries, solar generation, homes, and even Amazon warehousing[vii]. The US and China have developed gigawatts of renewables on former mining land in addition to remediated forests and tourist resorts[viii]. In the UK, mining land is occasionally redeveloped into real estate, which benefits from adjacent transport links and labour. Water within abandoned mines is now being used for heating homes in Gateshead, England. Some power stations are even aesthetically pleasing enough to be used as museums, like the Tate Modern in London, or shopping and housing precincts like Battersea Power Station.

These successes are striking because they are often the exception rather than the rule. They are fragmented projects driven by local authorities, existing owners and new investors. There are few if any national strategic plans for repurposing coal assets[ix] and projects can languish for years with no progress or support, and there is a long tail of projects with no redevelopment plan at all. Private owners may stall development plans or a sale if the investment options aren’t clear. Local governments may only deal with one or two remediation sites in their area and sometimes lack support on how to structure, select, and progress the best deal for their constituents.

For example, Blyth’s redevelopment into a data centre was far from inevitable. The coal plant was closed in 2001 and demolished in 2003. Its private owner kept the property and explored the option of opening a new coal power plant on the same site before abandoning the idea. A wind turbine factory was floated as n option, before the site was finally selected by Britishvolt as the home of a new battery factory – 17 years after it was demolished. This project was eventually cancelled when Britishvolt went into administration, and Blackstone signed up to take over the site in 2024 to build a data centre, which is still under construction.

If there had been national support to develop a plan for the site when it first closed, the local government could have offered partnered with the owner to convert it to housing, industrial facilities, a factory, or renewable generation and offered mutually beneficial incentives. While the multi-decade delay to develop the site has led to using it for a high-value data centre development, the land could have been put to better use of the past 25 years.

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Around 25 major coal plants were retired in the UK since 2000, and less than half have completed their redevelopments with some still lacking any concrete plans at all. For example, the Rugeley Power Station conversion into over 2,000 homes was announced in 2018 but only received planning permission in 2025. Renewable projects on former mining land like Fife’s 80 megawatt solar development in Scotland are a rarity, and even this one remains to be built. Remediation and sourcing the best investment opportunities do take time, but other places have been able to deliver faster. Myriad solutions have been tried and tested in patchwork programs around the world. Our governments could be learning these global lessons to support their regional authorities to think strategically about how to monetise valuable industrial assets for the modern era.

What would that support look like?

In the UK’s case, where all the assets have already shut down, the national government could work with regional counterparts and international experts to collect the best practices for redeveloping these sites and an inventory of opportunities for investors. The Department for Energy Security and Net Zero, the National Wealth Fund, and Great British Energy could develop a guide for how to prepare a site for its second life and support local governments to structure negotiations with the private sector to create the most value from their industrial assets. Developers could in turn be encouraged to review coal re-developments more closely, for example drawing more on the Mining Remediation Authority’s structural surveys to identify sites where it is safe to build generation assets and logistics depots.

Deal support for local governments could include benchmarks for the typical rents that renewable firms, data centres, and real estate tenants pay so that councils can weigh the trade-offs of different use cases against other benefits like job creation. Education on the breadth of commercialisation opportunities available, from an outright asset sale, to lease agreements and profit shares, could also help regional authorities negotiate the best financial outcome for their risk tolerance. The national government could pre-qualify developers so that individual councils are not duplicating efforts to assess their quality. The government could also support on financing and de-risking projects, offering bridge funding, guarantees and even equity and debt investments to get redevelopments off the ground and build traction with private developers.

In countries where coal assets are yet to be decommissioned, businesses and governments alike should start thinking about how best to monetise their assets once they are no longer needed. This includes designing mine and power plant closures to be able to capture critical minerals from waste, maintaining grid infrastructure so that it can be repurposed for a new site, and planning remediation so that the land can be used for solar and battery technologies. China already does this at scale with its abandoned mine lands. A systems approach, advocated by Duke University, could also unlock opportunities that bilateral deals for single sites might miss. These investments can help to maintain economic activity in communities that have seen coal jobs decline and reduce the net liability of remediation by creating value from an otherwise abandoned site. Even if they don’t create long-term jobs, they can offer infrastructure that underpins the modern economy.

A group of intrigued infrastructure investors visited Aberthaw in the summer of 2025 to discuss what could be done with the site, and they were brimming with ideas. There is a growing appetite from the private sector to understand the opportunities that industrial revitalisation offers. The national government could unlock investment and jobs growth if it offered strategic support and a deal playbook to the regional governments tasked with their redevelopment, and keep them on track to deliver results. This could help places like Aberthaw to revitalise in years, not decades, and build valuable infrastructure that the UK sorely needs for growth.

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[i] More on land use for different electricity sources at Our World in Data.

[ii] Global Energy Monitor is an excellent resource for energy assets.

[iii] CREA reported that China and India coal consumption for electricity went down in 2025 in a landmark moment, though they also point out that China keeps expanding its coal sector. Ember reports frequently on the rise of renewables and fall in coal in Europe.

[iv] Profitable to extract is an important distinction from running out of resources generally. The UK sits on hundreds of billions of tonnes of coal deposits, which are primarily deemed uneconomic to extract.

[v] China was the second largest coal consumer, the US was the third largest, in 2025. Although it is the third largest consumer, China consumes more than half of the world’s coal and the US’s coal consumption is less than 10% of China’s per year. Coal 2025, IEA.

[vi] Full disclosure, I used to work at Blackstone.

[vii] The article talks about how much Amazon warehouse jobs are much less inspiring than former coal jobs. I see this as part of the decline in pride and culture in coal communities, even if there is still technically employment - more on this, check out my piece in LabourList.

[viii] For example, Chief Logan State Park in West Virginia.

[ix] See Duke University’s new paper for an exploration on the approach of the US, India, and South Africa

A small off-grid system powered a projector and a refrigerator in this village in Ethiopia’s Danakil desert. The grid had arrived elsewhere in the region, including to connect wind power back to the cities, but not at our rest stop for the night. As expensive as these off-grid installations were, people preferred to pay than wait for a connection that may never come.

Entrepreneurs in Africa have been working on the problem of slow grid build-out for years. US data centres are fast realising that the grid can’t be taken for granted. The median grid connection time for power projects in US interconnection queues was four years between 2018 and 2024, more than double the wait compared with 2000 to 2007[ii]. Just last month, Google reported data centre grid connection delays of over a decade.

To deliver compute as quickly as possible for their customers, data centre companies are increasingly taking energy supply into their own hands. Bloom Energy reported that over 70% of sites were actively contemplating co-located, or ‘behind-the-meter’ generation. Cleanview estimates that a third of data centres in the ~150-gigawatt pipeline are currently planning to develop electricity generation behind-the-meter. Building so much co-located generation doesn’t necessarily mean the data centres plan to operate off-grid or as an ‘islanded’ system. Nonetheless, Africa’s experience can offer lessons for the American data centre industry as it considers whether ditching the grid entirely would be better for its customers.

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1. Speed has value worth paying for

Off-grid solar developed in Africa because so many people lacked power, and the grid was unlikely to extend to their communities any time soon. Over 600 million people lacked electricity access when I started working in Africa a decade ago – almost two entire USAs. Households who got connections didn’t spend much money on electricity, mainly because of low incomes and a lack of appliances. Although electricity connections were a vote-winner[iii], extending the grid to rural areas was often loss-making as consumption didn’t cover connection costs. Unit economics combined with limited state capacity contributed to a slow build-out of the grid, even with foreign aid.

Private companies launched to fill the gap. Diesel generators were common in rural villages and urban areas alike, to power homes and businesses during power cuts or if there was no alternative. Solar lantern companies proliferated across the continent, offering products packaged as lighting, cell-phone-charging, and TV-watching. Mini-grids offered a solution that mirrored the electricity experience of a grid at a lower cost per connection than extending the grid to sparsely populated areas, building a standalone generation source, and poles and wires. Customers in all these cases were willing to pay significantly higher rates than grid electricity, sometimes over ten times higher per kilowatt-hour[iv], because the alternative was no electricity access at all.

AI model developers also cannot wait. All else equal, cheaper electricity is better for developing AI because it lowers the cost of powering compute. But for the large AI models, losing time can be worse than paying too much for energy. Data centres used for training AI models no longer need to be sited next to where customers live to reduce latency. This in theory means that some training can be done in rural areas with cheap land and renewable energy potential, bypassing grids altogether. But for AI model developers, losing hours or days of training to electricity intermittency or a power outage is an unacceptable cost if it means their competitors can bring out their next model iteration faster.

Data centre developers and their customers will increasingly need to assess the time, cost and reliability trade-offs from their energy supply. Data centres typically have very high reliability requirements which pushes them to grid connected electricity and significant back-up power for redundancy. The trend towards behind-the-meter power is part of de-risking a late grid arrival, but ultimately still assumes the grid will get there in time as the base case. Depending on the time value trade-offs, it might be worth building completely off-grid systems that can cut years off the project’s delivery time, even if it is more expensive or less reliable.

2. Build modular and use anchor tenants

Forecasting demand for rural mini-grids was a major challenge for the African off-grid sector because many of its customers were gaining electricity access for the first time. Pre-build surveys were costly, and the results didn’t always help with successfully forecasting demand.

In response, mini-grids built modular systems, sizing system capacity based on early estimates of demand and initial sign-ups. Their technology choice of batteries and solar enabled gradual expansion. As demand grew, they augmented off-grid systems with more solar and batteries. Developers also signed up large off-takers (anchor tenants) to reduce the reliance on residential customers and even subsidise their bills.

Data centres which start off-grid can deliver training compute from some of their electricity generation before the full site is commissioned. Computing technology is also improving so fast that some planned data centres are obsolete before they even break ground. Building energy and compute infrastructure in phases allows later stages of the development to include the newest technology, and in the meantime generates cash to offset construction costs. Systems using moveable solar and batteries can also be transported to other sites once the grid arrives if they are no longer needed as back-up power.

Building off-grid with a specific tenant in mind also reduces the risk of stranded assets. Utilities and energy developers may otherwise build infrastructure to meet an anticipated increase in demand that may not materialise if data centre developers cancel projects. Off-grid data centres would also help utilities avoid confidential bi-lateral agreements that lead to socialising the cost of the additional infrastructure across their customers.

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3. Plan for when the grid eventually arrives

Grid arrival was a catastrophic outcome for several African mini-grid operators. To generate a profit, off-grid electricity providers often charge higher rates than the national utility even with capex subsidies provided by donors. The utility benefited from economies of scale, and often below-cost electricity prices for residential, low-consumption customers. It is politically desirable to offer customers cheap electricity connections via the grid as soon as possible, even if they are less reliable. If there was no enforced legal framework for what happened when the grid arrived, mini-grid operators risked losing their customers to a cheaper provider once they had already built all the infrastructure and created a market for electricity.

To counter this, mini-grid companies started building their systems with grid interconnection in mind. They pushed for clear agreements with utilities for the rates and compensation from grid arrival, and ensured their systems were interoperable to avoid duplicating infrastructure. They also often offer more reliable service than the grid, so can retain some customers with a higher quality product.

US data centres that choose to start off-grid should plan for the same eventuality. The grid might offer cheaper electricity once it arrives, or charge extra fees for the privilege of a reliable connection if it is not supplying much generation. Energy developers need to consider how that will look to their customers, and what happens once their electricity contracts expire. They could potentially sell resiliency services to the grid or even re-deploy systems elsewhere if their revenues are adversely affected by grid arrival. This requires building in a way that anticipates these two-way flows and ensures grid compatibility.

Where the analogy diverges: purpose, scale, and climate impact

Africa’s off-grid sector was solving for a humanitarian end, and it was often difficult to make enough money from rural customers to cover costs. Data centres in the US have no such problem, with customers willing to pay handsomely to access compute as soon as possible. Their impact by staying on grid may even be negative to the rest of the ratepayers. Going off-grid offers a way to limit the impact of data centres on energy bills.

The US’s off-grid push is also different from Africa’s in its potential for climate damage. Solar and batteries dominated Africa’s installations, usually with a diesel back-up. This was not only the cheapest and most reliable option but the cleanest. They could source from a wide variety of suppliers, at a time when batteries and solar faced few supply chain shortages.

