UK Electricity 2050 Part 2: A High Nuclear Model

Guest post by Energy Matters’ commentators Alex Terrell and Andy Dawson. In part 2 of their trilogy, Alex and Andy examine how the UK 2050 electricity demand may be met by a nuclear dominated supply model. It requires 85 GW of nuclear capacity in the UK. The model is founded on existing technology and existing UK nuclear sites. But as the decades pass goes on to include new UK nuclear sites previously occupied by coal fired power stations and clusters of small modular reactors (SMRS) that have yet to be built, licensed and tested. It concludes by introducing the concept of nuclear islands built in very shallow water off the English coast.

UK Electricity 2050 Part 1: a demand model


The previous article on 2050 electricity demand provided a scenario where the average electricity demand was approximately 72GW, but peak demand on exceptionally cold days could reach 121GW.

This article shows how this could be substantially fulfilled with nuclear power, relying on some gas (or biofuel) to provide peak power when required. A number of different scenarios are explored, with a preferred scenario of 85GW of available nuclear capacity.

The aim with this scenario will be to have 85GW of nuclear capacity available throughout the winter period. In practice, this will probably mean having 87GW of total nuclear capacity, with scheduled outages (for maintenance and refuelling) timed for the summer months.

The thermal capacity (mostly gas, but it could also contain some oil or biofuels) is used for peaking, especially in the winter months. The current UK electricity supply strategy already envisions 37GW of gas capacity. In this high-nuclear scenario, they only run with a utilisation of 6.5%.

Our next article, number three in the series, will explore how demand could be provided with a mix of wind and solar power, supplemented by gas and electricity storage. In reality, it is likely that a mix of nuclear, wind, solar, tidal, import cables and gas will be used, but the extreme scenarios provide useful reference points.

A Nuclear Capacity Model

The demand target

The previous article modelled the following electricity demand distribution curve for 2050.

Figure 1 – Frequency distribution of electricity demand in 2050. Whilst typical demand is around 60GW, extreme weather can push up demand (averaged over the course of the day) to 120GW.

Providing a system what can produce an average of 72GW, but up to 121GW (averaged over the day) on the coldest days is not straightforward. A demand of over 120GW might occur one day every three to ten years, but it still needs to be dealt with, and in a way which minimises the capital expense of nuclear plant (or renewables, as discussed in the next article), whilst minimising the use of fossil fuels.

Whilst current nuclear power can be ramped down, it is not currently economic to do so to any great extent, there may be future developments that could allow increased flexibility:

  • Generation 3+ reactors such as the EPR can be ramped down to 60% of nominal output. In theory, doing so could extend the life of the reactor, but this is determined more by regulatory constraints than actual wear and tear. In addition, the cost of capital means extending the reactor life (decades in the future) is not such an advantage.
  • Molten salt reactors may have a much lower capital cost, and could therefore economically be turned down or off. Designs based on graphite moderators (e.g. ThorCon, Terrestrial) have cores that are swapped out after a certain number of years. Reducing the power of these reactors will extend the core life and reduce the need for core swaps, making this solution more economic.
  • Molten salt reactors will produce heat at a high enough temperature for steam methane reforming. The resultant CO2 could then be stored, and the hydrogen used to supply energy in the winter (either for direct heating, or by electricity generation in gas turbines or fuel cells). However, spare capacity would be in the summer, and demand for hydrogen will be highest in winter, and storing large quantities of hydrogen is not straight forward.
  • High Temperature reactors (such as the pebble bed design being built in China)
    may be able to switch from the production of electricity to the thermal production of hydrogen from water, whenever demand is low. This is a highly attractive solution to powering aviation, haulage and shipping (perhaps through synfuel production), but not without complications for energy storage. As above, spare capacity would be in summer, demand for hydrogen in the winter.
  • High temperature reactors, including molten salt reactors, can store energy in the form of hot salts. The developers of the Moltex Reactor have proposed storing several hours worth of thermal output, which can be used to vary the electrical output. They have suggested this as a way of working with renewables, to counter their intermittency. However, this is not a solution for seasonal storage.

Given the uncertainty of the above technologies, it is prudent to assume – or at least to base the analysis on the assumption – that we want to run nuclear at a high capacity factor, and avoid building more capacity than is required.

Nuclear and gas solutions

The clear implication of the above analysis is that there’s a major incompatibility between the concept of an all-nuclear grid and the ability to supply the more extreme ends of the probability distribution for demand. However, the effects of this are not as severe as might immediately be assumed; carbon output is not particularly time-sensitive in that our key parameter is annual output, and hence short periods of what might appear to be high levels of fossil fuel output have little effect.

Taking the weather related demand model from the last 20 years of temperature records allows us to plot nuclear and gas plant utilisation on a daily basis, and to tabulate this into a capacity model.

Figure 2 – A nuclear capacity model. At low levels of nuclear penetration, the reactors work at their maximum available capacity (refuelling would result in extra gas being used). Only after about 50GW of capacity, does nuclear supply start to be curtailed (in the summer). An “available” capacity of 85GW nuclear would supply 97% of the electricity, and requires about 35GW of thermal power (gas, diesel, biofuel or hydrogen) capacity to supply the remaining 3%.

Figure 2 above shows this effect. With a nuclear capacity of 80 – 85GW average carbon intensity is of the order of 25-30g/kWh – well below the 50g/kWh threshold regarded as a “stretch target” by the Climate Change Committee.

