Decarbonising UK Power Generation – The Nuclear Option

Guest Post by Andy Dawson who is an energy sector systems consultant and former nuclear engineer.

How to decarbonise UK Power generation is a topic of heated debate, with renewables enthusiasts often keen to argue that there are a range of obstacles to the use of nuclear generation to meet more than a small proportion of total demand. Reasons cited are availability of space/sites, grid integration and the challenges of meeting variable demand. So, is an all-nuclear UK grid (with the small sleight of hand of pumped storage hydro in support) potentially viable?

I’ll set out an argument that it is indeed so, and more so that it comfortably exceeds any current carbon intensity targets.

The basic concepts arose from discussion on the website of the “Guardian” newspaper about the relative strength of fit between pumped storage on one hand, and nuclear or renewables on the other. That led me to do some basic numbers on how much pumped storage hydro (hereafter PSH) you’d need to meet UK daily demand variations on the assumption of a steadily generating nuclear fleet underpinning it. The first pass surprised me on how relatively close we were in terms of total PSH capacity (and in how few nuclear units basic demand could be supplied).

The other realisation was that the constraints on development of PSH are almost all to do with reservoir capacity (and particularly upper reservoir); there are few limits on the generation capacity associated with it (costs aside). If I’ve got an upper reservoir capable of storing sufficient water to give 20GWh of electricity production and a lower reservoir of greater capacity the site is technically viable whether I generate that 20GWh over 8 hours at 2.5GW, or 50hours at 400MW. There’s a secondary realisation in this area – the economics of PSH are crucially dependent on cycling the plant frequently and through the maximum possible proportion of capacity. So, it’s NOT good economics to have PS sitting for days or weeks with water in reserve.

What demand do we have to satisfy?

I’ve reviewed in detail the “Gridwatch” downloads available for 2011-12 at the level of (approximately) five minute reporting intervals. I’ve broken those into Winter (Dec, Jan Feb), Spring (Mar, Apr, May), Summer (Jun, Jul Aug) and Autumn (Sep, Oct, Nov). Recognising that designing for EVERY circumstance would be overly extreme, I’ve truncated these at the 2nd (minimum) and 98th (maximum) percentiles – since certainly in the upper bound case, having fossil-fuelled back up plant addressing peaking loads in such tiny amounts makes no material difference to overall carbon intensity. There’s also a strong economic argument for addressing peaking with plant with a cost profile leaning to (proportionally) minimal fixed and maximised variable cost.

These give (in MW):

Operating pumped storage in conjunction with a stable primary generating source is basically a matter of managing any differentials between primary output and demand by sending power to storage, or drawing it down. The generating (or pumping) capacity of the pumped storage. (i.e instantaneous MW) must be capable of delivering sufficient to fill the maximum deficit between primary generation and demand and ideally, to absorb something close to the maximum surplus. Obviously, over each period of deficit, the total energy available, adjusted for “round trip” efficiency must equal the total to be delivered over that time.

So, let’s look at those maximum surpluses and deficits; we can work on the assumption that we’ll size primary generation to match average demand and then define the surpluses and deficits on the basis of steady primary output to match that average:

Reviewing these two tables brings a few comments to mind:

  • The demand minima vary less from season to season that gut-feel might have led one to expect.
  • The delta between the 98th percentile and the peak is impressively large; however, this represents actually very little total production (on a rough calculation, in the winter period, and assuming that distribution of values above the 98th percentile is flat – a very pessimistic assumption – then it’d represent about 1% of total electricity production in the Spring period. Frankly, for the cost and carbon impact of that we may as well install or retain 10,000MW of CCGT and diesel and run it only sporadically.
  • That the reasonably close match between average and median in each period means we’ll not be too far out in assuming a broadly symmetrical distribution of demand across the day – but this may give us an issue of arising from the need to have higher input energy into storage than the output we can withdraw due to round-trip inefficiency.
  • And that the winter – perhaps unsurprisingly – gives us our “worst case” ; however, we need to modify that assumption slightly as we have a somewhat larger differential between absolute peak and average demand in Autumn.