Gas seems to be the preferred generation option for American data centres because it balances cost and reliability at a large scale. The US regularly builds hundred-megawatt- to gigawatt-sized data centres, up to five orders of magnitude larger than a rural African village’s off-grid supply[v]. This is dramatically expanding the potential for carbon emissions growth in the US, with 97 gigawatts of gas powering data centres in the pipeline. This is about the same size as the entire UK electricity grid.

The time-saving advantage of going off-grid may be limited, though, by the shortage of turbines the data centre boom has itself created. Most gas developments in the US pipeline have not identified a turbine manufacturer, suggesting they have not actually secured their equipment order. Waiting for turbines may replace grid connections as the binding constraint in delivering data centres as quickly as possible.

The US could deliver speed with solar and batteries. They can be less cost-effective if they need to over-build to meet the reliability demands of a typical data centre. More importantly, they are politically sensitive and any imported inputs are at risk of tariffs.

Diesel could provide back-up to reduce oversizing solar and batteries the way it does on hybrid African mini-grids, but Jigar Shah recently illustrated the comical scale of the re-fuelling operation these require in a crisis. Unless a huge and dangerous amount of diesel is stored on-site, a 100 megawatt data centre would require a full tanker of fuel every 1 to 1.6 hours. In a genuine emergency, it seems unlikely they could access these endless trucks of diesel before hospitals and other essential sites.

The US lack’s a national carbon pricing framework to incentivise clean energy sources, and is diminishing the power of the Environmental Protection Agency to mandate health or environmental protections. Developments in geothermal and modular nuclear are promising but unlikely to be delivered in time to avoid the current gas construction wave. For now it seems gas is king.

In the off-grid communities I visited in Africa, getting electricity for the first time was life-changing. It enabled not only ‘productive’ uses like reading at night or powering work equipment but also supported entertainment and community. AI will of course be even more transformational for humanity but has real-world costs in the near-term. The desire for speed means infrastructure may not be funded fairly or could crowd out other uses. Going off-grid addresses some of these challenges, though with very different climate and health impacts if the US pursues gas in favour of Africa’s reliance on solar and batteries.

Either way, time is the scarce commodity. If tech companies want speed, off-grid data centres could help ensure that the cost of going fast stays off everyone else’s electricity bills.

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[i] As described in a 2005 Nat Geo spread, gorgeous photos here.

[ii] This has eased off somewhat in 2024. Berkeley Lab.

[iii] Moussa Blimpo’s published an incredible World Bank paper in 2019 laying out a summary of all sorts of evidence and complexities of electrification in Africa, including reference to connections changing electoral outcomes and increasing the willingness to pay tax.

[iv] For example, this study examines the unit tariffs in Tanzania.

[v] In 2018 a 30 kilowatt system could power a 100-household village in East Africa, while data centres are being developed at gigawatt scale.

These are drawn from this week’s LinkedIn posts - follow for updates, and read on for the highlights. Drop a comment on what catches your eye!

This Week’s Energy

1. Getting more bang for buck on rooftop solar in the Warm Homes Plan

2. How EVs can help when power goes down, like the storm in Cornwall

3. Should data centres go flexible and off-grid? In the US, 33% plan to.

4. Indian government partially privatises coal mine, but at the right price?

5. Australia’s Q4 2025 power prices halve after renewables boom

6. How UK cuts to renewables subsidies could change investment sentiment

7. How Amazon lay-offs could impact the UK former coalfields

8. Transmission costs are putting off UK wind developers

9. China tripled oil & gas BRI engagement abroad in 2025, mostly in Africa

10. Offshore wind is about security not cost reduction - Hamburg & CfDs

Getting more bang for buck on rooftop solar

UK rooftop solar costs 2.6x more to install than in Australia. The Warm Homes Plan's £15b investment is welcome, but the government should get more value for money.

The Warm Homes Plan will fund upgrades to reduce energy bills, mainly in heating but also in electricity investments like solar and batteries.

The input costs of solar systems have plummeted, but British installation costs haven't. The government could get more value for money, reach more homes, and save more on bills by helping to bring down unit installation costs.

How could it do this? Some ideas from Australia and beyond:

• Reward speed: installers who deliver fast have less customer attrition and lower customer acquisition costs

• Coordinate installations: reduce fixed costs of scaffolding, planning applications, and disruption by joining forces with neighbours

• Public procurement: generate scale benefits from higher volumes via councils, social landlords, and large scale customers (similar to GB Energy's NHS and schools deal)

• Aggregated procurement: support installers to get better deals through a central facility, similar to programs for the off-grid solar sector in Africa

• Streamline planning applications and safety / quality inspections

• Automate the approval for any required grid upgrades and deliver these on time

What do you think - are the high costs of solar justified in the UK, and if not, what could reduce them?

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How EVs can help when power goes down

When I visited West Virginia, tens of thousands of residents were cut off from power. Reliable coal couldn't help them when storms brought down powerlines. More Electric Vehicles might have.

Even a portion of an EV's charge can power a household for days. This means people could still drive if they used EV charge to power their home. They also have the choice between driving and electricity, an option petrol cars don't offer.

Really interesting to see reports in Cornwall of people using their EVs to deal with power outages due to weather.

I think demand response and in-home energy storage is a still untapped opportunity and could go a long way towards reduces energy costs and increasing system resiliency. Not everyone in the UK can or should own a car, so other solutions like batteries can help fill that gap.

What do you think - should we be supporting EVs more as a grid resiliency measure, not just for carbon emissions, air quality and fuel cost savings?

Should data centres go flexible and off-grid?

Energy for AI is constrained. This leads to extremes like delaying coal retirements, or using jet-engine-like turbines to get projects powered up before the grid arrives. According to Cleanview, 33% of data centres in the pipeline are planning to be off-grid in the US.

The largest models need always-on power and fast. They could checkpoint to tolerate downtime and intermittency, but time is the ultimate commodity. It's a race to develop the next model ahead of competitors. Intermittent power may be cheaper, but reduces utilisation.

Nimble providers can innovate by offering flexible data centres, building modular generation systems and making use of cheap energy for customers that can handle shut-downs in their workflow.

They may not attract the largest model developers but they serve a flexible customer segment that otherwise would be squeezed out from the data centre capacity landgrab.

What do you think about the potential for modular data centres to deliver compute for AI developers?

This discussion was part of a panel at SALT London on AI infrastructure and applications, building on my column on the same topic last year. Watch the full panel here.

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Did India get a bad deal on its coking coal partial privatisation?

When governments privatise assets, setting the price is lose-lose. Sell too low and citizens lose out. Sell too high and no one will buy it. How do we rate the Indian government's $119m coal privatisation this month?

India's coal mines are predominantly state-owned, and the largest coal conglomerate is Coal India. Earlier this month, they sold a ~10% stake in their subsidiary, Bharat Coking Coal, via an IPO. I visited one of BCCL's underground mines on my last trip to India.

The IPO was way over-subscribed, and the stocks priced at the top of the issuing range, ₹23 per share. This generated $119m (before fees) for the government, and ultimately the people of India.

When the stock later listed on the market, it 'popped' to ₹45 per share, a 96% bump. This enthusiasm for the stock is potentially $114m of value the government left on the table.

Since the debut, the stock price has fallen to ~₹38 per share, still a 65% premium to issue price.

So was this a good deal for India, or for the investors?

Companies may want an IPO to pop above issuance price to generate buzz, and attract demand for future stock issuances. But they don't want it to pop too much otherwise they lose potential money they could have raised.

Governments face a similar problem, but they're accountable to citizens for getting a good deal.

Coal for steel-making is harder to displace than coal in the power sector. Coking coal is a more valuable and resilient asset than India's lower quality coal resources. Even if coal quickly exits the power sector (I don't think this is at all likely), coking coal has much more time to turn a profit.

India also doesn't price in all the externalities of coal, like health or environmental costs, and it doesn't invest coal profits in a fund to support people when coal eventually goes away.

My view is that selling one of the best state coal assets with this many subsidised externalities should probably have generated more value for the Indian taxpayer than its issue price, even with the decline since its stock listing.

I'm curious what you think about how government gets the most value out of privatising state assets and any examples of this going really well or really terribly?

Australia’s Q4 2025 power prices halve after renewables boom

A headline the UK would love to have - '“Landmark moment:” Prices plunge as renewables supply half of grid, batteries surge and [fossil fuel] hits new low.' Alas, this is Australia, where wholesale prices fell 50% to ~£25/MWh in Q4 2025.

The chart shows how the mix of different technologies changed between Q4 2024 and Q4 2025 for average dispatch across the day. Wind, solar, batteries are up, while coal and gas are down (also hydro, not sure why).

"As usual, average wholesale prices were lowest in those with the biggest share of wind and solar – such as Victoria and South Australia (both ~£18/MWh) – and highest in those most dependent on coal, NSW (~£37/MWh) and Queensland (~£29/MWh)."

This is an incredible result that the UK could only dream of. That would be a >2/3rds drop from UK 2025 average prices, and is less than half of our cheapest CfDs.

It may not last. "The March quarter is likely to tell a different story given the extraordinary heatwaves that swept the country in January."

It also may not impact total bills much, or soon. From The Guardian - "Network costs make up about 39% [of bills], while 16% goes to energy retailers’ administrative costs and profit margin. About 7% covers environmental policies." "The falls in wholesale prices ... may take time to flow through to customers because energy retailers often sign contracts for electricity years in advance."

I'm especially interested in how market design and mix of contracted vs wholesale power can drive a similar outcome for the UK. What do you think the UK could learn from the Australian experience?

Read more from Giles Parkinson @ at Renew Economy

And Petra Stock @ The Guardian

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UK cuts RO subsidies by changing inflation linkage

30% of the UK's electricity is subsidised* and rises with the 'retail price index'. By switching to CPI, the government saves ~90-120 bps of annual price increases**. Should investors be upset?

Companies underwrote energy projects assuming an RPI forecast, not CPI. Because of its methodology, RPI was consistently above CPI - ~90 bps over the last ~40 years and ~70 bps higher when ROs were first introduced.

Investors would have factored this into their returns calculations, and believed the government would honour their contracts.

The government at the time was trying to incentivise renewable development, and inflation linkages helped. It doesn't exactly reflect the ongoing cost inflation of running a renewable project, as the bulk of expenses are upfront.

In my view, UK investors have done very well out of the RO scheme, especially with above average inflation long after many projects were in the ground, and the falling cost of financing since ROs were introduced. I don't see it as a big issue to bring cost rises in line with inflation, and indeed can even see a case for keeping them fixed in nominal terms or shortening their duration.

Nonetheless, I expect investors to be grumpy about this change, and claim that it increases the cost of capital of investing in UK energy because the government can't be trusted to stick to their contracts. But the decision to share some of these gains with consumers on affordability grounds feels like a small price for investors to pay. Opposition parties have pledged to scrap carbon pricing and subsidy systems entirely if they get into power, and this appears to be resonating with a large number of voters.

What do you think about this RPI change? Is the £270m annual gain worth any potential 'investor confidence' hit?

*You could argue more is covered under CfDs, also indexed to inflation, but this is not a straight subsidy as it is structured as a price guarantee - it's just turned out as subsidies way because contracted prices have usually been higher than market prices.

** Average of last 10 years is higher, ~120 bps.

Former UK coalfields are more exposed to Amazon lay-off risks

You know which British regions are highly dependent on warehousing jobs? Former coal communities. Will Amazon's mass lay-offs be the new miner's strikes?

From the Coalfields Regeneration Trust in 2024:

"Across the former coalfields, warehousing employment is now beginning to match the number of jobs in the coal industry itself in the years prior to the 1984/5 miners strike." 176,000 jobs in total as of 2022, often on the site of former coalmines.

"The warehousing jobs are concentrated. There are almost 60,000 in the former Yorkshire coalfield. The adjoining coalfields in Nottinghamshire and North Derbyshire account for nearly 30,000, and there are 20,000 more just across the Pennines in the former Lancashire coalfield."

Keep watching these updates to see how many of these job cuts will be in the UK - and where. The impact could be devastating if these jobs are concentrated in regional areas that already face worse health and employment outcomes than the UK average.

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Balancing resource availability and transmission cost is hitting investment

Building projects where it's windiest isn't enough to make them the cheapest - the power needs to get to where people use it.