Note that we’ve not attempted to model any effect from short term interventions available from the use of pumped storage, other than intra-day demand levelling. We anticipate a significant amount of pumped storage being available “on system” as it will have been key to a transition to a low carbon grid at current demand levels, before demand management becomes fully developed and delivers the diurnal stability which we have identified for this 2050 scenario.

We’re therefore led to the following preferred scenario:

Table 1 – A summary of the 2050 Nuclear supply scenario.

This compares with emissions from the energy supply sector of 153 Mt in 2014, which excludes emissions from nuclear, wind and solar. The carbon intensity of these sources is taken from the IPCC mid-range estimates (and is of course highly contentious).

The 85GW of nuclear capacity is the targeted winter availability. In effect this means having an additional 2GW of capacity to account for unscheduled down time in the winter (based on current US nuclear power plants “ forced outage rate” of between 1.1% and 3%.

The gas usage could be replaced by bio fuels if available. At the “tail –end” of the supply model, we could use diesel generators. These might not be used at all in a typical year, only coming into use in extreme circumstances – funded by a standby capacity payment. In this case, their high emissions do not materially impact CO2 emissions.

It should also be noted that the current Government / National Grid strategy expects a requirement of approximately 37GW of gas capacity by 2030. This would then fulfil the “peaking” capacity requirement for 2050.

Utilisations and maintenance

The next question we must consider is the sustainability of this level of supply against demand over the year – especially given that for a considerable proportion of the year demand is below that 85 GW.

In fact, the apparent mismatch is not problematic. A large proportion of demand will be fulfilled by Pressurised and Boiling Water Reactors – even if other technologies come on stream in the 2030s. These reactors do not “on-load refuel”; that is, they are periodically taken off supply, depressurised and a substantial proportion of the fuel load removed and exchanged (it’s also usual to “shuffle” the fuel that remains to optimise fuel utilisation). This would typically involve a 4-6 week shutdown occurring every 15-18 months, although there are technical options available to extend this to 18-24 month intervals. It is also usual to utilise these outages for overhaul and maintenance on those parts of the plant which are not accessible during normal operations. It leaves the majority of the world’s LWR fleet operating at a NET capacity factor of around 85-90%, including the effects of forced outage (see above).

The timing of these outages is, of course to a very large degree discretionary, and hence can be managed across a fleet to follow a demand profile. In principle, it should be possible to schedule outages in the summer. Figures 4.2 and 4.3 show the capacity utilisation of the nuclear and gas fleets. Through June to September, capacity utilisation averages around 75% and rarely goes above 80%. Therefore 20% of the fleet can be taken offline during those 4 months.

The end result is that an 85GW fleet largely made up of LWRs would, in fact, be operating close to its optimum, provided that the refuelling outages were aligned with the period of low demand.

Figure 3 – Monthly capacity from 2010 (coldest recent year) weather patterns with 2050 demand. Generating amounts are stacked and sum to demand.

Figure 4 – Daily capacity from 2015 weather pattern with 2050 demand.

It is quite feasible for the “tail” of capacity to be provided by oil fired power stations, without major impacts on emissions. Figure 5 illustrates a scenario, based on 2013 weather patterns, where capacity over 2,520GW / day (105GW average) is provided with oil fired power stations. Oil fired power stations have low capital cost, and an easy to store liquid fuel – they are therefore well suited to long standby periods and occasional use.

Figure 5 – Daily supply amounts assuming a mix of 85GW nuclear capacity, 20GW gas and the remainder diesel/bio-diesel

In this instance, the capacity amounts and factors are shown in the table:

Table 2 – Supply parameters for with diesel providing standby capacity. (The small difference in nuclear supply from table 1 is that this is based on 2013 weather only.)

Delivering 85GW of nuclear capacity

Initial LWR deployment

There is little point considering this model if physical and economic constraints make it infeasible to install the necessary capacity. This section will consider the viability of an 85GW nuclear fleet within the UK’s geography and grid characteristics.
The current plan (Wave 1) is to have approximately 20GW of nuclear capacity by 2030:

Table 3 – Wave 1 deployments

This deployment is possible, but the plan is perhaps optimistic. Given the issues regarding the EPR implementation at Hinkley Point, there is a chance that future EPR implementations – including Sizewell C – will need to be replaced by AP1000s, ABWRs, Hualong Ones or another design.

It should also be noted that Sizewell B will, even with a life extension to 60 years, be at, or close to retirement in 2050.

Auctions subsequent deployment

By the time it comes to commission Wave 2 – perhaps 2025 – there will be several accredited designs, probably including some Small Modular Reactors. The most cost effective way to deploy reactors will be for the Government to select site and obtain outline site approval, and then auction off the right to build and operate approved reactors. The Dutch Government has recently adopted this approach for offshore wind farms and has used this to cut bid prices significantly.

With this approach, the siting will be determined by the Government, but the actual builds to be deployed will be determined by the market. The build constraints will to some extent feed back into the site selection – as different technologies may be more suited to different sites.

Technologies for subsequent deployment

Debate about available nuclear technologies over a 30+ year timescale will inevitably be speculative to a degree, and will reflect the enthusiasms of the various proponents. In particular, the role of technologies such as liquid-metal cooled fast reactors (LMR) molten salt designs (in their various guises) (MSR) and Small modular designs (SMR) are open to debate.

