| To tackle the industrial energy crises, there are three key reforms that would address uncompetitively high electricity prices: system marginal cost pricing for industry; reform of the wholesale market, including Equivalent Firm Power; and setting the carbon price inversely to the oil and gas prices. More general reforms include: investing in gas storage; creating a strategic gas generation reserve; and entering into long-term gas contracts as part of licensing the North Sea. |
The UK was already in trouble over energy and especially electricity prices before the Iran war started. It (and Germany) is at the top of the global leaderboard for industrial energy costs. The latest Iranian war cost shock, and the associated price spikes, finds the UK no better prepared than it was back in 2022 when the Russian tanks crossed the Ukrainian border. In both cases, the UK imported the least gas from Russia and the Gulf respectively, but was amongst the hardest hit.
As ever, it is argued that it is different this time (in the case of this Iran war), but it is also in many respects the same. The difference this time is that the US is now the primary source of liquefied natural gas (LNG) for Europe and it is the US which keeps Europe afloat. Gas comes from elsewhere too – notably Norway – but what matters are the marginal costs, and these are currently set by the highest bidders for US LNG cargoes, whose terms are typically “free-on-board” and not necessarily destination-specific.
This new dependency on the US reflects a remarkably rapid change in global energy markets. Ten years ago there were virtually no LNG exports from the US. Twenty years ago there was very little US fracked shale gas at all. The Sabine Pass LNG export facility only started exporting in 2016.
The global picture on oil and gas is dramatically different from the First and Second Gulf Wars. The US is now effectively oil and gas independent of the Gulf. It is by far the largest oil producer in the world, and it is already the world’s largest supplier of LNG gas exports. It joins Russia as a primary beneficiary of rising oil and gas prices. China, on the other hand, is dependent on the Gulf, taking nearly 40% of all the oil going through the Strait of Hormuz. India is next and then the rest of the Southeast Asian countries, notably Japan, South Korea and Taiwan. These are the immediate losers. Of these, China and India have lots of coal. China burns well over 50% of the world’s coal. They can ramp these up, but this doesn’t make up for the multiple uses of oil and gas.
One delusion which needs to be dispelled urgently is the idea that the UK and Europe are getting out of oil and gas (and coal) and hence that the current problems are merely transitionary ones. European fossil-fuel energy is still around 80% of its total energy supplies, and over 70% of the UK’s. Decarbonisation is therefore a huge undertaking – it requires replacing almost all of this oil, gas and coal. The European approach has been to rapidly increase intermittent, low-density and geographically dispersed renewables electricity production, and to exit much of its energy-intensive industries.
For the UK, the latest shock is added to its already high energy costs and especially electricity. It makes matters even worse, from what was already an unsustainable position. Unless the underlying high costs of electricity in particular are addressed, the UK’s now rapid deindustrialisation is going to accelerate. Perhaps more importantly, the UK will remain uncompetitive when it comes to the new energy-intensive industries of the future. None is flocking to the UK to get access to its “clean” offshore wind: the UK is no “clean energy superpower”.
What, then, should the UK and Europe do about energy, and specifically electricity costs, and who pays them? Contrary to the usual claims, and what has become the conventional wisdom, the addition of lots of solar and wind generation has not resulted in lower costs of electricity. The place to start is with the question: why are electricity costs so high when the share of renewables has gone up a lot?
The system costs of electricity are rising
The first reason why the costs are so high is that, as more and more intermittent, low-energy-density and dispersed renewables are added, the system costs rise. The amount of capacity needed to meet peak demand goes up, the networks have to be expanded, and lots of storage, including batteries, has to be added. Whilst the marginal cost of wind and solar is close to zero, the system costs are not.
In the UK, for example, with a peak demand at around 45GW, there is now 120GW of capacity where 60GW was once sufficient. In other words, the capacity on the system has to double for the same equivalent firm-power output. This doubling applies to the grid as well, and all the storage is extra. Finally, the costs of the back-up, notably gas, go up because gas power stations are rendered intermittent too as wind swings between exceeding the total demand and contributing very little.