Wind developers in Scotland are being hit with higher transmission costs than those sited closer to demand centres.

This seems like a good thing to me, because it recognises the system costs of electricity, not just its unit costs. It incentivises projects to be built where the all-in cost is lowest.

As a counter example - the UK has low solar irradiation compared to other booming solar markets, and middling to high solar build costs. But solar is still cost-effective here versus alternative technologies.

We accept that the cost of upstream transport is embedded in the fuel price for resources like coal and gas. Although transmission costs are a different concept, it seems odd to consider resource availability of renewables but ignore "transport" costs at dispatch when choosing where to build new projects.

I do think there's a case for subsidising T&D for rural electrification - but that's a different issue from subsidising rural generation to connect to demand centres in cities.

China tripled oil & gas deals abroad in 2025

In 2025, China's BRI engagement in oil & gas almost tripled to $71b. This dwarfs clean energy investments at $18b. For an 'electro-state', they seem quite keen on fossil fuels....

Dr. Christoph NEDOPIL WANG's new report on BRI from Griffith University has a lot to unpack. Here's what stands out to me:
🌍 Africa received ~48% of construction contracts and ~22% of investment for a total of $80b in 'engagement' (out of $214b globally).
⚡ Energy engagement was the largest category at $94b, and more than doubled from 2024.
🔥 Fossil fuels were 76% of energy engagement - and this share rose since previous years.
⛏️ China is still investing in coal-related assets abroad ($2.5b), primarily mining infrastructure.
👷 'Exploitation' (mining, oil & gas extraction) was more than half of energy engagement.
🛢️ All the figures above are heavily skewed by two investments (46% of energy; 54% of Africa): $23b oil and gas project in Republic of Congo and $20b gas development in Nigeria.

What do I think?

• The electro-state narrative is right in that China is building more renewables than anyone and supplying the world, but they are still very much in the market for fossil fuels too. Adding more renewables does not reduce emissions unless fossil fuel consumption goes down.

• BRI funding for renewables looks strikingly low given China's huge clean energy manufacturing sector, but China may not need to push its products with BRI funding to drive exports given their competitive price point.

• Investing in oil and gas is helpful given China's more limited domestic production of these fuels. They don't need to supplement coal so much.

• BRI engagements don't read like aid or plunder, but projects with commercial and industrial benefits for both parties.

• Single year figures are lumpy - mega projects skew the results - so watch for sustained trends over time.
  
  What jumps out at you from Christoph's report?

Offshore wind is about security, not cost reduction

Gas prices are up >30% in January - a reminder of the price shocks and energy dependency that renewables protect against. This week's Hamburg declaration on offshore wind is framed as a 'security pact', unlike 'bill-cutting' CfDs.

The Hamburg declaration, a collaboration on 100GW of offshore wind development in the North Sea, greatly emphasises security in its press release. This feels right to me, as offshore wind isn’t always the lowest cost.

The typical pro-renewable narrative on the UK’s CfDs is that even if they price at levels above today’s wholesale rates, they reduce cost by two primary mechanisms:

1) Displacing gas to reduce traded wholesale prices

2) Avoiding investment in even costlier technologies

To be clear, I am also pro-renewables and pro-climate action. But when a voter thinks about the promise to cut energy bills, it isn’t about whether the government avoids higher future costs - it’s about whether their bills are actually lower than last year.

As the UK Energy Research Centre (UKERC) reported this week, 2/3rds of the price rise from 2021 to 2025 was from an increase in gas prices. I have a hard time imagining how a unit CfD price that is 17% higher than 2025 wholesale prices (set by gas) and linked to ongoing inflation will lead to bills going down in absolute terms when those projects come online.

These CfDs could reduce traded prices for gas on wholesale markets - but then customers are hit with a subsidy top-up.

This linkage does have a positive outsized impact because CfDs are a small share of total demand. But when CfDs start to represent 40%+ of the market (the estimate for projects through to AR6 as a share of energy demand in 2030), they need to deliver a larger saving across a smaller amount of generators remaining on wholesale markets. And if wholesale generator costs do plummet, it will beg the question of why so many generators are locked into higher priced contracts.

I’m also speaking in terms of comparing energy costs to prior years. Estimates I’ve seen of savings from CfDs are often avoided costs rather than actual cost reduction. Avoiding cost is great, but I can understand why people get frustrated when they are told bills have been brought down by renewables, then see prices go up - as they did this quarter.

I see the government prioritising energy security and protection against price shocks with their offshore wind CfDs and the Hamburg declaration, which is a really important goal.

But I think we need more discussion among the pro-renewables crowd on whether policies are about cost management or deliver other important benefits, and how we communicate this to voters.

Other policies will bring costs down, so why does offshore wind need to be sold on cost instead of security? We risk disappointment and even more net zero backlash if we get the message wrong.

Read more in my LabourList piece last week.

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As the last shard of light escaped under the elevator door, I asked Sumit how deep we were going. 538 metres, he said. I felt woozy. I had never been so conscious that the oxygen in the air could vanish. I followed his instructions to take deep breaths and relax. After a clanking eternity, the lift finally reached the working level of the Moonidih mine in Dhanbad, India’s coal capital. We were greeted by a throng of workers waiting to return to the surface at the end of their shift.

Since the Moonidih mine in Dhanbad was built in the 1960s, India’s coal consumption has grown 15-fold[i]. As of 2025, India’s coal production was the second highest in the world at 1.1 billion tonnes per year, dwarfed only by China. India is still expanding its coal mines and power plants, even as solar and batteries now rival coal to deliver low-cost and reliable electricity.

At the power system level, it makes economic sense to stop using coal when it becomes more expensive than alternatives. This is already happening in market-exposed energy systems, and India saw a 3% decline in coal power consumption in 2025. Long lead-times to install plants, increasingly cost-competitive clean energy that can deliver reliable electricity, and the steep environmental and health costs of coal are all trends that should suppress demand.

To understand why coal power persists, look for the benefits upstream. Coal-fired electricity is usually provided by a domestic mining industry, with just 16% of global coal production crossing international borders[ii]. Coal mining offers advantages like employment, tax revenue, currency management, and international independence. This is before considering the opportunities coal creates for political donations, fighting culture wars, and even corruption. Renewables, nuclear, or gas may deliver cheaper electricity but may struggle to replace the macro benefits of coal, especially if governments continue to avoid pricing in health and climate impacts.

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For India, coal jobs are important, but not the whole story. Despite announcements of recruitment drives and job creation, workers are also retiring or being pushed out by machines. This was confirmed by staff at Moonidih, a subsidiary of the largest government-owned coal company, Coal India Limited (CIL). CIL employed 220,000 people as of 2025, 32% fewer than in 2016. Over the same period, production increased by 45%, more than doubling productivity per worker. Pressure to reduce costs has led to more outsourcing and less stable employment, with CIL now indirectly employing 114,000 contractors in 2025.

CIL production and workforce, FY16 to FY25

Even with adjacent jobs, possibly as high as four million in 2021, the Indian coal industry employs less than 1% of the working population. Renewables already employ over one million people in India, and the sector is rapidly growing. However, coal is regionally concentrated, which leaves some locations exceptionally exposed to job losses. NGOs have been calling on the government to support workers losing their jobs as coalfields become more efficient or decline.

The real prize of coal seems to be government revenue. The government controls 85% of the country’s coal production via two companies, CIL and SCCL[iii]. In 2024/25, the Indian government collected over $11.3 billion in revenue from royalties, dividends, and income taxes from these two entities[iv]. Locally mined coal generated over $8 billion in levies for state and national governments, $1.6 billion in income tax, and $1.3 billion in dividends from state-owned coal profits. The government’s 74% stake in CIL[v] is worth over $20 billion at current market prices, and the government periodically sells shares to raise additional revenue.

Estimated government revenue from state-owned mining entities CIL and SCCL, 2024/25

These two entities alone generated the equivalent of 1.4% of India’s national and state government revenue in 2024-25[vi]. IISD estimated that the government’s coal revenue across all sources was $17 billion for 2023/24, or 2.3% of the total[vii]. This might sound small but remember the drama around Britain’s budget “black hole” in 2024. This £22 billion shortfall represented 1.9% of all government receipts[viii].

Estimated total government revenue from coal, FY14 to FY24, Real 2024 $ billion

Coal also offers other macroeconomic upsides. Growth in domestic coal saved $5.4 billion in foreign currency for imports in 2023-24, a meaningful boost to the current account deficit of $23.3 billion. Continuing to use coal reduces dependence on importing foreign products, including solar panels and batteries from China. Coal also subsidises India’s railways, with freight payments amounting to $10 billion in 2022-23, around 33% of the railway company’s total earnings.

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Keeping coal in India’s energy system is an indirect way to collect extra tax revenue via electricity bills and subsidise other services. This is not so different from the UK levying a carbon tax on electricity generators through energy bills and using the proceeds to fund billions of pounds of general government spending. This is in stark contrast to India’s approach for state-owned railway operations, which operate with almost no profit margins to offer low-cost passenger services.

These coal rents mean government has some leeway to protect coal in the face of competition from renewables, by removing coal taxes or reducing state-owned enterprise dividends. The government already cedes at least $3.2 billion in revenue from discounted import tariffs and sales to utilities. It reduced coal costs further in September 2025, by replacing a coal tax (‘compensation cess’) with an increase in GST.

Renewables will need to offer more than cheap and reliable electricity to displace coal at a faster pace. Clean energy already provides large-scale employment but domestic company profits have yet to generate the same rents that coal provides the state. Solar and battery installations have been historically dependent on imports, with a significant portion sourced from China despite tensions between the two countries. The Indian government and cleantech industry recognise this, with a push for domestic manufacturing to generate local income, maintain independence, and manage foreign exchange. True independence will require more than just local assembly and component manufacturing, but also sourcing and processing raw materials domestically.

Pushing the government to recognise the environmental and health damage of coal in energy bills would help even more. In Dhanbad, the hills are literally on fire and have been for over a century. Homes spontaneously combust and residents inhale polluted air. Across India, millions of people die prematurely due to fossil fuel particulate inhalation each year, yet the government recently exempted 78% of coal plants from installing equipment that would protect against harmful pollutants. The government’s coal taxes could be considered compensation for these effects, but this revenue is not set according to coal’s health and environmental damage, nor is it necessarily spent on remediating these issues. The renewables industry could lobby for coal taxes to reflect these costs, and for proceeds to be invested in transition funds instead of in-year general spending.

As the world’s third largest carbon emitter, India’s coal future matters for global climate change, and it also impacts human health. Accelerating clean energy installations in India is not just about matching coal costs and reliability at the power plant level but delivering comparable benefits to the state like tax revenue, independence, and foreign exchange savings. It’s too soon to celebrate last year’s decline in coal consumption. Until clean energy can match coal’s upstream pay-offs, or coal’s true costs are reflected on energy bills, coal is likely to remain in the system longer than power plant economics alone would suggest.

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Subscribe for more updates and analysis on the energy transition. I focus on the UK energy sector and the global coal transition, but occasionally publish on other topics.

[i] Measured in Exajoules, not tonnes, due to data availability.

[ii] IEA Coal 2025, tonnes traded (1.5 billion) divided by tonnes produced (9.1 billion).

[iii] Singareni Collieries Company Limited, jointly owned by the Telangana state government (51%) and national government (49%).

[iv] This is my estimate for CIL and SCCL. I have not included benefits/dividends from the power companies like NTPC.

[v] Direct stake of 63.1% and indirect stake of 10.8%, a 11.2% stake held by a 96.5% state-owned life insurance agency

[vi] Using national revenue of ~$365 billion, state’s own revenue of ~$309 billion, shareable transfers of ~$153 billion. This method is line with the totals used in the IISD report for prior years, rolled forward to 2024/25.

[vii] IISD’s estimates includes CIL and SCCL, as well as revenue collected from customs duties and GST outside of these two entities. Detailed excel files here.

[viii] Using financial year receipts from April 2024 to March 2025

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The UK is a world leader in high electricity costs and I am constantly asked why. I am hard-pressed to identify one single cause. The cost of generating electricity has risen, especially since the Ukraine War, but so has the other two thirds of the energy bill. I’m even harder pressed to identify a silver-bullet solution to bring down costs.

Domestic electricity prices by country, 2024

Why are British electricity costs high?