Whilst the UK Government is attempting to accelerate the development of SMRs through development funding and competition, there are certain core constraints as to the ability of radical new technologies to play a major role, most specifically the timescales for licensing processes, and the need for any new technology to pass through a prototype/demonstrator phase before large scale commercial deployment.
This implies that a substantial roll-out of any new technology is unlikely until the mid-2030s (in line with the expectations of the international “Generation IV” consortium), and hence can play a major role only in the latter part of any build out at best.

Assuming a roughly linear build rate from today, approximately 3GW/year will have to be commissioned. To what extent this comprises existing LWR designs and to what extent it comprises of SMRs, will to some extent depend on the outcome of the Government’s development program and competition. It is prudent to assume that a “second wave” of LWR reactors will be required.

Considering each of the three LWR designs likely to be built (excluding EPR), there are reasonable extrapolations in terms of what can be expected in terms of capacity:

  • AP1000 is capable of considerable “stretch” (SNERDI, in China is investigating options for 1700MW and 2100MW 3-loop derivatives), but Westinghouse ceded commercial rights for derivatives over 1300MW to China as part of the licensing deal there, resulting in the “CAP1400”. We’ll therefore assume that “second wave” AP1000s will be of 1300MW capacity.
  • ABWR is already available in a 1600MW variant (proposed by Toshiba as opposed to Hitachi); we’ll therefore assume any ABWR build beyond those listed ahead are built at 1600MW capacity.
  • Hualong-1 is a derivative of the 3-loop Framatome design of the 1990s, originally of 900MW capacity. There’s a practical limit on the degree to which such a design can be stretched; we will therefore opt for conservativism and assume 1300MW units.
  • There is however political opposition to using Chinese based designs. Some of this is based on misplaced fears, but we would assume this might limit the Hualong to less than 10% of the overall market.

One other development option is worthy of note, albeit not making a material difference to the scale of deployment and available capacity – that is the “Reduced Moderation Boiling Water Reactor”. Currently under development by Hitachi, this is closely based on the ABWR design, with changes to the core design that leaves it operating on an epithermal neutron spectrum. This permits the “burning” of higher transuranics which cause issues in reprocessing of conventional LWR fuel. Replanning some or all of the assumed ABWR deployment with RMBWR would considerably ease waste management problems.

Location Options – a guideline scenario

We’re therefore left with a challenge to find a distribution of capacity that broadly fits with the UK’s geographical demand pattern and is both economic and has minimal environmental limitations. That implies:

  • Generation close to demand, meaning a southern bias.
  • Reuse of existing nuclear and generation sites where possible.
  • Coastal or estuarine sites are to be preferred, where possible – this avoids the parasitic power losses and other constraints of cooling towers, or excessive heat dumping into rivers.
  • Where existing inland sites are utilised (typically fossil fuelled), the new build should be no greater in thermal impact than the current stations.
  • Where possible, there are operational gains in using similar technologies within a single site.
  • As a minor consideration, within range of large centres of demand for district heating. This is not actually a severe constraint as the cost of the “local loop” will exceed the cost of main supply, even up to 100km distance.

Six of the current new build nuclear sites appear to have land area to accommodate six LWR units. These are specifically Bradwell, Hinkley Point, Sizewell, Hartlepool, Wylfa and Moorside. Our 2030 proposal assumed four LWR units/site; installing six LWRs at some or all of these sites would give us up to twelve of the eighteen additional units required.

Six units is a large station by world standards, but far from unknown – examples exist in Japan, Ukraine, Canada and France (at Gravelines, near Dunkirk). At these coastal sites, there is no lack of ocean cooling water – even if the tunnelling works to access the cooling water can be expensive (The cooling water for Hinkley C requires 9km of 7m-bore tunnelling).

Also in the 2030 proposal, we have further identified three additional sites apparently suitable for new build – Aberthaw, Killingholme and Tilbury/Isle of Grain. Expanding these sites to four LWR units would give us six further LWR units.
There are a limited number of former coastal coal-fired station sites that would seem to have potential – Lynemouth in the North East being perhaps the most obvious. Lynemouth would appear to have space for up to four LWRs.

Of a more contentious nature, two current nuclear sites could readily provide a home for 8-12 LWR units – Hunterston and Torness. This would, however required a significant shift on the political relationship between Holyrood and Westminster.

Subsequent LWR deployment

A Wave 2a deployment could consist of the following existing sites and technologies.

Table 4 – Wave 2a deployments

If EDF / Areva are able to sort out the issue of the EPR, and bring the cost down, then the Hinkley Point D build could be made up of EPRs. Assuming the Hualong-1 option, total nuclear capacity in Waves 1 and 2a come to 45.9 GW.

For the deployment if subsequent LWRs or novel SMRs, new sites are going to be needed. We assume a Wave 2b deployment of LWRs would only take place if SMRs do not make expected progress in the 2020s. A wave 2b deployment could consist of the following existing sites and technologies (new sites are in italics).

Table 5 – Wave 2b deployments

SMR Siting

Making assumptions about capacity/site for the novel designs is inevitably more difficult, given that unit size ranges from the 50MWe of the NuScale unit to around 600MW for a twin PRISM unit, or the Moltex MSR.