The costs of this additional capacity and extra grid and extra storage are baked into the future costs of the UK electricity supply for years to come, depending on the guaranteed prices that renewables are contracted for. These renewables rarely, if ever, pay for the system costs they cause as a result of their intermittency, and hence the costs of the contracted renewables do not represent anything like the consequences of adding this type of generation onto the system. Worse, in the UK, the renewables are paid for generating electricity whether or not the electricity is needed, and they are largely located independent of the development of the grid.
Renewables need gas
The second reason is that, contrary to the claim that by building renewables we are getting out of gas, the opposite is true in terms of dependency and in terms of the price of gas. Gas remains essential for an electricity system that is building larger shares of intermittent renewables. Why? Because these sources are intermittent, something else has to ensure security of supply, and firm power is what is required. Batteries won’t bridge the gap for a very long time to come. Gas will and does. The more intermittent renewables that are added to the system, the more important this back-up becomes.
Now the expensive bit. The gas capacity required is not operating as it would once have done as baseload. As the amount of renewables increases, gas generators operate less and less of the time. The National Electricity System Operator (NESO) estimates that if the electricity system is to reach net zero by 2030, some 35GW of gas capacity will be needed to ensure security of supply, but will operate perhaps as little as 4% of the time. That is a huge largely deadweight cost looming over the costs of the renewables contracts for differences (CfDs) and the extra grid costs and the extra battery and storage costs.
Deliberating getting out of home-grown gas
The third reason for higher costs is that, as the North Sea gas is being deliberately squeezed, the marginal gas is increasingly being provided by LNG cargoes, almost all of which come from the US. This cost of gas translates through the wholesale cost of electricity into the price of electricity. It is in effect the system marginal cost. The price of gas, the government says, is determined on international markets by autocrats and dictators.
Perhaps a little history would help the government realise that there is much UK energy policy can do about this. In the “bad old days” of British Gas, all gas produced in the UK’s part of the North Sea had to be landed in the UK, and British Gas was the sole buyer. The gas producers agreed with British Gas long-term contracts – and prices. As we shall see below, since the government controls the offshore licences, there is nothing to prevent it from entering new fixed-price long-term contracts going forward. Given, too, that there are new licences at stake, as we shall see, there is a contractual bargain to be struck here for long-term contracts in exchange for new licences.
Baking in the costs of renewables and nuclear for the long term
The higher cost of electricity is being baked into the CfDs and other support mechanisms for the next decade, and in some cases even further towards 2045. The irony is that, in addition to the exposure to gas and the need for more gas capacity at higher costs, the price paid by industry (and domestic customers) is the locked-in costs of the CfD renewables contracts and the grid costs. This makes the industrial energy pricing issue not only an immediate crisis but one baked into the next decade and more.
From this follows an obvious conclusion: short-term and ad hoc “fixes” will not solve this competitiveness problem. Special deals and tariffs for steel, for example, are but sticking plasters, as is the electricity competitiveness pricing scheme due to kick off in 2027. Both bring only temporary relief, with lots of unintended consequences. The cost and pricing problem is fundamental and it needs fundamental reforms of energy pricing to industry if the UK is to have a future for its existing energy-intensive industries, as well as the new ones.
Three options for addressing high prices
UK (and European) industry cannot stand the cost differential with the US and China (and other competitors) for another decade or so. There is an urgent need to do something now, and to do something that sticks for the next decade or so.
Fortunately, several things need to be done in electricity now. These include:
- charge system marginal cost pricing for industry
- reform the wholesale markets
- set the carbon price inversely to the oil and gas price.
(i) System marginal cost pricing for industry
Though little can be done to reduce the costs of energy in the short term, there is considerable choice as to who should pay. This flexibility is increasing as the system becomes dominated by zero-marginal-cost generation and as the networks are expanded. What this means is that more and more of the costs of electricity are fixed. It is capacity that is the basis of future costs.
