Guest post by Energy Matters’ commentator Alex Terrell. Part 4 of the series on designing a renewable or nuclear electricity supply for the UK in 2050, where parts 1 to 3 were co-authored with Andy Dawson. Here costs of the renewable and nuclear options are compared. The forecast based on BEIS’ median 2030 scenarios for renewables (wind+solar) comes in at £143 / MWh and for nuclear at £84 / MWh, for wholesale costs. Both costs will be a lot lower if the respective technologies improve as their advocates hope.

SUMMARY



Part 1 of this series on 2050 electricity demand provided a “high electrification” scenario where the average electricity demand was approximately 72GW, but peak demand on exceptionally cold days could reach 121GW. Part 2 described how this demand could be fulfilled with a nuclear supply model, and Part 3 described how it could be fulfilled with wind and solar.

A number of different scenarios were explored, with the preferred nuclear and renewables scenarios laid out below.

Table 1 – The preferred scenarios identified from Parts 2 and 3 of the 2050 UK Electricity Supply model.

Parts 1 to 3 avoided a focus on costs because:

They are highly speculative for deployment in the years between 2030 and 2050. They would distract from the purpose of parts 2 and 3, which are to define the supply requirements for meeting the demand identified in part 1.

Obviously the question of costs came up, and now that the arguments over the model capacities have been made and perhaps exhausted, it’s a good time to overlay cost scenarios on to the generating scenarios.

The core cost data scenarios are therefore taken from BEIS (the UK Government department formerly known as DECC). However, there is a lot of sentiment that these costs are too high – there is always an example of someone, somewhere, doing stuff radically cheaper, and these lower costs are included as an “advocate” cost. The results are summarised below:

Table 2 – Total cost summary of preferred scenarios with different cost scenarios.

COST COMPONENTS

Generating costs

The core cost data scenarios are taken from the BEIS scenarios. Specifically Table 6 of the cost report shows “Levelised Cost Estimates for Projects Commissioning in 2016, 2018, 2020, 2025 and 2030, technology-specific hurdle rates, £/MWh, highs and lows reflect high and low capital and pre-development cost estimates”.

In the absence of 2050 figures, the 2030 figures are used. There would be some justification in extrapolating the costs to 2050, but this relies on uncertain developments, and it is not clear that the cost of solar, wind, or nuclear would continue to fall – and in any case, much of the infrastructure operating in 2050 will be being built in the 2030s.

There is a good chance that costs will continue to fall further, and the figures therefore include an “Advocate” cost – which is what those advocating the technology might claim, and is discussed later in the document.

The analysis assumes that thermal generation is made up of CCGT. The BEIS estimates a carbon price of £35/ton of CO2 in 2030, rising to £200 in 2050. The generating costs (taken from BEIS) therefore assume the £35/ton is embedded in the cost of the CCGT. Any additional increases are shown separately as CO2 costs.

Table 3 shows the BEIS and “Advocate” scenario costs per MWh, and also the amount of each generation under our nuclear and renewables scenarios. Note that these are “Levelised Cost of Energy” figures, which are not quite the same as strike prices.

Table 3 – BEIS and “Advocate” scenario costs (left side) and the annual usage scenarios (from parts 2 and 3 – right side), for operation in 2050.

Multiplying the costs by the amounts gives annual generating costs.

Table 4 – Total annual generating costs for 2050 in £ billion (2014) under the wind and solar scenario and the nuclear scenarios.

According to the BEIS 2030 cost projections, a wind and solar scenario would have generating costs of between £70 and £88 billion per year (in 2050), and a nuclear scenario generating costs of between £44 and £63 billion per year.

Capacity costs

Both scenarios require a large amount of standby capacity, which is assumed to be CCGT plant. There are cheaper options, such as diesel, and more expensive options.

The amount of capacity that is funded by a capacity charge is calculated as:

(1 – Utilisation) x Capacity Amount.

This is the “idle capacity equivalent” and comes to 35GW for the nuclear scenario and 106GW for the wind +solar scenario.

Recent capacity auctions have suggested that capacity can be purchased for a very cheap £22.50/KW/year (that means a generator receives £22.50 per KW of capacity, per year, regardless of usage which is funded separately). However, this figure is distorted:

Many of the bidders will be expecting to make some profit in generating, and therefore still view the capacity payments as supplemental income.

The lowest price is being set by diesel capacity. Whilst it would make sense to have some diesel for the least utilised capacity, by 2050 this may be unacceptable and the model therefore assumes 100% gas.