The primary production issue

At the annual level, if I want to see an average production of 36.5GW, how much capacity do I need? 85% is a comfortable average capacity factor for a Light Water Reactor operating in baseload mode. That includes refuelling outages (for modern designs about 1 month every 18 months, although with advanced fuels that can be stretched to one outage every 3 years or so – 5.5%); it includes an assumption of unplanned availability of 2%, and to stay on the safe side, doubling the total of the two.

36.5/0.85 gives us 43.0 GW of total primary capacity.

Can we accommodate that in existing nuclear sites? All the eight currently licensed sites for new build, with the exception of Heysham are around 350-450 hectares – given that EDF operates six units on 150 hectares at Gravelines, we can treat those as unlimited in space terms. We’ll go through the details later, but 1300MW is an average size for a modern LWR – so that’s around 33 units, or an average of 4.1 per site. So at first glance, it’s possible. There are a few further constraints – for example, Oldbury is constrained in terms of cooling water availability, and generally you’d want to play a few games to balance load across the grid.

But let’s think about what might work. I’ll limit myself to existing designs (i.e. at least with a first site in construction globally, and known to be through, in or entering the UK GDA process), and assume that technologies currently earmarked for given sites are maintained. I’ll also assume a life extension to Sizewell B. That gives the following technologies:

I’m also assuming that the rumoured interest of China’s CGNPC and it’s partner CNNCin the currently undeveloped sites beyond Bradwell is real, and that the travails of the EPR are such that no developments beyond those currently planned will happen (actually, I’ve got my doubts even Sizewell will end up being developed with EPR technology…). That gives us:

Hinkley Point – 2x1620MW EPR currently planned. – 3220MW
Sizewell – 1x 1200MW SNUPPs unit (existing); 2x1620MW EPR currently planned. 4420 MW.
Wylfa – 2x1300MW ABWR currently planned. Double that up to 4x1300ABWR to give 5200MW.
Oldbury – 2x1300ABWR currently planned. Site constraints limit to 3x1300ABWR, so assume a total of 3900MW
Moorside – 3 x 1120MW AP1000 units planned. There are no space limits, but it’s a remote site relative to major demand therefore relatively unattractive to be very large so assume only one extra unit to give 4480MW
Bradwell – large site close to heavy demand. Assume CGNPC/CNPC interest materialises, resulting in 3x 1150MW Hualong-1 units – 3450MW
Hartlepool – large site. Assume CGNPC/CNPC interest materialises, resulting 2x1150MW Hualong-1– 2300 MW
Heysham – space constrained site. Assume CGNPC/CNPC interest materialises, resulting in 2x Hualong-1 units – 2300MW

Which gives us 29,270 MW.

We can add more units at those existing sites, but for grid reliability reasons it’d be best not to over-concentrate. Let’s set an arbitrary limit of four units per site, and assume any new development takes place as twinned units. That gives us a pair of Hualong-1 at Hinkley (given the EDF-CGNPC relationship), an extra pair of Hualong-1s at Hartlepool, and fourth unit at Bradwell – giving a grand total of a little under 35GW.

Beyond this, it’d be better to add some more sites. Where might those be? To start with, let’s rule out Scottish sites, given Scottish Government opposition to new-build nuclear.

The decision not to redevelop Dungeness was to all accounts marginal, and the site enjoys local support. Let’s add that option back in, but assume limiting it to a twin unit site given constraints imposed by the bordering Site of Special Scientific Interest.

For Grid purposes, it’d be good to have more capacity servicing the far west (Wales and the West Country), and another station somewehere close to the Humber Estuary, replacing the “megawatt valley” coal units of Drax, Eggborough and Ferrybridge.

For that former, the obvious sites would be next to the existing (soon to close) coal fired station at Aberthaw, or somewhere like Milford – although the LNG processing site isn’t the perfect neighbour. In either case, a sub-sea connector to Devon and Cornwall would be a useful addition, and improve grid reliability for South Wales and the West Country considerably.

For the Humber station, the most obvious spot would be next to the mothballed CCGT units at Killingholme in North Lincs.

In terms of technology, in order to balance the fleet it’d be best if the additional sites were a mix of ABWR or AP1000; that’d be 2240-2600MW per site.. Let’s assume a pair of AP1000ss at Dungeness and the other two sites as one twin AP1000 and one twin ABWR.

That gives total capacity of 42,540 MW from 34 reactors – roughly the same number that France deployed between 1973 and 1987. Only 500MW short of our 43GW target.