The important point about fixed costs is that there can be no competition; there is no scope for switching. As a result, there is a choice as to the allocation of the costs without distorting the what is left of supply competition. Put another way, suppliers are increasingly cost (or tax) collectors.
The old dream of the electricity privatisers – that the industry would become an increasingly competitive one, with suppliers shopping around to find the best merchant prices from generators – has been replaced by a monopsony of government buying through CfDs and regulated asset bases (RABs), and passing on these costs, plus transmission monopoly costs, plus distribution monopoly costs, plus storage costs. Every party wants government-backed contracts. The market is an ever-decreasing residual. This is the legacy of Ed Miliband’s energy market reforms at the end of the first decade of this century. It is a central buyer model.
Thinking of the pricing of electricity as fixed cost collection opens up a host of options, for efficiency and for industrial policy. The efficiency aspect is covered by the Ramsey pricing principle: charge the fixed costs inversely to the demand elasticity. The rationale is the following: everyone should pay their variable costs, and make some contribution to the fixed costs. The more inelastic the demand, the more of the fixed costs should be charged.
The relevance to industrial pricing is immediate. If the industries that are closing as a result of high energy costs could cover their variable costs and make some contribution however small to the system fixed costs, then it is in everyone’s interest that they are charged on the Ramsey basis. Refineries, the steel industry, and fertiliser producers that have closed are no longer paying anything at all towards the fixed cost. That makes us all worse off. The marginal system costs are the costs to the system that the industrial customer causes. The rest of the costs don’t go away because all this industry closes. On the contrary, the remaining customers (notably, domestic consumers) have to bear more of the burden. Closing large industries down increases the costs to the rest of us.
Which system costs are genuinely marginal is a matter of time scale. In the short run, it is the cost of generating the electricity that industry uses, and that price is currently set by the wholesale market. It is the cost of the last (most expensive) power station needed to meet total system demand. This might be wind or solar when these can cover the total market demand, with a marginal cost of zero, or it might be gas or even the DRAX wood pellet power station.
For efficient pricing, the pollution costs must be added to the marginal cost of the fuel. A carbon cost is incurred at the margin, and would not be if the industrial plant stops producing. This is not straightforward, because carbon emissions are location-independent in their impact on climate change, and competitors overseas are not always charged the equivalent amount. Territorial carbon production targets – the basis of the UK’s net zero targets – seriously distort this aspect. Then there is pollution which is not charged at all. DRAX is the obvious example. It produces multiple pollutants, the costs of which are not borne by DRAX.
All the above are short-run marginal costs. In the short run the system is non-marginal. Long-run marginal costs are those that bring change to the nature of the system itself. Place a large data centre in the south east of England, and there will be costs to connect the data centre to the network, and network reinforcements and changes elsewhere in the system. The costs of the connection are called ‘shallow entry costs’; the wider system impacts are ‘deep entry costs’.
There is a case for treating the costs of existing industrial customers on a shallow-entry-cost basis, while treating new demands on the basis of their full system costs. If an industrial plant closes, the connection does not go away. If it is taken up by a new plant, such as a data centre, there is a case for not applying deep entry costs, since the marginal costs of the connection are zero if perfectly re-used. In practice, it is hard to be precise about the wider system marginal costs of new entry, so some rough approximation is necessitated.
(ii) Reform of the wholesale market and Equivalent Firm Power
The wholesale electricity market has been around for a long time, and it has had a very compelling intellectual rationale, and one that can form the basis of pricing. But this rationale only goes so far: it is designed for an electricity market that is driven by the marginal costs of fuel and the electricity generated from the fossil fuels, notably coal and then gas. It is not designed for lots of zero-marginal-cost generation.