The recent auctions have also failed to bring in significant CCGT turbines. In the most recent capacity auction 9.7GW of CCGT exited the auction. It is reckoned that CCGT needs a price of £35/KW/year to justify new build. This would however be based on the assumption of some utilisation – and the model is trying to identify the cost of capacity separate from the cost of utilisation. The model therefore has Low, Medium and High cost scenarios of £35, £50 and £70 per KW/year.

Table 5 – Capacity costs for the unutilised portion of required standby capacity.

Storage costs

The wind and solar scenario requires 500 GWh of storage. A nuclear scenario would require some 10s of GWh. How much will this cost to provide on an annual basis?

Coire Glas, a pumped storage proposal for the Scottish highlands, has been costed at £800 million, for a storage capacity of 30GWh. This comes to a very reasonable sounding £26.7/KWh of storage capacity. That however is based a favourable terrain, a low power output, and does not include costs of extra transmission. The amount of storage available in this form is limited for the UK.

At present batteries are expensive. The Tesla Powerwall 2 (available from February 2017) works out at about £350/KWh (or £430 with installation). That is at a domestic scale, and prices are coming down. Some industry watchers talk of US$ 100/KWh being achievable in the 2020s, at commercial scale. It may be that this price is reached, and does not fall much further – after all, this price would make electric vehicles affordable.

It may be that for further cost reductions, developers need to move on to lower cost chemistry such as Organic Flow Batteries and leave Li-ion technology for the automotive market where weight and power matter more than cost. The model has low, high, medium scenarios of £50, £75 and £100 per KWh. For the nuclear scenario, only the lower of these costs is used, as pumped storage in the UK is quite capable of supplying 30GWh of storage (batteries not required).

Batteries also wear out, so the annual cost can be quite high. The model assumes that the annual cost is 10% of the capital cost.

Table 6 – Storage Costs

CO2 emissions cost

The calculation is complicated by the fact that the CO2 cost of the CCGT is assumed by BEIS at £35/ton, and this figure is already in the CCGT generation costs. At this price, the CO2 costs of wind, solar and nuclear are also included in their prices.

BEIS however has an assumption that CO2 costs will rise to £200 per ton by 2050. This seems a high case as it exceeds most estimates for the cost of carbon capture and storage, estimated at between $120-140 per ton .

The model has costed three scenarios:

Low: Zero cost above what is already in the CCGT costs (£35/ton)

Medium: £65/ton, based on CCS costs of £100/ton, minus the £35 already embedded.

High: £165/ton, based on the BEIS figure, minus the £35 already embedded.

Table 7 – CO2 emissions costs

COST SUMMARY



Overall costs

The low, medium and high cost scenarios are laid out below. The “Advocate” column is assumed to equal the low scenario except for the Generating costs.

Table 8 – Cost summary. This covers wholesale costs only.

Note that the scenarios are “mix and match” – you don’t have to stay in the same column. You might accept the “Advocate” costs for a generating cost, but place a higher value on emissions costs, or a higher price on the storage costs.

Note also that these are LCOE (Levelised Costs of Electricity). The “strike price” should be higher, to allow for some profit over and above a minimum rate of return. How much higher depends on how the delivery contract is negotiated.

Whether nuclear or renewables are cheaper depend of course on the assumptions made. We can’t settle that argument and it won’t be fully settled until well after 2050, if ever. If you look at the BEIS scenarios, even the highest prices for nuclear resulting in a cheaper system than the lowest prices for renewables. But there are plenty of advocates who argue that renewables prices will be much, much lower. There are also a few advocates who argue that nuclear prices will be much lower. How valid are these claims?

Cost of “grid integration”

What are the costs of “grid integration” for renewables, and how does this compare to nuclear? Integration costs could include:

The cost of excess production. It is assumed that this is shared evenly between wind and solar, and that with nuclear there is no excess production (which may not be quite accurate, depending on the definition of “excess”)

The costs of backup capacity

The costs of required storage

The CO2 emissions costs of the gas burnt are excluded. This is a cost of the fossil fuels – but one could argue that it is needed only because the renewable or nuclear scenarios are not perfect.

The costs of transmission are also excluded, as the price for renewables is the price at the UK grid connection point. In other words, any HVDC cable costs are included in the costs of renewables generation.

Table 9 – Costs of grid integration for the wind / solar and nuclear scenario. For renewables, we need to take the composite LCOE calculation and add between 32% and 41% depending on assumptions.