A number of commentators have suggested that the SMRs can be deployed in small clusters near to cities to provide district heating as well as electricity. We think this is unlikely for two reasons:

  • SMRs are likely to be grouped in clusters for security and operational reasons. Whilst a single 60MW NuScale unit is feasible, we would expect clusters to have at least 600MW of capacity.
  • The main cost of district heating is the local loop. If a City builds a local loop, then it is possible to supply large quantities of hot water from some distance. For example, Bristol has recently announced plans for a district heating scheme – it would be quite feasible to supply it with hot water from Oldbury power station.

A typical small cluster of SMRs might consist of:

  • A single twin PRISM unit (PRISM is design to deploy in pairs driving a single turbogenerator)
  • 10-12 NuScale units
  • 3 Westinghouse or Rolls-Royce SMR
  • 5-6 mPower SMR units
  • 2 Terrestrial Energy Molten Salt Reactors, if the technology progresses

There is indeed no reason why SMRs can’t be grouped in larger clusters – for example twenty of Terrestrial Energy’s IMSR600s would supply between 5 and 6 GW of electricity, whilst occupying less space than Hinkley C.

Sites for novel technologies.

Assuming SMRs make reasonable progress in development, they would be installed instead of the Wave 2b LWRs. We then need sites for around 40 GW of reactors, in clusters of various sizes. The first sites might include:

  • Sellafield – where there is already a proposal to deploy two PRISM 300MW reactors as part of the UK’s waste disposal strategy.
  • Trawsfynnydd – Site of a former MAGNOX station, there is considerable local support for this becoming a site for SMR development. Cooling capacity is inherently limited, however, being (a) located in a National Park, and hence unlikely to be allowed cooling towers, and (b) reliant on an artificial lake. A single 600MW cluster would be viable at the site.
  • Dungeness – Dungeness was not included in the original list of sites for new reactors. The main reason given was cooling water constraints near a SSSI. There is however considerable local interest in maintaining a nuclear power station asset on the site. A higher efficiency SMR design – for a example a MSR or HTR (High Temperature Reactor) would alleviate the cooling issue.

The relative compactness of SMRs, even deployed as clusters, gives considerable flexibility in location terms. Two existing nuclear sites have potential in this context – Heysham and Dungeness (see above). Heysham is an awkwardly shaped site, but is not constrained in cooling water capacity.

Our best prospects for siting further clusters are current and recently vacated coal-fired sites (albeit Didcot is lost to housing development). Typical former coal-sites have supported stations in the range 1000-2000MW, hence a reasonable assumption of 2GW sites is not infeasible, utilising sites such as Rugely, West Burton, Eggborough, etc. Unfortunately, these sites tend to be associated with the former coalfields, and are hence further north than is ideal. Hence potential early sites for SMRs could include:

Table 6 – Wave 2b SMR deployments

In practice, a mixture of “wave 2b” and SMR deployment is perhaps the more probable option, allowing for a gradual cutover as the SMR market becomes established. That results in a total supply position of somewhere between 66,000 and 86,000 MW.

Going offshore

Even with the above list, we could be up to 20,000MW short for our 2050 target. Finding sites may be difficult – as it has been for onshore wind farms. Perhaps nuclear could follow the wind farms offshore. At least one developer of SMRs has proposed siting clusters of reactors offshore, on artificial islands. The island would be situated about 12-20km offshore, in water of 5-10m depth (at high tide).
Initially, the island wall would be built, 20m above the sea bed, to provide a sheltered marina. Then, complete SMR units – of about 250MW electrical capacity – would be floated in at high tide. The units would be on barges, complete with nuclear island, steam turbines, and all associated support facilities. Once the barges are in place they are ballasted down, and the remaining marina space is filled in with sand – apart from the harbour. Any reactor (up to a height of about 18m) or fuel store is below the island level, protected from the sea by at least 30m of rock and sand, as well as its own protection of metal and concrete.

To accommodate Molten Salt Reactors, the island would be about 230m wide (excluding the sloping sea wall), with a length of 160m plus 160m per Gigawatt (of electrical output). Hence a 4GW island would be approximately 800m long, an 8GW island 1,440m. A Pressurised Water Reactor island would be quite a bit larger. The cost of the “island-works” in 5-10m of water depth (at high tide) would range from approximately £200 million for a 1GW island to £500 million for a 8GW island.

Siting the reactors in offshore islands has numerous advantages:

  • The cost of building the island is cheaper than cost of onshore “nuclear land”;
  • Access to cooling water is easy – the whole island cost may actually be cheaper than the tunnelling works for Hinkley C;
  • The entire power unit – including the nuclear and generating sections – can be factory built and floated to the site;
  • For most designs, the actual reactor core is partly or totally below the high water wave level. This means that unlimited passive cooling can be provided to provide true “walk away safety”;
  • There are no neighbours to upset – and the sites comply with existing Government guidelines on nuclear power station siting;
  • There are a number of suitable sites on the East England coast, from the Thames Estuary up to Lincolnshire. (On the west coast, the heavy tidal ranges would increase the cost of the island – the sea wall cost rises with the square of the wall height).
  • The sites are near enough to shore that HVDC connectors are not required – though they could be built to access more distant connection points on the East Coast or on the continent;
  • If the islands need to be dismantled and the reactors decommissioned, then the marina sand can be pumped out, and the barges can be towed to the decommissioning factory.
  • An island can be easily expanded. If it starts with 1GW of capacity, it can be lengthened to 8GW subject to appropriate sea bed depths;
  • This approach also enables the export of “SMR islands” across Europe and beyond. 250-500MWe barge units could be manufactured in a former ship works and deployed on the coast near to demand centres.