As more and more wind and solar (and nuclear) are added to a system based upon a wholesale market, there will be times when the total wind plus solar exceeds total electricity demand. Then the wholesale price falls to zero. This has consequences both for the variable-cost power stations like gas, and for the zero-marginal-cost generators, like wind, solar and nuclear.
When the share of zero-marginal-cost generators is small, and they never cover total demand, they can reap the system marginal wholesale price and their economics depends upon the integral between their total cost (fixed) and the system marginal price. Put simply, as long as there are not too many renewables and nuclear, they get paid. If they also get a subsidised contract as well via the Renewables Obligation Certificates (ROCs) for example, they get paid twice.
Now add lots of renewables and nuclear. In France, nuclear generation often exceeds total demand. Since the cost of turning nuclear power stations on and off is very great, nuclear runs even if the wholesale price is zero. Solar and wind are in effect always on, generating whenever there is wind and sunshine.
How is the scheduling to be organised and how is it going to get paid for? The answers are provided by two mechanisms. The most important is that there is a capacity payment: a payment for just being there is available to generators if and when called upon.
In most electricity systems, there has been an energy charge (related to the system marginal cost) and a capacity charge. The Central Electricity Generation Board’s (CEGB) Bulk Supply Tariff (BST) worked well for the decades after the Second World War and the replacement after privatisation was essentially an updated version where generators bid in prices rather than marginal costs to allow the system operator to schedule the generators onto the system.
In a pure zero-marginal-cost world, there is only a capacity cost, and scheduling has to in effect be administered.
The transition from a wholesale-driven market model of pricing to one based upon largely fixed system cost was what the Review of Electricity Market Arrangements (REMA) was subsequently supposed to address. It was set up following the Cost of Energy Review (2017), in which I proposed the introduction of a form of capacity market, called Equivalent Firm Power (EFP).[1] This matched the needs of the system (and hence the system operator) to ensure sufficient capacity to meet the peak demand (plus a security margin). This is the 45GW and the extra margin taking the total system capacity requirements to, say, 60GW.
It is firm power, because we want the lights to stay on. The question is how that firm power is met. Renewables are intermittent and typically located at the fringes of the networks. They cannot guarantee firm power. A renewables-only system would be unsecure. But renewables do bring some capacity to the party. They just have to be de-rated. All systems de facto de-rate intermittent generation, and hence have to work out EFP. The practical question is whether renewables should be paid as now as if they deliver firm power when most of the time they do not. This is current UK practice, and it is wrong.
EFP received a hostile reception from the renewables lobbyists and from a captured government department. It would have revealed a very significant cost of renewables, which they should, but did not, pay for. It is reflected in the false claim that the costs of renewables are equal to the CfD prices they are paid. (No one could argue that the ROCs reflected their costs, in receiving both the subsidy in the ROC and the wholesale price as well). Renewables are (much) more costly to the system. These system costs are reflected in the need for 120GW capacity to meet the peak (and firm) power demand of 45GW (as well as their shallow and deep entry costs). Under EFP, the renewables could reduce their de-rating in the EFP auctions by bilateral contracts with battery and small-scale gas standby generators. In doing so, they would face the costs of trying to aspire towards the firm power.
The total of the EFP bids necessary to meet the peak demand plus a margin (let’s say 60GW) would make up one component of the total system (fixed) costs. This would then have to be allocated between industry and other customers on the basis of Ramsey pricing. It would be the largest component.
There would be other system fixed costs to add to the total to be allocated. These would include the network costs. Recall that the renewables cause the grid to be expanded by a factor of two to meet peak demand from intermittent, geographically dispersed and low-energy-density wind and solar production. This extra grid is a cost of renewables, and to be able to qualify to get paid in an EFP auction, this extra deep entry cost would have to be added. There would also be the shallow entry costs: the costs of connecting up the wind farm or solar installations.