Average integration costs are 36% of the generating cost for renewables, and 4% for nuclear. That is equivalent to a mark-up of 31% for renewables compared to nuclear. This means that:

If Nuclear can generate at £69/MWh (the BEIS “Low” scenario), then renewables will be cheaper if the price is below £52.50/MWh.

To be lower than the £100/MWh (2016 currency) strike price of Hinkley, renewables need to be lower than £76/MWh.

Value of “surplus” electricity

The surplus electricity could be “sold” to make gas. The value of this is – again – hard to quantify but should relate to the price of natural gas. Assuming a natural gas price of £50 / MWh, then the electricity to make this could be worth about £20 / MWh.

At this price, the excess generation in the renewables scenario is worth £4.3 billion per year, and this could be subtracted from the integration cost estimates above.

Marginal versus average costs

Whilst the numbers in Table 8 above show a strong cost advantage for nuclear, the cost of renewables will fall faster. In 2050, the high strike price for Hornsea and other current offshore wind farms will be long gone. Hinkley C however will still – just – be receiving £92.50/MWh, indexed from 2012 prices.

The cost of nuclear “in operation” in 2050 could range from Hinkley C (which should end its strike price between 2050 and 2052) down to the “advocate price” (£50/MWh in 2016 money) or lower. The average will depend on how fast the Government and industry can force down costs.

RENEWABLES COSTS TRENDS



A UK renewables supply will to a large extent be dominated by offshore wind, so that is the cost we will focus on.

Current UK costs

In February 2015, Contracts for Difference were awarded to 1,162 MW of offshore wind capacity at average of £117/MWh. This was below the £140-150 that DECC expected to pay, and below the cost of previous CfD agreements which were not put out to competitive tender.

At the same time, solar projects were receiving £82/MWh, though at a much smaller scale. Indeed, two solar projects bid at £50/MWh, but these are not expected to be delivered. This illustrates that we should not take one-off prices for small schemes too seriously – there will always be bidders who do not understand their cost of capital, or who are prepared to accept losses for one reason or another.

Latest European wind power costs

Outside of the UK, recent costs for offshore wind contracts appear to be a lot lower:

Netherlands: In July 2016, a 700MW wind farm (Borssele) was bid at €72.7/MWh (currently £63/MWh) by Dong Energy. It appears this price is comparable to a UK strike price in its structure. The project is shovel ready – the Government has already paid for the required environmental impact assessments, and it excludes transmission costs (which should add €14/MWh).

Denmark: In November 2016, Vatenfall bid €49.90 for the 600MW Kriegers Flak offshore wind project. This appears to be under the same conditions as the Dutch auction – but there is as yet no explanation for the very low price.

Key factors enabling the lower price are:

A cost of capital estimate of 8.5% or less, rather than the 10% that the UK auctions appear to accept. An 8.5% cost of capital assumption for Hinkley C, would have lowered the strike price to about £73/MWh.

A highly competitive auction with several bidders, forcing bidders to make economies and lower their cost of capital.

The Government undertaking site survey, removing a large up front expense. Forewind for example has spent £60 million on site surveys for the Dogger Bank wind farm. If Borssele’s developers had to pay €60 million for a site survey, this would add €5 to €10 to the strike price, depending on how they account for the risk of not being able to proceed.

It is also not clear whether the cost improvements are durable and repeatable, or whether the winners are going in with a lower cost of capital to boost market presence – in other words, treating this as a loss-leader. If they are prepared to permanently accept a lower cost of capital in future, then much of this cost reduction should be transferable to the UK.

Upward cost drivers for wind power

The Dutch and Danish projects are also for near shore developments in favourable waters. Future UK (and German and Dutch) projects will have to be far offshore.

Going further offshore also tends to mean deeper water. A decade ago, it was widely assumed that water depths needed to be below 25m to be economic. However, larger turbines require larger towers and larger foundations, and an effect of this is that the maximum economic water depth is increased, to perhaps 40m for 8MW and 50m for 10MW turbines. 50m brings most of the North Sea south of the 55th Latitude within range for development.

However, above 50 to 100km offshore, AC transmission losses start to become unacceptable and DC transmission is required. This increases costs significantly.

Figure 1 – The HVDC platform for an 800MW offshore wind farm. The topside has a total weight of 12,000 tonnes and measures 72.5 m x 51 m x 25 m high. The cost is estimated at €500 million which appears to include €200 million for the 200km long cable. This compares to an estimated (reverse engineered) construction cost of €1.5 billion for the 700MW Borssele wind farm discussed above.