OK, what about the summer-winter variation? Well, that capacity/availability number was very much an annual average. By manipulation of refuelling cycles, we can reasonably assume close to 95% availability in the winter period. That gives almost exactly 40GW available – leaving us about 1GW short in winter. Or, one more site needed. Given heavy Thames valley demand, Didcot would be ideal, but be unlikely to be licensed, so I’ll suggest a pair of AP1000s at one of the Thames Estuary coal or oil sites – Isle of Grain or Tilbury, perhaps? The final grand total is:

Italics indicate not currently a nuclear site.
The map below gives an idea of the geographical spread of the sites:

And a breakdown by technology of:

A good spread of technologies, minimising risk of exposure to flaws in any given design, I think.

The pumped storage requirement

Our basic assumption will be that storage capacity is the constraint. We’ll also, for the sake of simplicity, assume that daily demand is roughly symmetrical around the mean (which is pretty close to the truth, in fact) and describes a sine curve.
In that winter period, for 12 hours a day, demand is greater than the average 41.1 GW. If it’s a half-sine wave over a 12 hour period with a maximum amplitude of 12.6GW that gives approximately 96GWh total demand over that period. On this we’ll be conservative – to keep a useful reserve for general system support, black start and so on, let’s add 15% – taking us to 110GWh.

What’s currently available? Installed and Consented/Planned Pumped Storage capacity is:

We’re about 32 GWh short. However, three other sites, all previously identified and evaluated for development can take us there:

With those in play, we have 127.2GWh of storage. Assuming these are reconfigured to deliver full capacity in either 5-6 hours (Dinorwig, Ffestiniog, Bowydd and Croesor) or 12 hours (the rest), it gives the following generating capacity (MW):

Giving 14.3 GW against that winter demand gap of 11.9GW. There’s also about 1.4GW of conventional hydro available.

Note that giving the Scottish storage units a longer operating time reduces loading on the cross-border interconnectors; allowing for about 4GW of local winter demand, that means about 3GW flowing south; night time MAY be more of an issue, with local demand, minimal basic generation, and up to 7GW flowing north just to recharge the storage. We may need to beef up the interconnectors up to 9GW or so – or add Torness and Hunterston back to the list of new build sites…


So, where does that leave us in the grand scheme of things?

In terms of system capacity – 44.8GW nuclear, 14.3GW of pumped storage, 10 GW of (infrequently used) CCGT and diesel, and 1.4GW of conventional hydro, to give a grand total of 70.5 GW. Against peak demand of 59.2GW, that gives a system reserve of 19% – a far, far better place than we are in at the moment.

In terms of carbon intensity – roughly 98% of basic production is nuclear and 2% CCGT/diesel, which on the IPCC figures of 11g/KWh and approximately 450g/kWh respectively gives just 20g/kWh – comfortably beating the Climate Change Committee’s basic assumption of 100g/kWh and stretch target of 50g/kWh.

In terms of cost, estimates are harder to make; all of ABWR, AP1000 and Hualong show every indication of being considerably cheaper than EPR – so let’s assume a conservative £75/MWh (the aggregate strike price on offer if EDF proceeds with Sizewell C values output from that plant at £86.50/MWh). Some rough calculations on pumped storage undergoing heavy cycling (perhaps the subject of another post…) give something about £30/MWh incremental cost for every unit that passes through them. Gas and diesel costs will be considerably elevated from where those technologies currently sit, given impacts of the need to amortise fixed costs over a small production volume. A working assumption of £150/MWh would seem reasonable. That gives an aggregate cost in the order of £80/MWh.

Now, in one sense, this is only a partial analysis. To be done properly, it needs multiple years of data, and much closer examination of issues like the controllability/variability of demand within the daily cycle and the matching of production to it. There’s also a minor task in validating that the surplus power available at times of low demand matches adequately with the necessary inputs allowing for “round trip” inefficiencies. However, I don’t believe at this stage that those will shift the picture materially, and the “nuclear option” is at very least technically viable.

The bigger issue is that to meet grander decarbonisation objectives, we’d need to factor in both demand growths and considerable changes to the daily/seasonal demand variation. That needs to be the subject of a much larger, and rather more speculative analysis exercise.