Revealing the full costs of renewables has two consequences. First, it explains why the costs of electricity in the UK are and are going to be (much) higher for a long time to come. The costs don’t go away by chanting “nine times cheaper”. Someone has to pay. They also reveal the costs of decarbonisation: in effect, one option for making us all pay the costs of the pollution we are causing, independent of the consequences of closing down large energy-intensive industries and importing the emissions instead. This brings up the carbon element and who should pay what towards the costs of decarbonisation.
(iii) Setting the carbon price inversely to the oil and gas prices
There is a very good efficiency argument for having a uniform carbon price across the whole economy: a single carbon price. One reason why the costs of decarbonisation are high is because whole sectors escape some or all of the consequences. These include imports substituting for home production, and much of agriculture. Carbon emissions do not just come out of gas power stations and petrol and diesel cars. Soils have around four times the carbon of the atmosphere, and the ways soils are cultivated and fertilised and the pesticides applied to them cause carbon emissions too (as well as other pollutants). Our territorial emissions do not capture all the emissions, and not all the territorial emissions face the carbon price.
Whereas there is a good case for charging energy-intensive industries the system marginal costs, the argument does not carry across to carbon. It does not matter where a tonne of carbon is emitted. The marginal damage is independent of how the tonne was caused.
It is therefore a mistake to try to give ad hoc exemptions and reductions to industry for carbon. But that does not mean that what we are currently doing is efficient. On the contrary, the carbon price is badly designed and set. Most importantly, it is important to recognise that the price of carbon is not equal to the price of an Emissions Trading Scheme (ETS) permit. On the contrary, the major carbon price is embedded in the prices of oil and gas. Why? Because the price of oil is not equal to its marginal cost. OPEC and OPEC+ jack up the price to extract monopoly rents. If the marginal cost of oil is, say, $5 a barrel (for Iraq and Saudi Arabia in particular), the price is much higher – say $60–$70 a barrel. In crises, it is even higher. If it is $60, then the implied carbon tax is $55 in my very simple example. If, as during the Iran war, it is $100, then the implied carbon tax is $95 per barrel of oil. The carbon price is added on top, via the ETS (UK or EU) and by other carbon taxes. It gets even more distorted because retail and industrial oil and gas get taxed on top of the OPEX tax. Petrol and diesel are highly taxed. On top of all this, the oil production itself is subject to a variety of taxes. To the conventional petroleum revenue taxes are added windfall taxes.
Oil and gas taxation is a mess. If the aim is to signal and tax the marginal cost of a tonne of carbon, then the carbon tax should be set inverse to the oil and gas price. If, say, the US attacks Iran, and if as a result the Strait of Hormuz is closed, the implied carbon tax in the price spikes raises the costs of carbon dramatically. Better to use an inverse index, so that, during spikes, the carbon price is adjusted down, and in troughs it is raised. This creates a stable carbon price. Apply this across all the sources of emissions, and the burden on industry is much better managed.
Other measures that could be introduced
To these reforms—system marginal cost pricing, EFP to replace the wholesale market and inverse indexing of the carbon price—several, more general, energy policy measures can be taken to better set industrial prices. These include:
- investing in strategic storage
- creating a strategic gas generation reserve
- entering into long-term contracts with North Sea gas
- protecting the pipelines.
(i) Investing in strategic storage
A resilient energy system is one that copes with shocks. The UK energy system was once characterised by domestic coal production and coal stocks at power stations, and by the flexibility to extract gas from the North Sea, making the gas wells effectively a giant storage buffer. On coal, the resilience turned out to be considerable, even in the face of major strikes (the main threat to security of supply). But now coal has gone, it is all about gas and gas storage.
In the “bad old days” of British Gas, the gas wells in the North Sea were the UK’s gas storage. Why extract the gas and put it into a storage facility when it was already in a storage facility -the gas well itself? As the gas production has declined (and now is being deliberately further reduced), there is a need to plan for the days when the gas wells are no longer our stores, when the UK becomes like Germany, relying on imports.
An intelligent energy policy would anticipate this problem and would plan the rundown of the industry to use the emptying wells as stores of gas. They would also recognise that, as stores of gas, the declining reserves are of increasing importance and hence value.