Equally, maintenance becomes more difficult, more expensive, and more dangerous in waters further out. Maintenance crews will have to be based on offshore platforms – pushing up fixed O&M costs. With poor weather conditions, crew may have to wait weeks before they can access a wind turbine to perform repairs, reducing the available capacity and hence revenue of the wind farm.

Replacement costs

Dong Energy is assuming that turbines will last 20 to 25 years, after which the Nacelle and turbine can be replaced on the existing tower. This length is longer than current life time indications and if Dong Energy have got their assumptions wrong, then this will hit them financially. If the turbines fail before the end of the strike price term, this will impose severe financial problems on the company.

In principle, replacing just the top portion of the assembly should help reduce costs significantly when it comes to replacement time. However, the replacement market will be a monopoly – only Dong Energy will realistically be able to replace the nacelle, turbine and blades on a Dong Energy tower. This could enable them to make higher profits in future, and may have justified a lower bid in 2016.

Offshore wind technology development

Advocates like to assume that costs will continue to fall at the same rate as they have done so over last year or two, conveniently forgetting that prices have risen and fallen in the past.

Figure 2 – Cost trends in offshore wind installed cost from NREL . The 2016 cost has clearly fallen below the expected cost, but that does not necessarily mean costs will continue to fall.

Part of the recent cost reductions – especially for offshore – have come from increasing turbine size. Increasing turbine size will continue to push down costs, especially as direct drive (which avoids the needs for gears) benefits from a larger nacelle diameter. However, as turbine power increases, the weight of the blades increases faster (the power increases with the square of the blade length, the weight of the blade with the cube). These cost more and increase the lateral strain on the bearings, again leading to greater build cost or higher maintenance costs.

Costs of grid connections could be reduced with a HVDC network covering the North Sea, with hubs next to the wind farms able to send electricity to Norway (for pumped hydro storage) or to the UK or Germany, depending on demand. The hubs would also transfer stored energy from Norway to the UK in the event of low wind conditions.

However, unless there are technology breakthroughs (cue Kite powered wind generators), rates of cost reduction will decrease and may be overcome by the cost of moving further offshore.

Deployment scales

There may be some costs from increasing scale of deployment. A renewables powered UK will require some 200GW of offshore wind power, or 20,000 10MW turbines.

If the average turbine lasts 20 years, then this will require a 1,000 to be deployed each year, or about 5 per day during the installation season. There is scope for improving the deployment process – for example by using self-jack up barges:

Figure 3 – Titan 200 Offshore self-jacking platform – this kind of concept could help reduce deployment costs on a large scale, by reducing deployment and offshore assembly time.

With replacement turbines and improved processes, the “Advocate cost” of £40/MWh could be achievable.

Solar power costs

Solar power costs have been falling even faster than wind costs. Recent tenders in Abu Dhabi have seen tenders for solar power at $24/MWh. However, we shouldn’t read too much into individual tenders, and there are reasons why costs are so low:

Solar projects in the Gulf are financed by extremely low interest rates of 4%. (If Hinkley C were financed at 4%, it could sell electricity at around £25/MWh).

The land is free. Whilst in Europe grazing and solar panels can co-exist, in practice, on a large scale, the land will not be free.

The solar yield in the UK will be around half that of Dubai’s, effectively doubling the price. The seasonal variation also pushes up the cost of grid integration – though this section focuses on pure generating costs.

In Europe, there are people who are prepared to accept a very low rate of return: Householders with savings and an environmental conscience (whether it is right or wrong). Solar also works well at a domestic level as it bypasses the distribution costs – for “own use” it has to compete against retail, rather than wholesale prices. However, to provide 100GW of solar, there will need to be extensive commercial deployment, expecting commercial rates of return.

Commercial solar has bid at below £50/MWh in the UK. However, Gordon Edge, head of policy for industry body Renewable UK, said they look like “kamikazee bids which I don’t expect to be delivered”. More recently, Danish firms bid €54/MWh to build 50MW in recent German cross border bids. The main reason for the low cost was the auction format. With 17 firms trying to establish a positon in a growing market, the winners are unlikely to make a decent return on investment. As the market matures, we can expect to see fewer auction bidders and rates of return will increase, acting to push prices up.

Against that, module prices will still fall over the next few decades. The rate of price falls in silicon PV will probably tail off, as fundamental material costs start to dominate. However, there may be scope for further price falls if the industry switches to thin film cells, which can be printed onto rolls.