It would however require extensive validation by the regulators in terms of resistance to extreme weather and tidal situations, as well as security. Each site could house 4 to 8GW of reactors, easily bringing the 85GW target within reach.

Figure 6 – Simplified cross sectional view of a nuclear island – “generic” design for SMRs. (One service barge will support a few GW of reactor capacity)

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41 Responses to UK Electricity 2050 Part 2: A High Nuclear Model

  1. Rob Slightam says:

    how about costs?

    • Peter Lang says:

      Electricity cost would have to increase by +30 £/MWh to achieve the UK proposed emissions intensity of 50 g/kWh for electricity (c.f. France – 44 g/kWh). 31 GW of new nuclear capacity and no new weather dependent renewables or CCS would be the cheapest way to achieve that target. The carbon price would be 70/t CO2). See Figure 14 here:

      • Andy Dawson says:

        If I remember rightly, the EPR report explictly didn’t take account scale economies from larger deployments, so if we take a look at that:

        Certainly £60-80/MWh would seem conservative area for average cost across a large fleet such as that proposed. Most technologies show a cost-reduction curve of around 15% for each doubling of numbers, so taking the proposed fleet as an example. We’ll halve that for pessimism:

        Moorside budget cost – £10bn for 3400MW = £3m per MW.

        Wylfa cost £10bn for 2600MW = £3.8m per MW

        We’ll work on the Wylfa number for the sake of caution.

        Hinkley cost £18bn for 3200MW = £5.6M per MW.

        As a rule of thumb, 75% to 80% of the cost of nuclear output is driven by capital and financing cost, so taking the £92.50/MWh for Hinkley, that implies £70 of that should be capital cost driven, and £22.50 operational and other costs. We’ll assume similar operational costs for all three designs.

        Prorating, that implies Wylfa should require £22.50 + £(70 x 3.8/5.6)/MWh = £70/MWh. Moorside about £60.

        The high LWR option above ends with 21 ABWRs – something over three doublings from Wylfa’s original two. It implies units 3&4 (Oldbury) coming in at £65/MWh, units 5-8 at £59/MWh, and units 9-16 (we’ll say 9-21) at £55/MWh. That gives a fleet average of £58/MWh.

        It’s also worth noting that the load management permitted by the heating and EV demand means there’s next to no on-cost for storage and complex grid upgrades.

        What’s perhaps harder to cost is the impact of the low-utilisation back-ups. Working a similar fixed:operational cost model for a CGT units to that above with 80% operational/fuel and 20% fixed contributions to the overall output cost, and assuming todays output price of about £40/MWh on a 65% utilisation, reworked to a 10% utilisation implies a fixed cost of about £50/MWh, plus whatever the then current fuel cost would be. However, the gearing is very low in the overall mix.

    • Alex says:

      We decided also not to cover costs at this stage, as we wanted to focus on the technical paths and to see what is possible. And to be honest, we don’t know what costs of nuclear, wind or solar solutions will be in 2050.

      Section 3 will put nuclear capacities and alternative wind, solar and gas capacities in a side by side table and then it will be interesting to plug some assumptions in.

      • Andy Dawson says:


        What may prove really interesting is what Bradwell B comes in at. CGN is targeting $2500/kW for series build of Hualong in China. I’m sure there’ll be additional compliance costs in the UK, and obviously local costs will be higher, but $3,000-3,500/kW should be attainable. Even at post-Brexit exchange rates that’s comparable or less than AP1000. It puts £50/MWh in reach, even for early units.

      • Mike Parr says:

        The other economic reality: Kreigers Flak (off-shore wind) – being built by Vattenfall for £40/MWh. Just announced.

        • Alex says:

          Not quite. They’re building it for €1.2 billion, or €2 billion / GW capacity.

          Mooreside is budgeted at £10 billion for 3.3GW, which is about €3.5 billion / GW capacity, but will have slightly more than double the capacity factor, and at least double the lifespan. However, the operating costs should be lower.

          The price Vatenfall has is a FIT, so you have to add the export price, plus connection costs, plus the costs of providing backup power. At high levels of wind penetration, Denmark will still need firm capacity to cover about 90% of demand.

  2. Peter Lang says:

    However, spare capacity would be in the summer, and demand for hydrogen will be highest in winter, and storing large quantities of hydrogen is not straight forward.

    Have you considered using the hydrogen to produce synfuels? How much hydrogen can be produced and at what cost?

    • Andy Dawson says:

      Given the lack of real information on the cost of synfuel production, and the probability that it’s of even lower energy efficiency as a process than H2 production, we’ve opted not to go there. It’s also why we’ve assumed the majority of transport being electrified, with H2 or other fuels reserved for the genuinely difficult spaces like long distance road haulage and aviation.

      Obviously, synfuel production as a secondary process downstream of H2 production is likely to be even more expensive per joule delivered.

      • Leo Smith says:

        H2 is highly unsuitable as an off grid fuel especially for transport.
        There are good reasons why the world runs on diesel.

        my opinion, and that’s all it is, is that synthetic hydrocarbon fuel is actually the way forward, if for no other reason than we have a fully fledged distribution network for it already.

        • Andy Dawson says:

          I’d agree it’s an unlikely candidate for aviation – weight and bulk. I’m less convinced that in something like a fuel cell application it’d be a a significant disadvantage to synfuels – plus being easier to make.