I have a few theories about why electricity prices are high in Britain.

The UK generally is a highly liberalised and privatised electricity market. This alone can partially explain Britain’s high prices. A private sector owner is likely to extract more profit and have higher financing costs, which could outweigh any efficiency gains relative to a state-owned company.

Interconnected grids also reduce cost by allowing electricity to flow freely between demand and supply centres. As an island, Britain has lower interconnection than mainland Europe, and it has bottlenecks throughout its transmission system. Low-cost generation cannot always be dispatched where it is needed, increasing system costs.

Generation (wholesale) costs make up about a third of the UK’s electricity bill. These went up due to gas price spikes but are also generally high in the UK because construction is more expensive. This is driven by planning restrictions, environmental surveys, safety regulations, grid connection delays, and more.

Price cap unit electricity prices by bill component, by financial year

The remaining two thirds come from network costs, subsidies and other government policy choices, supplier margins, and tax. Network costs and subsidies have both risen dramatically due to the build-out of renewable energy and balancing the grid. This was compounded by broader inflation, which is baked into network revenue and subsidy payments.

Even if wholesale costs fall by half to pre-Ukraine war levels, the UK would still need to bring down the rest of the costs to get anywhere close to historic levels or a regionally competitive electricity price[1].

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Costs are likely to continue rising

Electricity bills are set to rise even more over the next five years, mainly driven by network costs and levies. Transmission alone is expected to cost 50% more in 2026/27 than in the prior financial year. New levies, like the funding for Sizewell C, will add further costs. This is offset by the hope of lower wholesale prices from renewable energy, and smaller generation subsidies as legacy programs like Renewable Obligations phase out. Unless wholesale costs decrease by more than 50% to £0.039 per kWh (2025 prices), analysis by Ben James suggests that all-in electricity prices are projected to stay the same or go up in real terms by 2030[2].

An estimate of electricity bill price rises, 2025 to 2030

Cost reduction by a thousand cuts

Focusing on wholesale prices alone won’t solve Britain’s electricity cost problem. Indeed, trawling through Ofgem and NESO data is a demoralising experience for anyone trying to identify ways to decrease energy bills. Chipping away at each bill component offers some hope[3].

Small cuts to policy costs in the short term can reduce bills and restore faith in government’s net zero and cost pledges. The government recognised this with their Autumn budget announcement to move 75% of Renewable Obligation (RO) subsidies off of bills, and end the Energy Company Obligation (ECO) efficiency scheme.

Eliminating policy costs from the bill entirely would reduce unit costs by an estimated 25%. In an illustrative analysis using the all-in unit costs (variable plus standing charges) from the latest Q1 2026 price cap, prices would fall from 35p per kWh to 26p per kWh, including the existing policy to scrap ECO and shift RO costs. This would help the government meet its pledge to deliver lower electricity bills. Unless they repeal these policies, which are increasingly about ensuring energy security rather than subsidising new technologies, these costs won’t go away[4]. Shuffling them to the Treasury may not be practical in the long-term, but it is expedient.

Illustrative bill reductions from the Q1 2026 price cap from policy cost decisions

A popular policy on the right is to scrap carbon taxes. When gas is the marginal price setter, wholesale prices for all bidders include carbon costs, so scrapping the tax would have an impact beyond the carbon-intensive generators. This would reduce bills by another 6 percentage points, or an estimated 2p per kWh depending on carbon prices and how often gas sets the marginal price[5].

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Like shifting policy costs, this bill saving would cost the Treasury. The Emissions Trading Scheme is expected to generate £2.6 billion in 2025/26 plus ~£400 million (2024/25) from the Carbon Support Price[6]. Changing the UK’s climate commitments would also affect energy investors’ ability to underwrite projects, if they perceive higher risks from government policy changes. It could come back to bite the UK in trade agreements with the EU, particularly the Carbon Border Adjustment Mechanism. For the avoidance of doubt, I do not support scrapping carbon prices in the UK.

These changes combined with VAT could bring bills down by 28% to 34% depending on if the carbon price remains, before tackling network, wholesale or supplier costs.

Tackling network costs

I started researching this piece by looking at just transmission and distribution costs. Most media coverage focuses on the cost of generation, subsidies, and increasingly, balancing. I wanted to estimate the impact of bold ideas to re-nationalise the grid, reduce network losses, or spread fixed costs over more demand. My high-level analysis suggests they have a surprisingly small impact on energy bills in the short term. This is partly because they only make up one sixth of the bill in the first place[7], though this figure is set to rise, and also perhaps because my assumptions are conservative.

Transmission and distribution companies, collectively networks, are privately owned in the UK. They were privatised in the Thatcher era to unleash private sector efficiency on improving the grid[8]. Nowadays, network profits are dictated by a Regulated Asset Base formula to avoid utilities taking advantage of customers with their monopolistic service. Networks can charge for operational expenses, replacement costs associated with depreciation, and a guaranteed return on their assets[9].

Since privatisation, networks have delivered significant returns to shareholders. Bringing networks back under public ownership could reduce costs because government borrowing rates are lower than private capital costs. Regulatory hijinks aside[10], investment returns are supposed to make up between 20 to 30% of network company base revenue in regulatory models. Refinancing the allowed revenue at today’s government long-term interest rates, around 4 to 5%, would reduce returns by around a third[11]. Applying these savings to Distribution and Transmission costs on the price cap saves around 0.5p per kWh[12], an order of magnitude lower than estimates from a 2019 study with a different methodology[13]. Nationalising may have other benefits if it can accelerate grid investment, but reducing financing costs alone doesn’t seem worth the political upheaval of changing ownership[14].

The UK also has high transmission and distribution losses relative to Europe. In 2024, losses were 8.9% of total British public distribution system demand[15], versus the European median of 5.6% in 2022. If losses went down to the European median, variable electricity costs could fall by ~3.5% from the efficiency gain. At least 60% of the electricity bill was variable in Q1 2026, so this could deliver another 0.5p per kWh in savings. This would probably require some capital investment, which may be too high to offset any benefits.

The UK’s transmission and distribution systems have high fixed costs and are spread over a diminishing base of demand. Transmission costs have increased in absolute terms, but they have grown even more per unit. Allowed revenue for the transmission system, a proxy for costs[16], rose by 93% between FY16 and FY26. Over this same period, electricity consumption from the distribution network fell 12%[17]. These factors combined led to a 120% growth in unit transmission costs[18].

Estimated change in transmission unit cost, split by expenditure and demand drivers

2025 was the first year that electricity demand rose in a decade, barring the post-COVID rebound. The network has expanded in that time to accommodate more connections. If electricity demand increased, unit network costs could go down, starting a virtuous cycle of cost declines from higher utilisation of network infrastructure. With 10% higher demand, network costs could fall on a unit basis by up to ~0.9p per kWh if all network costs were fixed. This small reduction is unlikely to drive much of a flywheel effect in the absence of other price cuts.

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Even more illustrative bill reductions from the Q1 2026 price cap based on policy cost decisions, network changes and wholesale cost reductions

And the rest?

I did this exercise primarily to understand the relative magnitude of a few different solutions to reduce electricity bills beyond bringing down wholesale costs. There are countless other policies I did not consider in this analysis, and the analysis I did was at a high level with assumptions that could be debated. These estimates are very rough and I do not support implementing all these options. Different changes could interact with each other, for example moving so much cost to central budgets could have unintended consequences if it causes demand for electricity to increase dramatically.

Reducing wholesale prices by half from 2025 would be a bigger prize than any of these other changes, around 3p per kWh net of carbon price reductions[19]. This could support a cumulative bill reduction of almost 50% inclusive of all the illustrative cuts (noting again that I do not support scrapping carbon prices and that these cuts do not necessarily reduce system costs but change who pays).

Bringing down wholesale costs is a function of cost of capital, build costs, and market design. The decline in renewable technology input costs (e.g. for battery and solar) has been promising internationally, but the UK’s solar install costs were 24% higher than neighbouring Ireland in 2023. By 2024, the UK’s offshore wind capex was 4% higher than Europe averages, and 42% higher than Asia, and onshore wind was the highest cost in the top markets covered by IRENA. Focusing on speeding up grid connections and construction, and bringing down build costs could drive meaningful savings.

Reforming markets could help to capture some of the upside of lower energy costs, by reflecting geographic constraints in pricing. Increasing flexible technologies like batteries, Electric Vehicles, and heat pumps could reduce the requirements for grid build-out if they can participate fully in the market. At the right electricity price, this would also reduce total energy bills by switching from gas or petrol to electric.

By laying out these options, I have found hope in the political possibilities of reducing bills. Reducing real costs is more challenging. In my view, tinkering with markets and ownership structures might help to make British energy prices more competitive. But it is essential that the UK reduces the cost of building energy infrastructure and the uptake of flexible technology to reduce investment needs in the network. I don’t see how energy costs can fall meaningfully without changing how and what we build.

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Subscribe to read more about UK energy, and international stories on coal and the energy transition. Read on for a bumper list of footnotes.

[1] Though to be fair, my analysis focuses on household electricity bills and not industrial prices – what we usually think of when we think about “competing” on energy prices.

[2] Ofgem has representative consumption coming down for the average household to 2,700 kWh per year as of November 2025. This number may go up as more households adopt electric heating and vehicles so I tend to focus on unit costs rather than bills.

[3] As does Ofgem’s decision to make bills appear a bit lower by reducing the amount of electricity it thinks households use.

[4] Except for the scrapped ECO.

[5] The Carbon Support Price is fixed at £18 per tonne, and the Emissions Trading Scheme price fluctuates with the market (£49 per tonne in 2025 and £68 per tonne in January 2026). Gas is estimated to set the price 85% of the time as of 2024 and less in future. Much of the market is also contracted by CfDs or over the counter contracts. A conservative estimate of cost reduction potential would add these two factors together (as in CBP analysis), but in reality the CfD delivery times have some correlation with the times when gas is setting the price so savings may higher.

[6] CBP analysis.

[7] Ofgem price cap, Q1 2026, TNuoS and DNuoS as a percentage of total bills.

[8] Whether this has happened is debatable – read Arthur Downing’s work to learn more.

[9] These are the main buckets, there other revenue items like pass-throughs and performance incentives.

[10] Investors optimise each regulatory cycle to increase returns, for example adding more leverage than the regulated returns compensate for, or re-financing at lower rates. These loopholes are sometimes closed in the next cycle.

[11] Returns for electricity networks are ~3.5% to 4% real WACC, plus inflation at 2.5% to 3.5%. If government financing is at 4 to 5%, this represents a saving of 2 percentage points.

[12] Using per kWh TNuoS and DNuoS costs on the Ofgem price cap, weighted average by region, applying their respective percentages of returns as a percentage of base revenue in FY26 (27% and 24%) and reducing this cost by one third (~4.3% to ~5.1% long-term government gilt rates versus ~6.3% to ~7.5% inflation-adjusted WACC).

[13] Multiplying 0.5p per kWh x 2,700 kWh of demand = ~£13 per customer saved. The study estimates savings of £142 per household from nationalising electricity grids. Partly this is because this was a low rates environment, but it also is a difference in methodology. I have looked at the allowed returns of electricity companies, rather than their dividends. I have also not assumed any reduction in revenue from remunerating depreciation. The author also assumes total financing costs are ~£5 billion across network companies in future, which seems high considering allowed revenue for T&D companies in 2025/26 is £11.9 billion.

[14] Networks also deliver outsized returns relative to their regulated returns in part because of re-financing beyond regulatory limits and because they can claim depreciation as a cash benefit even if not investing that level of maintenance capex.

[15] DUKES 5.2.

[16] This is an imperfect proxy that covers all generation, not just households. It is derived from allowed revenue for the Transmission companies, less connection revenue, and adding offshore transmission revenue. Allowed Revenue is consistently published by NESO and TNuoS costs feature in the consumer bill Price Cap.

[17] Using calendar year 2024 instead of FY2024-25 for the 2025 estimate.

[18] This will look different from the changes in the TNuoS section of the domestic price cap for a few reasons (possibly more). Transmission costs are levied on both generators and end customers, so a small portion of transmission cost is embedded in wholesale prices. The price cap was using the same per-household demand for the past 10 years (3,100 kWh), only reducing it in January 2026 (2,700 kWh).