Given these developments, it’s conceivable that solar could be generating at £30/MWh in England. Given the seasonal variation, it still won’t make sense for solar to become the dominant form of electricity generation in Northern Europe, though in much of the world – dry tropics and near tropics, where summer air-con demand is much higher than winter heating demand – solar with diurnal storage will likely be the lowest cost form of electricity production.

NUCLEAR COST TRENDS



Design cost trends

It is a common argument against nuclear that £92.50/MWh – the 2012 strike price agreed for Hinkley C – is too expensive and more expensive than renewables will be. However, it is also likely to represent a high water mark in nuclear costs, and as such, it is more expensive than nuclear will be.

Prior to the Brexit vote, the Hinkley C build budget was about $8,000 per KW. Following the fall in the pound, this cost has come down somewhat, to about $7,000 per KW. Despite the fact that about 40%-50% of the cost is expected to be spent abroad, the budget has not been raised due to currency effects.

It could be that there is head room in the budget – which was built in when the strike price was being negotiated with the Government. After all, the budget was based on costs at the Flamanville build, where a lot has gone wrong, and is therefore based on the assumption that EDF and the contractors will continue to make significant errors in the construction phase.

Both the AP1000 and ABWR show indications of being more cost effective. The developers will be looking for a generous strike price in the light of what Hinkley C has received, but the Government’s hesitation in 2016 may have sent a message that the Government is looking for a lower strike price. We would expect – perhaps optimistically – a strike price of between £70-80, compared to Hinkley C’s £92.50 (The actual figure will be indexed higher).

At the start of 2017, the Chinese Hualong One design has entered the GDA process. The developers have publically stated that they expect to build this in China at a cost of $2,500 per KW – about one third the cost of the EPR. Whilst the cost will be higher in the UK, we could expect a strike price of £60-70 for the Bradwell Hualong One.

The effect of auctions

We can see from Dutch auctions for wind power, Danish auctions for wind and solar, and UK auctions for capacity, that auctions are a very, very effective way of getting lower prices. They encourage bidders to accept lower costs of capital, and to innovate in the design and deployment processes of their product.

In nuclear, auctions may not be quite as effective, as bidders are constrained in changing a lot of processes and designs by safety regulations. Whilst there is significant surplus cost in the build and operations of nuclear plants, much of this is determined by regulations, some of which are quite necessary.

Auctions for nuclear capacity will have to wait until there are at least 4 or 5 qualified providers with competitive designs – say the AP1000, the ABWR, and the Hualong One, the APR1400, and perhaps the first SMR provider. This approach could however see a large number of Hualong One deployments, unless other suppliers can bring their costs down. For security (of supply) and political reasons, it may be desirable to cap the amount of generation from a specific design or a specific vendor (for example, no more than 15GW from any supplier or generic design).

Direct government investment

Auctions reduce the cost of capital, and therefore the cost of electricity produced. Another way of reducing the cost of capital would be for the Government to take a direct equity stake in the project – on the grounds that Governments (some, including the UK) can borrow at very low interest rates.

To what extent this could reduce the cost of capital is debatable. And there is also the risk that Government involvement may push up construction costs – though examples like CrossRail suggest Government led projects can be delivered on time and on budget.

This approach would be an alternative to auctions. However, as auctions require several participants – each with a GDA design – Direct Government investment may be preferred for near term developments as at Moorside and Wyfla.

The Government may be forced to try this approach at Moorside, as Toshiba may pull out as an investment partner due to global financial problems. The Government may come in and replace them as an equity investor, and bring in Korea’s KEPCO as a co-investor and delivery partner in the project. This would lower the cost of capital, and ensure that Moorside gets built.

If KEPCO is the preferred partner, they may switch the design to their APR-1400 reactor. This however couldn’t be certified before around 2022, and this would delay the project. More likely therefore is that they would stick with the AP-1000 design for Moorside, but then have the right to build their APR-1400 elsewhere. Hartlepool would be the likeliest site for two to four reactors.

Once the reactor is commissioned, the Government would then sell its stake, as a low risk, low return asset. This would attract infrastructure investors with a low cost of capital.

Removing up-front costs

The recent auctions for wind power in the Netherlands were conducted after the Government had organised site surveys and obtained the permissions. The UK nuclear builds on the other hand expect a 10% rate of return, which includes the costs of GDA and site purchase, licencing and preparation.

As these costs are many years before revenue is earned, they have a disproportionate impact on the return, and hence the required strike price. A basic financial model of Hinckley C suggests that removing the costs (including land purchase) prior to Final Investment Decision (made in September 2016) would reduce the strike price by some £6/MWh.