          I’d also point out we successfully transport LPG and CNG for vehicle uses – I’ve run an LPG fuelled car myself.

        • Euan Mearns says:

          Aberdeen has a fleet of hydrogen busses. Totally emissions free 🙂

          I agree on synfuel that will only happen with cheap input energy to make it.

      • Peter Lang says:

        The costs of H2 infrastructure would be prohibitive. been looking into this for decades. Synfuel petrol, diesel, jet fuels, etc. is much more likely to be viable alternatives to fossil petrol, diesel and jet fuel than H2

        • Andy Dawson says:

          What would you assume that infrastructure to be, Peter?

          On the assumptions set out I believe it would be relatively limited – cryogenic storage at filling stations/distribution centres for shipping and HGVs. I haven’t worked the numbers, but gut feel points strongly in the direction of that not being materially more complex than tanker supply for LPG/CNG.

          I agree that a nationwide piped H2 distribution system supplying at the sort of scale needed to directly replace natural gas would be problematic in the extreme – but that’s not what we’re discussing here.

          • Alex says:

            To add to that, storing energy as hydrogen is not easy. There’s currently a section on this in Part 3, A renewables / hydrogen economy would need to store about 50TWh of hydrogen. I would guess a nuclear / hydrogen economy – making hydrogen in the summer for heating use in the winter, would involve similar amounts of hydrogen.

            We need to add a bit more on fuel synthesis in that section, in light of the US navy’s progress in this area.

          • Peter Lang says:

            Andy Dawson. Read up on the thousands of studies that have been done on hydrogen, the problems and the costs. We will eventually need a replacement for fossil fuels for transport. Energy Transitions take a hundred years of more. We’ve been looking at hydrogen for a very long time. There is no progress and no sign it can be a viable alternative. However, as the US navy shows, synfuels from cheap energy and sea water could become economic. With hydrogen from high temperature reactors the Navy’s cost estimate of $3-$6 could be approximately halved. No significant change to upstream infrastructure required. I suggest it is a much more likely to be viable than hydrogen.

      • Grant says:


        In an electric world of transport I don’t see a problem with long distance haulage.

        Even if we assume the “vehicles” still have drivers, and I would somehow doubt that for the long haul sections, the concept of “rest breaks” could still apply for the vehicles just as they do now for drivers of the vehicles and, presumably, would still apply in the future if the vehicles are “attended”.

        However when this was a problem with long distance travel by original horsepower a few generations ago the solution was to travel in stages and change horse periodically along the route.

        I would guess that an electric powered fleet of HGVs (for example) would simply pull in to a charging station and swap a complete “tractor” unit for a fully charged unit and then continue the journey.

        It would not be a new concept for the haulage industry and there is plenty of time available to plan accordingly as existing infrastructure is redeveloped.

        Then again will long haul make sense?

        If the sun used to grow, say, tomatoes in Spain or Morocco before transporting them to the UK in refrigerated vehicles were to be transmitted to the UK for the fruits to be grown locally – might that make more sense? If so industrial scale growing centres could be established locally.

        (Food transportation where there is a refrigeration requirement might well justify its own power source and that could well require battery swaps – although costs associate with hauling batteries for millions of kilometers may cause some re-thinking there) .

        Basically (and much to my personal horror) the advent of electrically powered transport options with every movement managed and tracked in real time will be the end result whether people like it or not. Removing the human factors from “driving” whilst tracking everyone and charging by direct real time debits as one moves about will almost certainly become the normal approach. It’s just too attractive for or the “authorities” to turn down.

        Fortunately by the time it really come about I will be either too poor or too dead to make use of the facility.

  3. Peter Lang says:

    Good post. Thank you. I agree SMR’s are the way of the future. I hope UK will get involved in developing and marketing them globally. I think UK needs to find a way to reduce the licencing time and cost substantially.

    • Andy Dawson says:

      Alex and I differ somewhat on that, Peter. I’m not convinced that with a serious attempt to (finally) series build standardised LWR designs the advantages are likely to be anything so clear. Hence the “high LWR” and “SMR” scenarios for wave 2b in the model.

      I’d point out that both AP1000 and ABWR exit GDA in the next 12 months, after which they have no further significant licensing issues, of course.

      • Peter Lang says:

        I wasn’t clear. I didn’t mean to say that all the future builds would be SMr. I agree with your analysis (other than I think it is an extreme high side scenario by 2050 and unlikely such a large proportion of electricity will be supplied by nuclear). My comment about SMR was meant to refer to the longer term. The world will have to go nuclear as we transition from fossil fuels to higher density fuels sources. SMRs are much more flexible in many ways *build time, time from purchase order to first production, reduced investor risk, and ability to fit into small capacity grids in developing countries and to support faster electrification in these countries. That was the point I meant to make, but was to brief. I trust that clarifies.

      • Alex says:

        Once there are four, five or more accridted designs, then auctions can be held for each site. Then we’ll see which technology can build the lowest.

        Between 2025 and 2045, under this scenario, 65GW will need to be commissioned, so one auction per year, for between 3 and 5 GW.

  4. Leo Smith says:

    Yes, not a good post. A Great Post!

    What irks me is that there is more research calculation and sheer common sense here than there ever was at DECC…

    People keep saying ‘well nuclear is expensive’ but its no more expensive than wind, and has far far greater potential for cost reduction.