[19] Wholesale price allowances on the bill are more like 10p per kWh, possibly because of contracts outside wholesale markets and higher anticipated costs in Q1 2026 compared to calendar year 2025. ~3p per kWh avoids double-counting the carbon price reduction.

High prices cure high prices. This is a comforting maxim in commodities markets, because it suggests that price spikes won’t last long. Investors develop new supplies while a commodity is expensive, and prices come down as this production comes online. Similarly, when prices are low, investment in high-cost production stops, eventually raising prices again.

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This phenomenon has not quite translated to Britain’s electricity market[1]. Renewable energy is supposed to be cheap. If prices are high, this should be a boon for those providers, unleashing a flood of investment. Indeed, several projects have come online, and a record number are in the pipeline. Yet renewables developers still want a government backstop for prices. Why?

The simplest answer would be that renewable energy isn’t cheap after all. Building both solar and onshore wind is more expensive in the UK than globally. The UK has similar or higher wind resource than the world average, while solar is lower. Even though the UK may benefit from lower cost of capital than other countries, British solar and onshore wind has a high levelised cost of electricity (LCOE), a theoretical measure for the cost of generating a unit of electricity over its project life. This calculation is highly sensitive to capital expenditure and cost of capital, which has risen since the UK figures were calculated[2]. Although the quoted LCOEs are lower than current wholesale prices, they may not be representative of current costs[3].

Capital cost (£/MW) and Levelised Cost of Electricity (£/MWh) by technology, 2023 figures and prices

Another simple answer is that renewables capture a lower price than the rest of the market. This was certainly doing the rounds on the conference circuit in 2025, driven by high solar production in Europe. When renewables are generating at the same time due to correlated weather events, this brings down prices. This is partly because renewables are a low-marginal cost source of energy, and partly because if projects have a contract or a subsidy, they can bid close to zero and still be paid well[4]. This discount is real but not catastrophic in the UK because the prevailing market price is so high. Solar and wind capturing ~80% to ~90% of the average wholesale price (£67 to £74 per MWh in 2025) is still higher than Arup’s estimate of British wholesale costs and is on par with current contracted prices[5].

Capture prices of wind and solar relative to wholesale prices by year

Which brings us to the purpose of government contracts for electricity. As much as ~46% of solar and ~16% of wind capacity[6] in the UK is not supported by the government’s flagship subsidy and contract schemes[7], suggesting at least some have been financed outside these channels. Let’s assume that renewable energy can be built cheaply enough to beat gas prices[8], and that they will still make enough money on wholesale markets even with the discount. What, then, is the incentive to contract for each counterparty?

Percent of renewables capacity by support mechanism

Conventional wisdom is that government-backed contracts for renewable energy reduce costs by reducing risk. In the UK, the government supports renewable energy with Contracts for Difference (CfDs)[9], which guarantees projects an inflation-adjusted price for 15 to 20 years[10]. The contract reduces revenue risk, which in turn reduces the investment return for debt and equity that financiers are willing to accept to fund the project. When almost all the cost of renewable energy is up-front, this directly translates into reducing unit costs. Depending on how competitive the market is and how this saving is shared, it is a win for both investors and consumers.

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This capital-cost-reduction benefit has not yet translated to cheaper prices, in part because earlier CfDs were primarily a subsidy to support renewables. Over £12 billion has been paid to CfD holders since 2017, or ~£66 per MWh. Just one year yielded a net gain to the government: 2022 when energy prices skyrocketed. Newer solar projects [11] returned over £1 billion to the government in 2025, but the vast majority of the low-cost CfDs have yet to be built. There could be a big surplus in future, but inflation may erode new CfD cost advantages by the time projects come online.

Total payments and subsidies/(surplus) to CfD generators over time

What if another benefit of these government contracts was important: hedging. Buyers may want to insulate themselves from rising prices and are willing to pay a premium. Sellers may want to lock in prices now in case they fall in future.

The power of each counterparty dictates who profits most from the trade[12]. In a market with falling prices and big returns to reducing the cost of capital from contracts, I would expect incredibly competitive bidding from the private sector. I suspect that the government now has more to lose than the energy developers, and may pay up to insure against price rises.

Whenever I’ve spoken to veteran power sector investors and traders, they hold a belief that wholesale prices will be lower than forecast and certainly wouldn’t go up with inflation. This may be a conservative view that makes their deals look more profitable than they originally planned, or it may reflect lived experience of being burned by wholesale power markets. Investors who believe that wholesale prices will go down, and who receive a reduction in capital costs for fixing prices, are more likely to keep their CfD bids low. Their counterparty would then reduce their volatility and short-term prices but lose out on the benefit of wholesale prices going down in future.

What’s happening now is the opposite. Demand is increasing for the first time in decades, and likely to go up further with the rise data centres, and electric vehicles and heating. The additional infrastructure investment required to meet this demand is huge and takes time. Households and businesses have been strained by price shocks that they expect the government to protect them from in future. The government has a lot to deliver at once: sufficient electricity, at a reasonable price, with low volatility.

This places the government in a less powerful position. They want to guarantee the price for a large amount of newly built electricity generation, and demand is growing. Even though the government is reforming planning and clearing out the grid connection queue, building enough power at pace to meet demand and reduce gas power on the grid will be tough. If supply can’t keep up, wholesale costs will rise. The government could adjust taxation to ensure this price increase won’t affect consumers, but it would still need to be funded as part of the overall budget.

When prices are rising, or there is uncertainty, the opportunity cost for an investor is higher. Think about how mortgage rates go up for longer loans, unless the bank thinks rates are going to fall in future. Developers might charge a premium on wholesale prices to fix their revenue, rather than a discount. The government might end up locking in higher prices for electricity, not necessarily because the cost to build is higher, but because developers know the government values risk reduction and they can profit from it.

The latest CfD auction results are out this week and in early February. If they are higher than prevailing wholesale prices[13], the government will need to explain why cheap renewable energy isn’t delivering. There may be other drivers of this, like higher build and financing costs or an insufficient supply of sites. Bringing down construction costs should remain a government priority.

But the answer may also be that volatility management matters more than lower prices. Prices may go up because the government wants to buy insurance, not because renewables are expensive. If that is the case, the government needs to say so. Otherwise, they risk misleading voters about what contracting electricity is really for. This could put the public off “costly” renewable technology even if it is the best way to deliver energy security for Britain.

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[1] Wholesale and retail prices have come down since their price spikes before and during the Ukraine war but they have not settled to pre-war levels. This reduction is primarily due to gas prices settling.

[2] Arup estimates this at between 5 to 5.8% WACC, while CEPA analysis estimates this at 7.6% WACC, both pre-tax real figures.

[3] The LCOEs are also calculated using real pre-tax cost of capital, which is different from post-tax nominal cost of capital.

[4] Later auctions prevent being paid if the market price falls below £0.

[5] The wholesale capture prices shown in the chart are spread across all generated units. The prices for Contract for Difference are for delivered units, which accounts for any times of day when power prices are negative and the project cannot receive payment for its contract.

[6] Range due to potential projects covered under ROs built after the RO annual report date. This impact may be small as ROs closed to new projects in 2017.

[7] Contract for Difference, Renewable Obligation Credits and Feed-in Tariffs.

[8] A BIG assumption – I suspect the cost to build renewables is not cheaper on average compared to gas but is cheaper in volatile years and once projects stop being contracted. Maybe this is worth it – but we won’t get that benefit for 15-20 years.

[9] There are numerous other ways the government supports renewable energy, including carbon prices and other subsidies.

[10] Older contracts last 15 years, newer contracts last 20 years.

[11] Rounds 4 and 5.

[12] As well as strong competition between parties on the same side of the trade.

[13] Or likely to be by the time they come online.

“Gas sets the price of electricity” might just have been the most popular British energy commentary of 2025[1]. This insight offers a simple solution to policy-makers: push gas out of the market to bring down energy bills.

Britain is pushing a massive renewable and nuclear construction agenda, backed by government contracts. But whether gas sets the wholesale price or not is less relevant in a market where an increasing share of electricity has locked-in prices. Contracting so much power may end up counter-productive to reducing cost even if it decreases volatility.

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The original claim that gas sets electricity prices comes from a study in 2023, using data from 2021. In Europe, electricity is traded on wholesale markets in increments of time. The most expensive generator that meets the last unit of demand sets the price for every provider for that period. The study highlighted that in the UK, fossil fuels (read: gas) set the power price 97% of the time in 2021, excluding the worst of the gas shortage caused by the war in Ukraine[2]. In the rest of Europe, this rate is much lower, for example just 7% in France and 58% EU-wide[3]. The UK has much higher electricity prices than this peer group, so gas setting its price is presumably a driving factor.

% of time that fossil fuels set the wholesale price: 97% in the UK in 2021

This statistic isn’t as powerful as it first seems, despite being picked up with zeal in 2025[4]. The methodology itself is an approximation based on the change in bidding behaviour between different time periods. It does not actually track which unit was the marginal producer. ECIU reckon the percentage fell to 85% by 2024, but gas still delivered power in 100% of bidding hours. This statistic implies it is not the most expensive generator at least 15% of the time on short-time wholesale markets or that it isn’t bidding at all. Only 34% of electricity was traded intra-day in the UK according to the study and even less elsewhere. Day-ahead markets, private power purchase agreements (PPAs) and long-term inflation-linked contracts like the government’s Contract for Difference (CfDs) scheme drive a large portion of the electricity price.

CfD contracts mean reducing gas on the grid may not be sufficient to bring down prices. Generators with a CfD are incentivised to bid wholesale prices close to zero because they are paid a fixed price regardless. The traded wholesale price may be lower, but the all-in cost of CfDs is added elsewhere to the bill. Gas can become the most expensive marginal generator through this quirk of contract design, even if its unit costs are less than CfDs. For just 1.3% of 2025, electricity prices were lower than the weighted average CfD contracted (“strike”) price of £151 per megawatt-hour (MWh)[5].

% of 2025 when short-term wholesale prices (MIP) were higher than CfDs: just 4.1% for the future nuclear CfD and 1.3% for active CfDs

The good news is that contracted sites that have yet to be commissioned are much lower priced than historical CfDs. Future onshore wind (£58 per MWh) and offshore wind (£71 per MWh) prices were lower than gas over 73% of the time in 2025. Solar prices (£69 per MWh) beat gas 38% of the time, lower because it only dispatched during the day.

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The bad news is that CfDs lock in prices at a time when costs could rise, for example due to supply chain shortages or grid connection scarcity. CfDs fix the price of electricity for fifteen, now up to twenty years, growing with inflation. Currently, CfDs account for around 12% of total electricity demand in the UK[6]. By 2031, they are estimated to cover 40%. This could go up even further depending on the outcome of future government procurement rounds. The government is also pursuing a significant nuclear strategy, which is unlikely to bring down energy bills by displacing gas based on the current nuclear CfD price of £127 per MWh.

Total electricity demand met by CfDs: 40% by 2031

These prices also exclude other costs like capacity markets, curtailment and balancing.

Capacity markets pay generators like gas plants to be available, even if they don’t dispatch. These payments are approximately £1.4 billion in 2025 calendar year, with annual costs rising over 50% from 2024/25 to 2025/26[7]. These payments subsidise wholesale costs. Spread across every unit of generated electricity in 2025, they reach almost £5 per MWh[8].

Curtailment is when generators are instructed to switch off because there is too little capacity on the network to deliver their electricity to where it is needed. This partly happens because Britain has not expanded its grid infrastructure sufficiently to connect its generating sites to its demand centres, and partly because the power market in the UK does not incorporate any constraints by location. At the time of writing this paragraph, Kilowatts IO estimated that over 1,700 MWh of production had been curtailed in the past 25 minutes. This alone represented £120,000 of payments to plants that switched off. If any of these sites had a CfD above the prevailing price of £71 per MWh, they would be paid even more.

Kilowatts.io real-time energy dashboard: watch and be mesmerised

Curtailment is considered part of balancing costs, which also include paying other generators to switch on in less constrained parts of the network to make sure demand can still be met from another source. There are other drivers of balancing costs like responding to outages, but energy imbalances from thermal constraints make up the lion’s share of the £2.5 billion cost in 2024, or £9 per MWh[8]. This cost is projected to be between £4.3 to £5.2 billion in the 2025 calendar year or another £15 to £18 per MWh.