Figure 4 – The effects of Cost of Capital and removing up-front costs on the Hinkley C strike price. This is based on a basic model of Hinkley C costs and revenues. Other designs would show a similar proportionate fall in price.

After the first set of builds (at Hinkley, Moorside, Wyfla and Bradwell) the Government could buy future sites, obtain site permissions, and then auction the build permit to the lowest cost bidder. This would include an obligation to rent the land at a fair price – though the bidder could also present a different site (for example offshore) if that were cost advantageous. The company who bids the lowest strike price would get permission to build.

The other up-front cost is that of design approval. It is Important that the GDA process doesn’t add cost to the design, except where it is safety critical. The UK GDA is meant to be technology/design neutral, whereas the US process is more prescriptive – the regulations can require a design feature, even if that feature is made redundant by other feature. However, there is still the slippery concept of ALARA – “As low as reasonably achievable” – which applies to risk and radiation exposure. In theory, this concept allows a regulator to insist on expensive design or process modifications to reduce radiation levels, even though the radiation levels are already totally safe, and below background levels in many parts of the world. The UK’s ONR will have to take a pragmatic view on future designs, to avoid driving costs upwards.

This approach would bring the cost of nuclear power from PWRs to around the £50 shown in the “Advocate” column.

Technology for lower costs

Moving beyond large scale PWRs, the first generation of SMRs are unlikely to provide substantial price advantages. NuScale for example are estimating a capital cost of $5,000/KW (in the USA) for their 60MW units. Larger designs such as the Westinghouse and Rolls Royce 250MW units might work out more cost effective.

If Molten Salt Reactor technologies can be developed and licensed, then there is scope for further price reductions. For example, Atkins have evaluated the Moltex Stable Salt Reactor design and estimated the capital costs at $2,000/KW, for a UK build. Cost advantages of molten salt reactors come from:

High power density – it is possible for a 250MWe unit to be transported by road;

Low pressure operation, removing the need for large high performance forgings;

Simpler control – the power output of the reactor can automatically follow load, due to a strong negative temperature reactivity (a drop in load leads to a small rise in core temperature, which leads to a large drop in power output);

No complex fuel fabrication – liquid fuels rather than precisely engineered fuel rods;

Higher output temperature – this increases electrical generation efficiency and almost halves the cooling water requirements compared to a PWR;

Increased burn rate of fuel – reducing Uranium mining and reprocessing amounts;

The designed-in passive safety measures reduce the need for expensive active safety measures – though this would need to be confirmed by the regulators.

The Terrestrial and ThorCon designs overcome material corrosion and graphite swelling issues by swapping out the entire core after a period of between 4 and 7 years. This allows fairly conventional stainless steels to be used. It also shifts a lot of the upfront cost to an operating cost – repeated every couple of years.

This also means that the plant lifetime becomes indefinite. As parts wear out, they can be replaced. This will require significant changes to the inspection regime – for example, what will be the certification process for a core designed to last 4 years, rather than an entire plant designed to last for 60 years?

Needless to say, there is plenty of scope for the regulatory processes to increase costs to the point of non-viability. However, if build and regulation go as the advocates hope, we could see costs coming in below £40/MWh. Moltex expect their LCOE to be $45/MWh.

Using existing infrastructure

One final way of reducing the costs of a Molten Salt Reactor is to use existing infrastructure: Namely coal plants which otherwise need to be retired.

In the UK, long term, there is only really Drax. Others will have been demolished or have steam turbines dating from the 1970s. In Europe, there are new coal plants that could be converted, such as the 1560MW Eemshaven Power Plant in the Netherlands, completed in 2015. At some point – these need to be abandoned, and the Dutch Government is intending – if not planning – to exit coal.

It would be possible to reuse the high pressure steam turbines, low pressure steam turbines, switchyard, cooling water systems and general building infrastructure. If these “stranded assets” are treated as free, this could halve the capital cost of a molten salt reactor, and reduce generating costs to around £30/MWh.

Rollout schedule

With the above changes, we can see costs of nuclear falling substantially from the highs of Hinkley C:

Figure 5 – Generating costs of different technologies with process improvements.

Assuming – perhaps optimistically – that about 20GW is deployed by 2030, and the target is 85GW by 2050, then UK would need 3 to 4GW to be deployed every year between 2030 and 2050.

This could be achieved with an annual or bi-annual auction for a site, with 4-8GW of capacity, starting from 2025. A nominated site would be chosen in advance and the Government would have obtained site approval – though bidders should be allowed to bid on an alternative site.