Instead there have been two main policies. The first is to connect to other supplies and hence stores. This includes the overwhelming dependency on the Langeled pipeline to Norway and US LNG cargoes on the high seas and the LNG terminals. A repeat of the Nordstream pipeline attacks would expose the extraordinary reliance on the Norwegian pipeline and cause a widespread industrial and economic crisis. Reliance of US LNG, apart from its environmental consequences, is in effect a reliance on the US government and the US LNG exporters to prioritise the UK market.
None of this suggest that LNG terminals and the Norwegian pipelines do not contribute to greater supply security. They do. But it is not enough. More storage is needed, full stop. A start would be to model alternative gas demand scenarios, including data centres, and then model shocks like a pipeline explosion or a US president diverting US shale gas production to home and other markets. The industrial and economic consequences of such shocks to both prices and to availability should be modelled and then a rough estimate made of how much gas storage the UK should prudently hold, considered in the context of the costs of that storage.
(ii) Creating a strategic gas generation reserve
Renewables have, through the subsidy system, been protected from paying the costs of their intermittency, and in the process have rendered the gas power stations intermittent too. This destroyed the incentives to invest in gas, and yet gas power stations are needed to handle the ever-greater intermittency of the wind and solar. In the bad old days, investors could rely on a new gas power station running flat out for a long enough period to recover the capital cost of the project and then move up the merit order, as had coal stations for most of the post-Second World War period. Worse still, this position of intermittency undermines existing gas power stations and advances their retirement.
Recall that NESO projected that 35GW of gas-fired generation would be needed even if the 2030 target was met, but also that the stations would run a very small amount of the time. The consequence if obvious: there will not be enough gas-fired generation in the system to ensure security of supply. Without intervention, power cuts will follow.
As so often happens, the unintended consequences of one intervention (the net zero 2030 target and the CfDs for renewables) cause another problem. Intervening with CfDs now requires a protection mechanism for gas to pay for the insurance to the system that they provide.
Moving towards EFP capacity contracts would improve the situation, but would be incomplete. A preferable approach might be to create a strategic reserve of gas-fired power stations. There would be costs of the acquisition of the assets into the reserve, capital maintenance costs, and the costs of gas contracts that are on-demand but highly infrequent. There is a good case for a new utility model for this reserve of capacity, with a conventional RAB framework, based upon pay-as-you-go, not pay-when-delivered. It would then be a system cost and these costs could be allocated on the same basis as for the grid and other system fixed costs.
(iii) Entering into long-term gas contracts and licences in the North Sea
The supply of gas to the strategic gas reserve stations would pose its own economic problems. These problems need to be contextualised in a wider system context, including storage. The government has decided against new licences in the UK North Sea (whilst happily importing gas produced from the Norwegian North Sea), and has continued a very high windfall taxation regime inherited from its predecessor.
The argument, noted above, is that the priority is to get out of high and volatile gas prices. Yet, as also noted, the reliance on gas is ongoing and for a considerable time period, and the switch to Norwegian North Sea gas and US LNG does not solve the problem of exposure to globally set prices. What does address this problem is to contract long term for gas from the British North Sea, and, in the case of new licences, to mandate these contracts.
This is a return to the “bad old days” of British Gas. The contracts would be for fixed prices (in practice, with some adjustment clauses in the light of global market developments) in exchange for licences. Where there are existing licences, there could be a “negotiation” over the windfall and other taxation components in exchange for a long-term pricing contract mechanism.
These contracts could include storage aspects.
An obvious question is who these contracts would be with. In the case of CfDs it is de facto the government through the auction processes. It could similarly be the government via the NESO in the gas case, with the cost pass-through to gas for heating and for power generation and other industrial applications. The Gas Strategic Utility could be a major “buyer” of these contracts, with specific extra terms to address the uncertainty of when and at what value immediate gas supplies would be needed as the wind and sunshine varies.