NESO’s historic balancing costs and volumes: system constraints make up the majority of cost

The argument in favour of CfDs is that they lower the price of electricity through contractual certainty. Generators compete in the auction process for a contract rather than in the short-term markets. The CfD contract helps to lower prices because investors should be willing to accept a lower return on their investment if they are protected from price volatility and uncertainty. This protection also extends to their lenders, who may be willing to finance at higher loan-to-value ratios and lower rates. In theory, this reduces the price of renewable power because remunerating up-front capital expenditure is such a big portion of renewable unit costs. Bringing down the cost of financing, however, is no substitute for reducing the cost and speed to build or making the market more accurately reflect system constraints.

In 2025, there wasn’t a single half-hour period when gas didn’t supply at least one gigawatt of power. Reducing electricity prices is not as simple as building more renewables to use less gas if gas power is more competitive than CfD contracts. The government’s planning and grid reforms are a strong start. They need to make it cheaper and quicker to build energy projects in the first place, and reward plants based on what they physically deliver in a competitive market. Otherwise the government risks signing up to even more fixed capacity when it may not actually be any cheaper than alternatives.

As always I am open to feedback, but in particular welcome thoughts on extending this analysis or pushback on the approach. I plan to look at merchant capture rates for solar plants next, and an analysis on the investment returns of T&D companies. Hit reply or comment below.

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[1] Honourable mention to “zonal pricing will create a postcode lottery” and “paying windfarms to switch off costs over £1 billion”

[2] Russia’s supply of gas to Europe started falling towards the end of 2021, which drove up prices before the Ukraine war began early the following year.

[3] Note how coal disappears as “solid fossil”. It sets the price ~20% of the time.

[4] 98% of the time is the figure sources often quote, but checking the original source it is 97%. It is unclear if the numbers in the study were revised, or just routinely misquoted across different platforms. In addition, Parliament references this as 2023 prices when this was the study publication year, not the year the data was collected.

[5] This calculation is a weighted average of LCCC’s strike prices across all the generation it paid for during 2025, including Investment Contracts and Allocation Rounds 1-5. Source data here. At time of download, data was current to December 18^th with values imputed for the remaining days of the year.

[6] Depending on the denominator. I use NESO’s demand figure as it relates to grid power, which is slightly lower than the UK-wide total.

[7] The capacity market “year” is from October 1st to September 30th. I have estimated the 2025 calendar year figure by taking ~75% of 2024/25 and 25% of 2025/26. This is only an approximation as the estimate of the difference between years is 52% (£1.26b up to £1.92b) but this tracks with monthly capacity market forecasts rising in Q4 2025.

[8] Allocated just to the capacity market generators and when they deliver power, this cost is even higher.

“If your mother was on life support, would you want coal or renewables supplying electricity to her hospital?”

A State senator for West Virginia threw this curveball at me when we were discussing the merits of renewable power over coal. Our conversation had been a series of shifting goalposts, ranging from whether renewables were lower cost, to whether they generated more waste. When we got to the question of guaranteeing dispatchable, reliable power, he had a point [1]. Historically, using renewable energy round-the-clock and relying on it for emergencies has been either impossible or far too expensive. Low-cost batteries are changing that picture.

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Before we talk about batteries, it’s worth clarifying what analysts mean when they say renewable energy is cheap – especially as energy bills have gone up around the world as renewable power has gained market share. Levelised cost of electricity, or LCOE, measures the average cost to produce each kilowatt-hour of electricity during a plant’s usable life, combining capital, financial, and operating expenses. This metric helps to compare technologies with different up-front and ongoing costs. On this measure, the unit cost of new solar and wind projects was lower than building new fossil fuel plants in 91% of utility-scale installations in 2024.

However, pundits criticise this measure because it does not reflect the interconnected costs of the whole system. Renewable energy is not always available when customers want to use electricity so alternative power sources are needed when renewable energy isn’t generating. This can raise the price of coal and gas power if operators seek to recover more of their fixed costs in the hours of the day when they are required. Turning on and off to match demand increases fatigue in coal plants, raising maintenance costs. Transmission and distribution system costs can also go up from renewable energy installations, partly from managing instability in the system, and more sites requiring grid connections in areas that may not be near demand centres.

Thanks to a sharp drop in battery costs, availability critiques are becoming outdated. Ember reckons that “dispatchable solar” is now competitive with fossil fuel generation. Based on data from recent battery projects (outside of the US and China), lower capital costs and improvements in operating efficiency have reduced the cost of storing power to be used when it’s needed. Using another levelised calculation for the cost of storage (LCOS), Ember estimates each stored unit costs $65 per megawatt-hour. In a stylised example, if 50% of solar generation is shifted to non-sunny hours, this adds $33 per megawatt-hour to the average cost of all electricity from that facility [2]. With global average solar prices at ~$43 per megawatt-hour, a solar and storage solution looks competitive with coal and gas at $73 and $85 per megawatt-hour respectively.

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Ember stresses that this does not mean solar and batteries offer fully “baseload” power, i.e. reliable, 24/7 availability. But is this the right goal?

Electricity demand is not flat throughout the day, and coal isn’t used around the clock. The average utilisation of coal plants globally is just 55% as of 2024, calculated using Ember data. Even in China, the world’s poster child for coal power, average utilisation was ~57%, with variability depending on the season [3]. Utilisation could decline dramatically with the rise of renewables and Centre for Research on Energy and Clean Air researchers anticipate coal’s role could shift to back-up generation with the right policies in place.

Baseload generators alone are no guarantee of grid reliability. In Australia, for a 6-month period this year, analysed by Reliability Watch, coal power plants were down 22% of the time. Two thirds of that downtime was unplanned. In West Virginia, a coal-heavy grid was disrupted by a deadly hurricane in the week before I visited, leaving 92,000 customers without electricity. Whether coal or clean, utility-scale generation can’t provide electricity when the network is down. A grid that incorporated interconnected, distributed infrastructure like electric vehicles (EVs) or batteries would offer back-up generation in such situations and can be used or monetised when they are not needed. Instead, some people were without power for a week or more.

Flexible technologies also make baseload less relevant. Some power demand can increase or decrease according to the supply available to the system. Something as simple as controlling when hot water heating systems turn on could unleash 22 gigawatts of flexible capacity in Australia while reducing energy bills. Electric Vehicles (EVs) can be charged whenever electricity is cheapest without affecting the customer experience and eventually could provide hundreds of gigawatt-hours of distributed back-up storage to the grid. Illustratively, with EV market penetration at just 5% of cars, British EVs contain enough batteries to power the equivalent of the UK’s electricity demand for a couple of hours [4].

Even so, there is still requirement for back-up power when renewable energy cannot deliver. Getting close to 100% availability requires over-sizing installations to accommodate extreme weather events, reducing the cost advantage of renewable energy. Coal and gas power are perceived as the last backstops for delivering reliable capacity, able to run at 95 to 100% load for as long as they have access to fuel. These could be kept as back-up only systems, only turning on when absolutely needed and thus saving on carbon emissions, if they can be compensated for their reliability value independently from energy delivery.

A landmark renewable energy project in the Democratic Republic of Congo could prove that renewable energy can deliver back-up power too, at 95% uptime and saving money compared to fossil fuel solutions. CrossBoundary’s first-of-its-kind solar and storage project, serving the Kamoa-Kakula copper mine, plans to deliver 30 megawatts of dispatchable power with a 95% availability guarantee. This is intended to displace more expensive diesel back-up power, a necessary cost of doing business in a country with a notoriously unreliable grid.

There’s one catch: it’s astonishingly large.

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This project illustrates the trade-off of oversizing systems for extreme weather. CrossBoundary will install 233 megawatts of solar power and 532 Megawatt-hours of batteries across 150 hectares of land. Peak generation capacity is 7.8 times the expected load and batteries store up to 17.5 hours of energy at the contracted output.

These numbers aren’t so big after considering the availability of solar energy. DRC’s average daily practical potential is 4.3 megawatt-hours per megawatt on average, which means that the facility can generate just shy of 1,000 megawatt-hours per day. Spread across 24 hours, this would be around 41 megawatts. This back-of-the-envelope calculation makes guaranteeing 30 megawatts at 95% uptime seem reasonable, especially after accounting for system losses and seasonal variation [5].

Solar and batteries might be cost-effective compared to diesel gensets as back-up power, but can they work on a large national grid? India, the world’s second largest coal consumer, now has solar plus storage projects contracting in round-the-clock auctions at competitive prices. UC Berkeley researchers found that based on the cost of storage at these auctions, solar and storage could deliver 95% availability more cheaply than building new coal or honouring some states’ existing industrial tariffs, at less than 6 rupees per kilowatt-hour (~$66 per megawatt-hour). This is an underrated achievement, considering that India is still powering ahead with new coal facilities.

Transitioning to a low carbon energy system still has technical challenges. Relying on any one energy source is a risk, especially as weather events are correlated across facilities. A diversified system with redundancy is a more resilient one. Coal and gas could be reframed as a backstop energy provider instead of the default. There may be times of the day when fossil fuels are always on, for example 6 to 8am before sunrise and after batteries have run out, but this would still represent a dramatic shift in carbon emissions. This might require alternative market designs that reward reliability, like capacity markets, rather than just paying generators for the energy they supply.

The goalposts will inevitably keep shifting for renewables while the coal and gas industries fight to stay in business. Land availability is a potential constraint, which could be alleviated by re-purposing brownfield land and co-locating solar panels with agricultural and other uses. Protecting local jobs and reducing import dependence are worthy goals, but governments should make it clear that this is a trade-off that could increase the cost of electricity. Arguments against renewables would be altogether less salient if more countries incorporated carbon prices and health impacts into the cost of energy.

As for what kind of energy I would trust for my mother’s life support, I think our grids should have a diverse mix that balances cost and sustainability. Hospitals and other essential infrastructure should and do have their own back-up generation so that resiliency isn’t just the responsibility of the grid. Storage is now a cost-effective complement to cheap renewable power, even before adding carbon prices. Diversity of supply, back-up fossil fuel generation, flexible loads, and distributed technology can all be options to manage extreme conditions and lower system costs. As solar and batteries get cheaper and more reliable, the goalposts against them will continue to shift. Soon there won’t be much field left for coal to play on.

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[1] Though on the specific example, hospitals and other critical infrastructure also typically use diesel generators in the case of grid blackouts, so the reliability of the grid is less of an issue.

[2] Or, cheap solar in the day-time and more expensive power at night-time.

[3] This is based on author’s calculations of monthly Ember data for coal electricity production and average coal capacity over each month. May 2024 had lowest utilisation at 49% while August had the highest at 66%.

[4] 1.75 million fully electric cars on the road as of November 2025, with at 20 to 60 kWh battery storage is a potential total storage capacity of 35 to 105 GWh. With peak demand of 47 GW in the UK, EVs could theoretically provide power for up to a couple of hours. In practice it is more complicated – these figures are just to illustrate scale.

[5] According to the Global Solar Atlas, the lowest month of the year has ~9% practical daily potential than the annual average. The 10^th percentile is ~6.5% lower than the average and the minimum long-term daily potential is ~20% lower than the average.

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The Times, a conservative-leaning newspaper, splashed its front page with a claim that “Scrapping [the UK’s] net zero deadline could save households £500 a year.”^[i] Carbon Brief, a pro-environment media platform, titled their coverage with [the] “net-zero scenario is [the] ‘cheapest option’ for [the] UK, says [the] energy system operator”. These two publications have more in common than just avoiding “the” in their headlines. They are both misleading.

These and many other articles are referring to NESO’s analysis on Future Energy Scenarios (FES). NESO model four scenarios of energy costs between now and 2050. Most articles are comparing two scenarios: “Holistic Transition”, i.e. net zero or 100% emissions reduction by 2050, and “Falling Behind”, i.e. 50% emissions reduction between now and 2050. The first scenario is closest to the Labour government’s current energy policy. The second scenario is not “net zero” but still represents a large decarbonisation effort. This isn’t necessarily the policy that best represents anti-net zero political parties, but it’s the least ambitious of the scenarios included in NESO’s study.