    The economics are interesting too. The capacity factors worked out above for peaking gas plant are so low it probably looks as though OCGT or diesel would be more cost effective for some or all of the plant. Whereas the opportunity cost of running a nuclear plant flat out versus throttled back are almost zero.

    And that fits nicely with using off-peak nuclear to generate synfuels of one sort or another.

    There is space here for a full cost benefit analysis of a future mix. There should be a simple equation into which cost of capital, capital costs, and fuel costs and O & M costs of all the technologies could be plugged along with a known demand pattern, to output a ‘lifetime cost of electricity’ .

    Hmm. On reflection, its not quite so simple, but there may be a way to do it.

    After I have finished transitioning gridwatch to the new Elexon portal I’ll think about some code for that.

  5. Andy Dawson says:

    “The capacity factors worked out above for peaking gas plant are so low it probably looks as though OCGT or diesel would be more cost effective for some or all of the plant.”

    It’s been an interesting realization, but the leverage of the low-capacity factor plant in both economic and carbon terms can be made so low (in this scenario) that it’s carbon intensity is all but irrelvant – and is fuel/operational cost.

    The optimization requires you to minimise fixed and capital cost for that peaking plant. And yes, diesel and OCGT look like good options (or even, good, old fashioned gas-engines).

    I’m still very cautious about the synfuels path, though. While there are undoubtedly niches where it’s hard to get away from liquid fuels, they’re surprisingly few and electrification wherever possible looks the most attractive route.

    Alex pulled a surprise on me recently in a discussion elsewhere by pointing out that short haul ferries could be readily powered by drive-on/drive off battery packs (I think he calculated that about 30-50 standard container sized batteries would serve to power even the largest cross-channel ferries, constituting less than 10% of the payload.

    I’m even starting to reconsider my long-haul freight argument in part 1; I’m hugely cynical about the “swappable batteries” concepts for passenger cars, but I do think it could be viable for HGVs – where there’s a large amount of space under the trailer with ready access for a swap, unlike a passenger car.

    Which increasingly leaves the only hard-to-reach sectors as aviation, and smaller long-haul shipping.

  6. gweberbv says:

    As I already argued in part I: Burning fossil fuels to generate electricity that is then used to generate heat does not make much sense from my point of view. Thus, the FF plants that are basicly just a backup for skyrocketing heat demand on very cold days should be converted to simple and stupid heaters located in or near to the buildings that have the highest demand of space heating.

    The price tag of a domestic gas heater with 20 kW capacity is something like 200 bucks per kW (probably much cheaper for larger units). OCGT is something like 500 bucks per kW. Plus you would need sufficient transmission lines to cover maximum demand. Plus on cold days air-based heat pumps will produce heat with a very low efficiency resulting in burning more gas at the power plant than what would be necessary when burning the gas directly in the building where heat is needed.

    When considering gas-based heating systems as backup in those buildings with the most heat demand, you could scrap most of your gas and diesel power plants.

    • Andy Dawson says:

      There are some issues with that analysis – while it’s true that the net heat delivery would be less carbon intensive than using fossil fuelled peaking plant , leaving gas distribution infrastructure in place would be hopelessly uneconomic for peaking use alone – and if used more frequently, renders any attempt at decarbonisation looking very sick. If you’re assking householders to pay for and keep maintained both heat pumps for routine heating, and gas heating equipment for sporadic use, it simply won’t happen. They’ll use the gas equipment for preference.

      There’s some justice in the argument around heat pump performance in extreme cold – indeed, Alex and I debated this during the building of the model. I believe there’s an argument for a proportion of that extreme load is more likely to be met by resistive heating (and indeed, there’s also an assumption of a significant contribution from storage heating built in there).

      As to the idea of heat recovery from fossil fuelled peaking plant, that falls foul of the issues of the investment and other cost associated with district heating – the need to install and maintain the necessary local-loop distribution systems. Frankly, if the (huge) investment required for that is undertaken, then there’s afar better source – the nuclear units themselves, which could radically reduce the net capacity. However, we simply don’t see the level of disruption and cost as viable – trenching every street in urban and suburban areas, retrofit to existing dwellings and so on.

      • gweberbv says:

        Andy Dawson,

        I expect that the idea to heat homes at any temperatures with electricity will lead to ‘trenching every street’. Because the ‘last mile’ of the power grid is usually not designed for massively parallel demand from residential areas. During a cold spell a single family home might continousely consume more than 10 kW.
        On the other hand the gas infrastructure is already in place (even the heaters are there!) and needs only maintenance.

        This might be less of an issue in the renewables scenario because when you need to cover every suitable roof with PV installations you also need to make sure that the grid can handle parallel feed-in from a large number of homes with something like 10 kW each.

        The power grid that is currently in place is most probably not able to do that. And the last few miles of the power grid is the really expensive part to replace/upgrade.

        • Alex says:

          This could be a worry. The model assumes that the home needs 90KWh of space heating per day at an average of 0C outdoors. 10KWh comes from appliances, and 80KWh from heating, mostly heat pumps. That translates to a bit below 30KWh of electricity for heating, and 10 for the appliances, per day.

          That could be average of 5KW for each house. Thst might be a problem in older areas with 1960s wiring and 1960s insulation, all be it re-insulated at some point.

          Solutions? How about increase the delivery voltage to 480v and step down at the home to 240v? Or local control of heating – so that the “when” for heating (and vehicle charging) takes account of local conditions.

          A wind/solar scenario would require a 20-30KWh battery in most homes, which would in some ways make the issue easier.