A final “buyer” could be gas-intensive industries, mirroring what happened under British Gas and the electricity contracts under the CEGB.
(iv) Protecting the pipelines and electricity interconnectors
Whatever reforms and reshaping of energy policy are taken forward, there is an urgent and obvious need for protection of the existing pipelines and cables. Now there is a very real threat to all of them. The Nordstream explosions are a real-life example. Both Nordstream 1 and 2 were blown up. There are also real-life examples of interference with electricity cables, from Svalbard to the Baltic.
Because there is so much renewables that is intermittent on the system, there needs to be much more interconnection, and because there is so little planning for the decline of the North Sea as a storage facility, there need to be more imports. In the Second World War, it was food supplies that were the critical constraint on the home economy, as the National Farmers’ Union (NFU) and other farming lobbyists keep reminding us in arguing for food security targets (and more subsidies). But, in any future war, there is unlikely to be time to starve to death: cutting the electricity interconnectors and blowing up the Llangled pipeline would bring an increasingly firm-power-dependent economy to its knees very quickly.
Protecting the cables and pipes is a system cost. As with the other aspects of the system costs discussed above, who is charged the long-run system marginal costs depends upon whether slowing down (and even reversing with the new energy-intensive industries) the de-industrialisation of the UK is a priority. Defence of the cables and pipes could fall to taxpayers, or it could be added to the national grid transmission charges. Either way, a full allocation of the fixed costs of a new naval capability and the ships and submarines to meet these needs to industry would probably speed their exit and thereby increase the burden to the rest of the consumers.
Would all this be enough?
Will all this make the UK (and Europe) competitive in an increasingly energy-intensive global economy? The answer is almost certainly no. The costs of the renewables (and now nuclear) are not going away for decades (and many are locked into long-term CfDs). The costs of doubling the grid and the costs of storage and back-up have to be paid for. These are not costs that are matched in the US. But the main reforms proposed here would reduce the cost burdens to industry and slow the deindustrialisation.
If this is not enough, we could start the other way around, and consider the parallels with any normal competitive market. We could just set the industrial price at this global competitive level and work backwards. Industrial policies would have to augment the reforms set out above.
There is a final option: just give up on energy-intensive industries. That is a pretty accurate reflection of the current position. There are exceptions, and government can on a case-by-case basis use the sticking plasters of tariffs (steel, for example) and subsidies and other tax concessions. This could work if done on the scale of China, but given the fiscal position, there is virtually no chance of a fully fledged industrial policy along Chinese lines.
Giving up – what might be called the UK’s “default strategy” – has its adherents. Some think that the UK could pay its way from services. This is a double mistake: the services are increasingly reliant on energy-intensive cyber-driven inputs, including data centres and AI, and eventually the energy needs of quantum computing. The services are likely to be sources of great increases in electricity demand. Even if the economy did go for a very extreme version of an industry-lite model, there are some obvious problems about the surpluses it would need to generate to pay for welfare, the NHS, defence, education and other public services, and to counterbalance the widening trade balance in goods. This problem of the current-account balance of payments dogged the twentieth century, and led to a century of currency devaluation, but was bailed out by North Sea oil and gas. Now it will be imports of energy instead. None of the “new” ways of generating are “home grown”. The solar panels and the wind turbines (and behind them the critical minerals, including and rare earths) are all imported, as increasingly will be the gas too.
To turn this lamentable position around, the reforms set out above are not optional. The decline of UK industry has reached a crisis point, at just the moment when the future industries will require more firm-power electricity. Industry cannot sustain these prices and hence they will not. The UK economy cannot sustain the further loss of what is left of its industrial base, and it must be able to attract the new industries, and hence it will not. Finally, defence cannot be sustained with core industrial capabilities. These reforms are urgent. Energy policy tends to change only after a crisis. We now have one, and hence the opportunity for change.
[1] Helm, D. (2017), “Cost of Energy Review”, 25th October.