In all scenarios, energy costs go up in the short term and down in the long term. The Holistic Transition scenario starts at £299 billion per year, around 10% of GDP. Costs peak at £354 billion before falling to £222 billion by 2050, or 5 to 6% of GDP. Falling Behind is cheaper than Holistic Transition in every year until 2046.

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Let’s revisit The Times’ claim of saving households money by scrapping the deadline for net zero. Although NESO caution against comparing scenarios because they contain assumptions unrelated to climate, NESO make it easy for the media to quote this anyway by presenting the cost difference between the Holistic Transition and Falling Behind scenarios. The Times are broadly right that hitting net zero by 2050 costs more than delaying action. The scenario which halves energy emissions is £14 billion cheaper per year on average between 2025 to 2050 than eliminating carbon emissions entirely. However, these savings would be unlikely to accrue to households alone. Businesses and the government share in energy costs too.

So why does Carbon Brief claim that NESO says that reaching net zero earlier is cheaper? Unlike the Times, Carbon Brief considers the implied cost of carbon emissions to be important, even if consumers wouldn’t necessarily see those costs on an energy bill or pay for them in cash. The Treasury values carbon emissions based on the marginal abatement cost of carbon to meet the government’s nationwide emissions targets. If these costs are included, the Holistic Transition scenario generates net benefits of £36 billion per year versus Falling Behind because it reduces carbon emissions.

This certainly makes it seem like the Times gets closer to the truth: that if NESO’s costings are correct, households and businesses will pay more for energy if the government works towards net zero by 2050 versus less ambitious targets.

This, however, ignores some important details. NESO changes some assumptions by scenario that aren’t related to climate, like data centre demand. £5 billion of the Holistic Transition costs in 2050 are due to estimating more than double the data centre demand than in the Falling Behind scenario. Put differently, this assumption suggests that delaying net zero would also diminish the roll-out of data centres, which the government considers a key pillar of economic growth.

The report also doesn’t consider the impact of achieving net zero on health, jobs, trade, and energy security. Cleaner air reduces deaths from pollution. Installing new energy technology generates significant jobs even if manufacturing is done elsewhere. European carbon border adjustments would affect British exports significantly if the UK stalls decarbonisation. Renewable energy investment reduces dependence on imported gas.

What’s striking is how confusing all this energy cost reporting is for voters. Reports that net zero is cheaper are hard to believe when monthly energy bills keep going up, even if they accurately reflect the non-cash cost of climate change. If the government can’t deliver real cost savings, they need to do a better job of selling the dream. Energy costs might go down in the long run, but the government doesn’t have a long run before they face voters at the next election.

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[i] A previous version of the headline stated “net zero plan to cost households £500 a year”

Car-sharing delivers on the city’s environmental and cost-of-living goals. Zipcars have lower carbon emissions than the average London car. One third of its fleet is electric against a city-wide average of 6.8% [2]. Car sharing fills a transit gap between public transport and ride-hailing, like moving house, one-off trips to visit relatives, or transporting bulky goods for work. This enables residents who rarely use cars to give them up entirely, saving on annual registration and insurance fees.

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The bigger, under-rated prize is space. London has 2.6 million cars of which around 43% are parked on the street [3]. In 2017, parking took up between 5% and 18% of all road space [4]. By another calculation, street parking uses the equivalent of 1,300 hectares of public land, or nine Hyde Parks [5]. Recent analysis by Collaborative Mobility UK, a charity, suggests that each car-share in London pushes at least 16 privately owned cars off the road [6]. In 2022, they calculated that with a fleet of 21,000 shared cars, up to 300,000 cars could come off London’s streets after taking into account trip frequency, driver age, and accessibility. This implies each shared car could save over 150 m² in parking space^[7], roughly equivalent to the internal area of three new 1-bedroom flats. In addition to decreasing congestion on the roads, councils could use this extra room to expand pavements and bike lanes, provide more parking spots for dockless e-bikes or even create space for new homes and businesses.

Despite all these public benefits, privately owned Zipcar is struggling with costs. It posted a loss of ~£6 million in 2024, driven by a mix of falling revenues and rising expenses [8]. They also wrote off a tax benefit of an additional £6 million, perhaps foreshadowing their exit from the market [9]. Some of this is because of Zipcar’s business model. It includes fuel costs in the price, which have been rising, especially for electricity. Public charging costs are notoriously more expensive than charging at home or in bulk as a business, and Zipcar reimburses them. Its convenient one-way flex journeys also raise costs as staff manage re-charging. Customers can leave cars on empty, making them less appealing to the next driver, possibly reducing utilisation.

Local government isn’t helping on costs, either. Zipcar negotiates parking with each of London’s 32 boroughs, adding complexity. Rather than embrace Zipcar’s potential benefits, councils seem to fear missing out on revenue. They have ratcheted up parking fees on car clubs, especially on the flexible model that customers like. Councils charge EVs less than other cars to park, but while resident permits range from £15 to £150 per year, EVs in car clubs are often hit with fees that are six to 80 times higher, up to £1,600 for flexible parking. Haringey council even conducted a benchmarking study earlier this year to make sure they were charging as much as other councils, almost doubling flex parking and more than tripling fixed-bay costs.

Changes to city-wide and national policy are set to increase Zipcar’s costs further. EVs are getting hit by London’s congestion charge from 2026 if trips end outside the congestion zone, along with higher registration costs starting this year and new mileage taxes starting in 2028.

Against this backdrop, Zipcar’s departure is no shock at all. After letting policy costs proliferate, the surprise will be whether the Greater London Authority (GLA) does anything about it.

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One option is to let Zipcar fail. This would disappoint thousands of users and potentially lead to more congestion if some of them buy cars again. It seems unlikely that a smaller player would scoop Zipcar up without any resolution of its underlying problems. This could potentially spell the end of car clubs as a viable business model in London, but maybe the GLA hope this would increase the focus on bikes and public transport.

Instead, London could explore “municipalisation”, treating car sharing as an infrastructure-like asset and bringing it into public ownership. Car-sharing benefits from economies of scale on charging and availability. It also provides public goods in addition to the service itself, reducing road congestion and carbon emissions, and freeing space for other uses. Municipalisation goes beyond subsidies or tax breaks, which could be offered to Zipcar without changing ownership. It re-imagines car sharing as part of the public transport system.

If car clubs became part of Transport for London’s offering, even as a standalone entity, it creates several distinct advantages versus private ownership. There could be better data sharing to inform planning across the system and connectivity with other services. TfL could use its land for parking and charging, and benefit from any bulk purchasing agreements for energy. TfL issues debt at just 5.75%, beating Avis’s intercompany interest rate of 7.1%. It could pass that cost of capital saving onto customers.

TfL might also have more leverage to negotiate a framework agreement for parking fees across all London boroughs. Councils would no longer feel like they are losing out on revenue to a private company, instead supporting a government body that they lobby for investment in roads, buses, and rail upgrades. TfL could tie the support of car clubs to increased investment in transport infrastructure as more space becomes available from fewer cars parked on the road.

This strategy carries risks, but they could be worth taking. One is finding the money for municipalisation. Even in a firesale, Zipcar’s vehicles could fetch upwards of £30 million [10]. This would potentially require outside financing partners but this is not an impossible sum to raise considering TfL’s debt is over £15 billion. Another issue is whether there is really as much consumer demand for car sharing as media reports suggest, given Zipcar’s recent decline in revenues. The number of shared cars in London apparently shrank by 12% between 2021 to 2024 [11]. Growing the fleet and coordinating better with the rest of the transport network could address this, as customers would see car sharing as a permanent option they can rely on. A third problem is whether a small service like car sharing is worth the hassle of bringing it into public ownership. A concession or not-for-profit model could also work, provided London fixes the problems first.

Zipcar’s demise is a policy choice. London has let a patchwork system of charges and rules get in the way of progress on reducing car ownership and improving land use. TfL has so far stalled on developing a pan-London plan for car clubs, according to the London Assembly. If London is serious about cutting congestion, freeing up land, and making infrequent driving cheaper, then Zipcar’s exit is the moment to prove it.

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[1] 3,000 cars in Zipcar fleet out of 2.6 million cars in London

[2] June 2024 data, Transport for London

[3] Travel in London 2017 data, the latest available that provides car parking details by borough

[4] As above

[5] 43% x 2.6 million cars x 11.52m² = 1,305 Ha, divided by 140 Ha area of Hyde Park. Previous estimates of 10 Hyde Parks by Centre for London were likely based on slightly higher car numbers and rounded space requirements from 11.52m² (2.4m x 4.8m) up to 12m².

[6] 31 cars per car-share if including avoided purchases of new cars.

[7] 12 m² parking space and 300,000 fewer cars divided by 21,000 car shares = net 13.3 fewer cars per share-car after taking into account the share-car parking space. 13.3 x 12 = ~150 m²

[8] Revenues declining by £4.1 million and costs rising by £1.6 million.

[9] This tax write-off happens because they accrued some tax deductions in prior years that they no longer believe they can offset against future profits.

[10] Used cars sold for £17,000 on average in October 2025, or £23,500 for EVs. With 3,000 cars and a 50% discount, this would be around £30 million and covers Zipcar’s intercompany loan and outstanding leases.

[11] 3,100 in 2024 vs 3,500 in 2021

EVs were initially supported to reduce the environmental impact of driving, even if they were more expensive. As the UK’s energy system became increasingly decarbonised, transport became the dominant source of UK carbon emissions. To meet climate goals, the government supported EV adoption through incentives (e.g. grants for cars and chargers, registration fee discounts, tax breaks on company cars, funds to build charging infrastructure) and deterrents (e.g. congestion charges, phase-out dates, penalties for missing EV sales targets). This combination of factors, along with innovation in places like China, has helped to grow fully electric cars to 22% of new car sales and 5% of total cars on the road as of October 2025[1]. Including plug-in hybrids, these figures are 33% and 8% respectively.

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Although EVs are more expensive than petrol cars on average, many EV models are now cost-competitive with new petrol cars. Charging EVs is also cheaper than running a petrol car, even with the UK’s high consumer electricity prices. The government advises that the fuel for petrol cars costs 12p to 14p per mile on average. EVs cost just 7p to 8p per mile if charged at home, or as low as 2p per mile[2] if customers sign up to special EV tariffs.

These compelling economics raise the question of how much further to subsidise EVs. They are still far from being the dominant consumer choice, so continuing to subsidise them is one way to motivate sales. The government introduced a new grant earlier this year of up to £3,750 per vehicle with a £650 million budget allocation. This was effective at driving demand, with September recording the highest EV registrations in a single month[3].

Yet subsidising EVs with cash grants sends the signal that they are not the cost-competitive option and does little to address other barriers to adoption. It interferes with re-sale value for EVs, affecting those who have already purchased them. It also creates volatility in the financing market as accurate residual value estimates are a key component of offering a competitive car loan. The government’s latest EV subsidy was also protectionist, excluding popular models from China on environmental grounds even though they would still save carbon emissions from petrol because of the UK’s low-emissions electricity grid. This subsidy could instead have been directed to other investments, like public charging, so that drivers are not charged excessively if they are unable to power up their car at home.

Meanwhile the government is rolling back some other EV incentives like discounted registration and exemptions from congestion charges. EV owners will now be expected to pay at least £195 of road tax per annum after their initial registration year. From next year, EVs will pay Central London’s £18 per day congestion charge along with everyone else[4].

The government may go even further in the budget later this month with a proposal to introduce a 3p-per-mile charge on EVs. This is to help to rebalance falling revenue from fuel taxes collected from petrol sales, which have decreased by 11% since COVID. This has caused outcry from the EV industry because it could disincentivise EV uptake at a time when the sector is nascent.

At the heart of this debate are two misunderstandings on the purpose of vehicle taxes: what these taxes actually fund and what is actually being taxed.

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Fuel duty and Vehicle Excise Duty (often called “road tax”) contribute around 2.7% of government revenue, at £24 billion and £9 billion respectively for 2025/26 or £1,170 per household. This tax is perceived as funding road use. In reality, Britain only spent £13 billion on roads in 2024/25. Churchill once called road tax the “raid fund” because it was so often used to support spending in other parts of the economy.

The rise of EVs has eroded a portion of this revenue base from road tax exemptions and no fuel charges. The call for EV drivers to pay their fair share for using the road is important not only for funding infrastructure but for the general government budget. But fewer fuel-consuming vehicles alone cannot fully explain the drop in tax receipts.