Other relevant posts:

Energy Matters’ 2050 pathway for the UK
How to cut emissions, and how not to
The Coire Glas pumped storage scheme – a massive but puny beast

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67 Responses to Decarbonising UK Power Generation – The Nuclear Option

  1. Rob says:

    Can’t most modern nuclear power stations load follow is pumped storage still essential

    For example EPR load following

    ‘between 60 and 100% nominal output, the EPR™ reactor can adjust it power output at a rate of 5% nominal power per minute at constant temperature, preserving the service life of the components and of the plant.’

    • Andy Dawson says:

      They can indeed. The ABWR is particularly good for this, as the recirculation system offers particularly good fine control.

      The issue is less technical than economic; as a low marginal cost generator, it usually makes sense to maximise output from a nuclear unit (to put it more simply, the fixed costs account for the overwhelming majority of the cost of a MWh of nuclear output; it therefore makes sense to absolutist that over as much output as possible).

      In reality, the solution above is unlikely to be the economic optimum – is set out simply as a demonstration of the manageable scale of the development required. There’s a crossover point somewhere between maximised nuclear utilisation and a larger pumped storage fleet, and accepting lower utilisation of a somewhat larger nuclear fleet and a smaller pumped storage fleet. Doing the modeling to establish that optimum would be quite a demanding exercise, though.

      • Andy Dawson says:

        Sorry, caught out by auto-correct there. For “absolutist” read amortized

      • Peter Lang says:


        I don’t regard pumped storage as a near term need. It isn’t needed until nuclear is supplying virtually all baseload. That’s a long way off for GB and most other countries (France is the exception), by which time, I expect, there there will be nuclear plants designed and economic for supplying shoulder/intermediate power.


        • Andy Dawson says:

          Pumped storage has a number of uses, Peter – peaking and frequency support as well as storage per se.

          But yes, the storage and diurnal variation management comes in only at high levels of penetration of high fixed/low marginal cost plant (it’s something else that would have to be worked in detail, but I think something similar would emerge with high penetration of CCS plant, too).

          As to the emergence of nuclear designs where the economics of operating the plant in load following mode become attractive, I’m not convinced that that’s likely any time soon. Certainly I don’t see anything inherent in SMR as likely to push us in that direction.

          • Alex says:

            “As to the emergence of nuclear designs where the economics of operating the plant in load following mode become attractive, I’m not convinced that that’s likely any time soon. Certainly I don’t see anything inherent in SMR as likely to push us in that direction.”

            And, there are two routes to making this happen:
            1. Make the capital cost of the plant low enough that you can afford the plant to be idle over the summer. MSRs certainly have that goal in mind, though how successful they’ll be is open to question.
            2. Make a plant that can switch to providing process heat. The answer to that is as above.

          • Andy Dawson says:

            The problem with that process heat option it’s”what do your process heat customers do when the plant is in generation mode instead”?

            You’ve just basically pushed the plant utilisation problem down the line into them.

          • jim brough says:

            The Snowy Mountains Hydroelectricity Scheme in Australia is an asset built in the late 1940s and the 1950. It was built with pumped storage from coal-fired power stations and it worked.

            Peter Lang made a study some years ago about the economics of using wind or solar electricity to pump water up to the reservoirs to provide reliable electricity supply.

            I suggest that you study his analysis and consider why this dry continent of Australia makes more hydro-electricity per capita than Germany. Look at IEA stats available on line.

          • Andy Dawson says:


            We’re not entirely without pumped storage experience here in the UK, you know….:-)

          • Alex says:

            Andy, good question. Two answers:
            1. Heat is much easier to store than electricity. So you could build up heat overnight, for use in a 24/7 plant.
            2. We might find an energy intensive, low capital cost use such as hydrogen production, which could be carried out in the summer.

            We’re some way off this, but then it’s not an issue until 2030 or 2040.