          It’s not a new problem. A few years ago I stayed in a brand new flat in the French Alps. Every flat in the building was heated soley with electric radiators. The building was cold on the day we moved in. At 9am the following morning, the whole block (about 40 flats) lost power. EDF had to come, remove tons of snow, dig down, and fix the line. Then I realised how much France could achieve by replacing resistance heaters with heat pumps.

          • gweberbv says:


            5 kW for each house on the coldest day is a *VERY* optimistic assumption. I am now building a house which comes near a passivhaus and the calculated heating demand at ‘reference outside temperature’ (=-14 °C in my area) is actually close to 5 kW. Even with a lot of additional insulation, new windows, etc. the existing building stock will never come close to that value. Maybe even my 10 kW for a typical single-family home (old building but with some improvements) is still too optimistic.

          • robertok06 says:


            “Even with a lot of additional insulation, new windows, etc. …”

            Well, unless you live in a place which is PERMANENTLY at -14C (Vostok research station?)… then you only need to buy a pellet stove to be used when the temperature drops.
            I’ve built a finnish chalet in the French alps back in 2000, at 1000 m altitude, and have lived happily there, for 9 years, spending a fraction of what my neighbours where spending with fossil fuels heating (propane or oil, as there was no natural gas network there), I use to use something like 10k kWh/year, at the time I had a cheap full-electricity heating/hot water, only the kitchen had a gas bottle (because I had taken it with me from the USA).
            On the very cold days, or when electricity was expensive (“red” days, 22/year, from nov to march, announced the day before at 8 pm) I used to accumulate heat on a 8 cm-thick slab of concrete under the wood floor on the bottom level. The following “red”day I used the residual inertial heat accumulated and/or add some extra nice fire with the pellet stove.
            No special windows, other than standard finnish windows.

            @Alex One of the neighbours had a heat pump (in fact he used to sell them, made a fortune with them and air-conditioning after the deadly summer of 2003), but he was not saving a lot in terms of money… and if the power is out (like in the EdF blackout mentioned above) then the heat pump is off too… not much difference.


            P.S.: I had an 18 kVA contract with EdF, and had installed a “delesteur”, a device which would disconnect some predefined low-priority electric lines in order to avoid a fault on the general switch due to too much power. The accumulation heating on the floor, covering about 70 m2, had 12 kW by itself, if I remember correctly.

          • Alex says:

            In Germany, we have a 6KW wood burning stove. As do, it seems, most of the houses in the village. I’m certainly going to make sure I have a week’s supply of wood in stock – and will probably raise that to a month once the nuclear phase out gathers pace.

            They are certainly a good standby solution, and will help manage the peaks. If 5 million 6KW stoves are running, that takes about 10GW off the peak electricity load.

            The down side – as discussed in Part 1 – is that if those 5 million home owners decide they want to use their stoves a lot more, (1) there’s not enough wood, and (2) local air pollution takes a hit. If there was enough incentive for those homeowners to have the stoves, but only to use them rarely, then that would be great.

            Perhaps the model should accept this reality – rather than trying to be “pure”. However, if it’s easy to build 85GW of nuiclear, and 37GW of peaking plant, why not aim for that?

            The other reality – if we can deliver 120GW of electricity when needed, the gas infrastructure will stick around. This model shows how that infrastructure can be got rid of – and we hold it is desirable to do so. Whether it can be implemented is partly up to the politicians, but more so to the developers and operators of nuclear power plants, insulation solution, electric vehicles, heating solutions and a host of other technologies.

          • Alex says:

            I meant “– if we can’t deliver 120GW of electricity when needed”

  7. Jan Ebenholtz says:

    According to this link will the taxpayer pay for the wastedisposal at Hinkley. Your are the experts and I wondering how trustworthy it is.

    • Andy Dawson says:

      Not hugely.

      As you’d expect with the Guardian, it’s verging on the deliberately misleading.

      The deal for Hinkley is that EDF/CGN carry the risk of overruns on development, and pay directly for decommissioning of the reactors themselves (in fact, the whole Hinkley site). The funds for that are to be set aside in a state managed fund over the first 37 years of operation (of a 60 year design life).

      Over that same period, they pay a fixed contribution to the development of a waste repository. Hinkley waste will be something under 5% of the total volume of waste to be placed in the repository – the overwhelming majority of the waste is material that was generated by the Magnox and AGR reactors while in state hands, plus (the largest contribution) old weapons programme waste.

      As you’d expect, given that the overwhelming majority of the waste is a state liability, the state is on the hook for the construction of the repository. Given that that’s a future programme, there’s no way potential over-runs can be costed at the moment. So, the contribution to be paid by EDF/CGN has been assessed on the basis of a figure that’s 80% probable plus a 25% contingency.

      In other words, the EDF/CGN contribution is considerably above a proportionate share of the probable repository cost.And no organisation is going to sign up for an unlimited liability for a programme that it has no part in managing.

  8. Euan Mearns says:

    Alex / Andy, Interesting to observe that on my 2050 pathway using the DECC calculator I got 90 GW of nuclear close to your 85 GW. It of course makes sense to use some FF or other thermal store to shave the highest peaks.

  9. RDG says:

    Meanwhile, in the real world, more Gazprom gas into Europe proving once again any sort of ‘Energy Transition’ is a farce.

    Someone should take Academia behind the barn and shoot it in the head.

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