People are also driving less. Average mileage for petrol cars is 6,200 miles per year, down 3% since COVID and 25% over the past 20 years. Diesel mileage declines are even more dramatic at 13% and 38% respectively.

It’s unclear why British society believes drivers should disproportionately shoulder taxes. What is clear is that fewer vehicles paying tax, and less mileage per vehicle is contributing to a widening budget gap that drivers once reliably filled.

The perception of the UK’s fuel duty has been further complicated by its confusion with carbon pricing. This duty has supported general government revenue for decades yet exempting EVs from this payment has been perceived as a reward for going green. When polled on introducing a new mileage tax, 28% of survey respondents felt EV drivers should pay less because of their lower emissions. The UK’s current fuel duty, which is £0.5295 per litre, translates to around 5 to 9p per mile. The 3p-per-mile charge to EVs is cheaper than the fuel duty. If attributing the per-mile difference to a carbon price, this would imply a price of between £76 to £135 per tonne[5]. This is significantly higher than the current UK Emissions Trading Scheme price (over £50 per tonne), which only applies to electricity generation and some air transport.

The EV mileage proposal creates a more complicated system where EVs pay for road use differently from other drivers. It also does not set an explicit price for carbon emissions the way other sectors have established, which limits the price signals available to innovators to drive down costs from emissions savings. Given EVs are becoming cost effective and could erode an important tax base, it seems fair to re-balance taxes on their use. What seems strange is to do so at the same time as offering cash subsidies for purchases.

The government could use this opportunity to simplify, rather than complicate, how it taxes driving.

The current vehicle tax system is a mix of emissions reduction and income generation. If what the government care about is reducing carbon emissions, then it should price them consistently and explicitly. This could mean incorporating diesel and petrol consumption into the UK’s Emissions Trading Scheme. More funds could be committed to address other barriers to EV adoption, like the availability of affordable public charging and ensuring that chargepoints are kept in good repair. If the government also cares about fair revenue-raising, the government could replace fuel duties and VED with a technology-neutral system of fixed and usage-based charges for all vehicles.

Inconsistent EV measures are an illustration of Britain’s complicated tax system. Governments are understandably trying to achieve many objectives but taking from one hand while giving with the other causes confusion. We should stop pretending that fuel and vehicle excise duties are to fund roads or tackle climate change when they are effectively general taxes. Incorporating a carbon price while scrapping hand-outs for an increasingly cost-competitive technology would send a clear signal on how the government sees EVs contributing to emissions reduction. It also helps Reeves meet her budget goals, as does re-balancing motoring taxes so that all drivers pay. If the government is going for fairness with the rest of its budget, it should pick that lane on EVs too.

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[1] Percent of new sales figures are year-to-date 2025.

[2] EV rates are 70% of retail tariffs. Using the government’s EV efficiency figure of 3.59 miles per kWh, EV charging on 7p/kWh tariffs costs ~2p/mile.

[3] Bumper sales are typically recorded in March and September number plates are updated to indicate the age of the vehicle.

[4] Some discounts will remain, e.g. 90% off for residents with EVs, 25% discount for EVs registered for Auto Pay.

[5] The difference between the EV per mile tax and the petrol car fuel duty tax, divided by emissions per mile. Petrol emissions are 265g per mile on average.

British right-wing political party Reform’s call to bring back coal mining initially seems absurd. British coal jobs peaked more than a century ago as mines were exhausted, machines replaced labour, and cheaper fuels emerged. Coal mining has represented less than 0.1% of the UK workforce since 1993. Yet as Labour, the governing party, mourns the loss of Caerphilly in the heart of the South Wales coalfields and develops its Green Jobs plans, it could learn something from Reform’s ill-conceived proposal. The appeal isn’t about coal jobs themselves, but coal culture.

Coal culture is shared across countries as different as China, the US, the UK and India. At any of their coal museums, heroic workers are depicted powering their nations and fighting for their rights. Workers are shown as a driving force for their country’s union movements, protesting against their coal bosses for better work conditions and pay.

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Conditions were tough, with accidental death and health problems common among miners and nearby residents. Regardless, the extended members of the community are shown supporting the miners, even recording the cuisine wives prepared for miners’ lunchboxes. Every museum eventually tells the same story of communities in decline, driven by rising mechanisation. The UK’s story is unusual in its speed and finality. Elsewhere, production rose even as the workforce shrank.

Coal is a harder industrial transition than most. Coal communities typically formed around the geological resource, with mining driving almost all the jobs in that area. Migration supported the growth of these communities, making them some of the more diverse regions of Britain. Everyone worked for the same employer – the colliery – or else provided services to miners and their families, instilling a strong sense of community. In coal regions, a large employer like a manufacturing facility could sometimes absorb unemployed workers as mines closed. In many cases, workers were redistributed across a multitude of sectors and small businesses and often needed to move if they wanted to work. As of 2022, almost one in seven employees in former coalfields commute out of the area for work, according to the Coalfields Regeneration Trust.

Labour’s 400,000 Green Jobs plan is ambitious, but place-based transitions are hard. In cities, job losses are easier to absorb because there is enough overlap in infrastructure and skills with other sectors. Once jobs go away in single-employer areas, communities gradually hollow out. Decline in sport, religious practices and public services compound this loss. Few jobs outside of the military can now offer the same culture of heroism and camaraderie as working down the mines. Green jobs alone cannot fill this void.

This opening has been exploited by right-wing politics, even while coal was once a symbol of the Labour movement. The right has turned net zero into a scapegoat for decades of industrial decline even when technological progress played a role long before the climate movement gained traction. What Reform gets right about coal is their attention to bringing back a profession defined by heroism, close-knit communities, and opportunities for work that don’t require a university degree.

Labour has the chance to combine its jobs agenda with a renewal of professional and civic pride. Labour’s Green Jobs already outnumber any employment that coal could conceivably provide, and energy workers shouldn’t need to risk their lives to feel valued and important to the economy. The Green Jobs plan rightly focuses on training, but it could go further to bring back community spirit and purpose. Skills programs could be paired with group projects that support cleantech upgrades for youth clubs, sports facilities, and religious and public buildings. Every new solar or wind project could be tied to investment in community infrastructure, like a tech or apprenticeship hub or reviving the high street. Linking green industry to local, visible renewal could make climate policy feel like a national service in addition to a job creator.

Coal once gave people pride in powering the nation. Labour’s task is to make the clean energy revolution feel just as heroic, not just because it makes our air cleaner and our bills cheaper but because it restores dignity, skill, and community in the places that need it most.

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Labour has four years left to deliver on its ambition to “make Britain a clean energy superpower.” There is no time to waste. The Reform and Conservative parties have identified net-zero as the villain behind the high cost of living. Voters will be more confident in Labour’s clean energy agenda if it lowers bills and creates jobs.

Nuclear features heavily in the government’s budget, and could create 10,000 jobs during construction, but it cannot deliver lower bills in the next four years. Existing solutions can. As such, the government should rebalance its support to more short-term options to capture this opportunity.

The UK’s high energy prices were a major 2024 election issue. Energy prices spiked after the Russian invasion of Ukraine, increasing domestic and industrial power prices by 80 per cent and 90 per cent respectively from 2021 to 2023. British industrial energy prices remain the highest in the G7. Even before the war, analysts identified gas as the major culprit of rising energy costs, and renewable energy as the antidote.

Labour committed to change, initially planning £28bn of investment in the green economy during their term. By February 2024, this pledge was slashed to £15bn, with just over half allocated specifically to energy.

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The government’s flagship energy policy was to create Great British (GB) Energy, an £8.3bn vehicle to invest in clean energy projects. Its design and mandate before the election was vague, though it hoped to fund projects at a lower capital cost than the private sector, generate profits for taxpayers, and stimulate local jobs. It was unclear whether it could actually reduce costs because it did not deal with key bottlenecks like planning, risked crowding out private investment in traditional renewable technologies, and did not address major components of energy bills like transmission, distribution, supply, taxes, and subsidies.

One year on, GB Energy has not yet gained momentum. It has already lost 30 per cent of its funding since its launch, with £2.5bn reallocated to the nuclear industry. It was styled as a state-owned investor, but its first transaction was a £110m grant program to buy solar panels. This generates savings for schools and the NHS but does not showcase GB Energy’s deal-making capabilities. GB Energy’s focus on smaller community projects might make its work visible at a local level, but it is unlikely to meaningfully impact bills. Meanwhile, GB Energy’s mandate to invest in energy supply chains and nascent technologies could benefit local manufacturing and industry without offering any short- or medium-term savings to consumers.

In parallel, the government has made a big bet on nuclear: more than seven times as much as the commitment to GB Energy. As of July 2025, the government has pledged over £45bn to nuclear in the form of grants, equity, and debt. This includes a tender for the first small modular reactors (SMRs) in the UK (£2.5bn, reallocated from GB Energy), the Sizewell C power plant (£40.35bn) and nuclear fusion research (£2.5bn).

While nuclear may be necessary to diversify the UK’s energy mix and improve energy security, it cannot deliver cost savings in time for the next election. Sizewell C will bring an additional 3.2 gigawatts of capacity online, enough to power six million homes, but not until the mid 2030s at the earliest. It will add £12 per year to every energy bill until construction is finished, and its eventual cost per unit is not yet known. For comparison, the government’s investment could fund at least twenty-four times as much solar capacity, and almost ten times as much onshore wind, with far shorter construction times.

Nuclear fusion, similarly, has long been the holy grail of unlimited clean energy, but is not expected to lead to a viable project within the next 25 years. SMRs are touted as the cheaper, quicker alternative to large scale projects, yet so far only a couple of commercial projects have been commissioned. The government is unlikely to deliver any nuclear projects, let alone their cost savings, before the next election.

If the government wants to win support for Britain’s clean energy future, it will need to make more near-term bets. Solar, wind, and battery projects in the UK have shorter development and construction times than nuclear, as low as two years for solar and batteries and four years for onshore wind. The private sector is willing to fund these projects, but grid connections have historically delayed their progress by five years on average. If these projects could be guaranteed grid connections, they could start delivering cheaper energy. The government needs to continue progressing on less visible reforms to grid planning and ensure grid upgrades are funded from private and public sources.

Reusing undervalued regional assets like shuttered power plants could partially help to reduce the pressure on grid connections. The land from former coal plants could be remediated and converted to clean energy, making use of existing infrastructure. Some plants have already been converted from coal to gas, others to biofuels, but conversion to cheaper renewable energy sources has lagged. The most famous conversion, Drax, will cost the government over £10bn in subsidies from 2015 to 2026.

The Aberthaw Power Plant could be a blueprint for such redevelopments. The Cardiff Capital Region is funding the demolition and remediation of this former coal plant and taking advantage of its strategic location to create a sustainability hub. Long-term bets on tidal power offshore from the site can be complemented with lower-risk investments in batteries and solar that could generate jobs and income for the community within just a few years. The site could also host other infrastructure like data centres, heat networks, and EV charging. The UK government could help to kickstart development at similar sites.

Another novel approach is to use software and hardware in homes and businesses to optimise energy consumption. A government mandate has ensured 66 per cent of UK’s electricity and gas meters are ‘smart’, yet the benefits of this technology have not yet been realised. Smart meters can save people money by helping them to shift consumption to the cheapest times of day, but most electricity plans in the UK do not offer a dynamic pricing option. Octopus Energy, for example, offers lower electric vehicle (EV) tariffs for charging at the cheapest times of day. It has also piloted a product which pays customers to turn off their EV chargers at times when the electricity grid is constrained. These innovations could be extended beyond EVs; in the future, we could even see two-way electricity flows, enabling EVs and home batteries to charge up during periods of high renewable electricity production and then supply power back to the grid when needed.. The government could play a role in supporting pilot programs and their scale-up, or even mandating that providers offer flexible pricing options.

Wind, solar, and batteries are less expensive and faster to deploy than nuclear power. Approaches like reusing existing assets and complementing investments with optimisation software could also give clean power an extra boost to deliver savings in the next few years. Labour cannot afford to wait until the mid-2030s to show progress on bringing down energy bills. Placing too much faith, and funding, in nuclear energy and other long-term technology investments risks costing Labour the next election.

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