          • Olav says:

            I agree with Alex here.. Heat is much more easy to store. A rector can continue during low demand at rated capacity while some of the heat is stored. The stored heat is almost “free” allowing for a capacity delivery plus stored heat when demand is high, The price differential is then the “peak price!” which may cover the storage cost.
            A storage of 280 MWth has a footprint of 4400m2 and cost 50 million US $ This has to be located close to the turbine hall only requiring minor O & M from staff already on site. In out efficiency is above 95% and heat loss over 24h is less than 1%.
            Looks better economically than PHS for me and siting is ideal. Footprint is limited so a 10x size is a possibility.
            This is the “Flat Land PHS” with 95% efficiency as long as you go the heat to heat path, and free charging cost is given as “reactors” like less load following.

          • Andy Dawson says:

            On heat and storage…

            Yes, and no. The obvious first point is, if you plan to store heat, from a thermodynamic perspective, you’d obviously take that directly from the reactor – which implies on-site storage capacity.

            That’s when you start to hit questions. Obviously, you’ll be storing at best at the primary circuit temperature of the reactor. Less any losses in initial transfer, and subsequent losses to the environment.

            Now, when you then need the generation, you’ve obviously already committed your normal version capacity; so you’d need additional, low utilisation stream raising and generation captivity to use the stored heat. That’d be technically similar to stream plant for conventional generation – not responding well to short term cycling either in terms of plant life or efficiency.

            Now remember, the efficiency of the generation using the stored is a direct function of the temperature of that heat.

            All in all, I’m a long way from convinced that you’ll end up with a significantly better result than the round trip efficiency than pumped storage, and particularly in terms of cost efficiency.

          • Andy

            I have to agree on the storage of heat. There just does not seem to be an easy way to store it for long periods without a significant capital cost and losses. I see schemes proposed like the link below and you start building storage plant of similar footprint to the actual plant.

            Hence that is why distributed systems using heat have cropped up as opposed to storage at homes or on the utility.


        • Bill Schutt says:

          Doesn’t it make more sense to after building a suite of nuclear baseload reactors, to build a second suite of reactors as hydrogen generators/electricity back-up. Most of the time, they will generate H2, but when demand is high, or there’s no wind, they can provide electricity back-up.

          In Australia and the US, biut not necessarily the UK, I would then build a 3rd suite of reactors as water desalinators/back-up electricity generators.

          • Andy Dawson says:

            Frankly, no.

            The costs of H2 generation as a storage medium, compared to pumped storage, in both unit and capital terms are prohibitive. It’s not even as though there’s a significant advantage if the energy is used in EVs, our as a heating source (assuming the use of heat pumps).

          • Alex says:

            I agree that H2 as a storage medium makes limited sense. However, I can’t see us entirely getting rid of hydrocarbons for a very long time. These hydrocarbons could be made from H2.

            Of course, to be viable, the H2 has to come heat, rather than from valuable electricity. Whilst this might be feasible using solar thermal power, it will probably be easier using nuclear.

  2. Euan Mearns says:

    Andy, its useful to have a template like this one to see the scale of the challenge. And I like you I believe the challenge is not that great. In my 2050 pathway I had 90GW of nuclear, but that included decarbonising heat and transport too.

    This is how my Coire Glas post ended:

    My 2050 pathway, that I hope to present to this forum soon, currently includes 90 GW of nuclear power plus 4 GW of pumped storage that I envisage being deployed along the Great Glen in sites similar to Coire Glas. This scheme goes some way towards providing that – a good hedge for SSE. Pumped hydro for Nuclear requires more muscle and less stamina and so I wonder if the Coire Glas scheme could be adapted to provide 2400 MW for 12 hours? Turbulent times perhaps for Loch Lochy. Delivering 2400 MW for 12 hours every day seems much more valuable than 171 MW for a week – though I wonder if the battery could be charged in time?

    One issue here with pumped storage where the lower reservoir is a natural lake is maintaining water levels within prescribed limits. Using a facility like Coire Glas on a diurnal cycle, it would of course make money, probably lots of it. But trying to use this as a store for wind energy on a weekly or longer cycle is simple Green pipe dreaming which is why funding has not yet been approved.

  3. Alex says:

    A good analysis. Though perhaps optimistic for nuclear designers, and pessimistic for bill payers.

    I can’t see Sizewell going ahead with EPRs. EDF – if they commit to Hinkley – will have their hands full for a long time to come.

    The Government’s primary strategy is to get about 16GW of new build Gen III+ in place by 2030. This will probably be made up of EPRs, ABWRs, AP1000s, and Hualongs.

    Beyond 2030, the strategy is also to electrify transport and heating. If successful, these will add about 40GW to winter demand and 20GW to summer demand. (These numbers are speculative – and really should form the basis of research and a new article). Given that there will be reasonable flexibility over 24 hours as to when cars are charged and homes are heated, we might be looking at a peak demand of 90GW.

    We could live with more AP1000s at £70/MWh (price by the dozen?), but beyond 2030, I think DECC is hoping for SMRs to take the strain. These come in two flavours:
    – PWRs. Basically, no new technology, just looking to get factory economies of scale. For example, NuScale is targetting $5,000/KW.
    – New technologies, probably molten salt reactors, though not to exclude liquid sodium.

    Don’t be fooled by the term “small”, and articles in the press saying they could be put in towns. These reactors will be grouped in clusters – probably of 3-6 GW. Their footprint is similar to PWRs, and they have less issue of waste heat rejection which can ease some siting issues. It would even be feasible to build them in 8GW offshore islands in the North Sea – well placed to export electricity to the continent.

    For better or worse, the UK will also have a few 10s of GW of wind to try and integrate, and perhaps 20GW of solar capacity. The latter is irrelevant in the winter, but adds an average of 4GW of average power in the summer. So we might need 80GW of nuclear supply in the winter, and 55GW in the summer.

    For reference, France already has over 60GW of nuclear capacity.

    • Dave Ward says:

      “It would even be feasible to build them in 8GW offshore islands in the North Sea”

      Given that this option could be years away, there is a good chance that many of the currently installed wind farms will be rotting hulks by then. The existing cabling and onshore grid connections would make “repurposing” these sites an obvious answer.

    • gweberbv says:


      what is missing in your picture are the (additional) interconnectors that are going to be build within the next 3 to 7 years. These will put every new plant at competition with the existing fleet of power plants on the continent.

  4. Andy Dawson says:

    Thanks, Euan.

    I’ve been doing some similar number crunching concerning a larger scale system sorting decarbonised heating & transport, and it leads to some interesting conclusions.

    The first is that with sensible load management for EV charging, and low delta-T heat pumps as the dominant form of heating, diurnal load variation can be all but eliminated. That’s without the need to draw power back from EV batteries

    The second is more difficult, though – and that’s the impact of heating load on seasonal demand patterns. With a primarily nuclear suppy it’s partly offset by managing refuelling and other outages to be biased to the warmer months, but even allowing for that it’s hard not to see a five-ten point hit on attainable capacity factors

    On the pumped storage cycling issue – I couldn’t agree more. It’s not hard to model the costs of a pumped storage unit like Coire Glas. On sensible assumptions, fixed costs (in the form of capital and financing costs) are of similar magnitude to variable (mainly the cost of power losses in the “round trip”); which obviously introduces a strong need to maximise utilisation and output to spread those fixed costs over as many units of output as possible.

  5. Peter Lang says:

    I am surprised there is no reference to and no acknowledgement of the recent ERP report:

    The results presented in the ERP report show all or mostly new nuclear capacity is likely to be the cheapest way to decarbonise the GB electricity system to meet the recommended 50 g CO2/kWh target. This post explains: Is nuclear the cheapest way to decarbonise electricity?

    The ERP analysis used the central estimates from the DECC commissioned Parsons and Brinkerhoff reports (17 July, 2013) here:

    • Peter Lang says:

      Excerpt from my post here:

      “The most significant points I draw from the ERP report with respect to the least cost technology mix to reduce CO2 emissions are:

      Weather-dependent renewables alone cannot achieve the UK’s targets for decarbonisation of the GB electricity system.

      All or mostly nuclear power gives the lowest CO2 emissions intensity for lowest total system cost.

      Hydro (if suitable sites were available) would be the most cost effective at reducing emissions. Since additional hydro capacity is very limited, adding nuclear is the cheapest way to achieve large CO2 emissions reductions.

      31 GW of new nuclear and no weather-dependent renewables or CCS would achieve the recommended 50 g/kWh target at lowest total system cost.

      32 GW of new nuclear and no weather dependent renewables or CCS would achieve the same CO2 emissions intensity of electricity as France achieved in 2014, i.e. 42 g/kWh.
      Wind, marine, and CCS are expensive and ineffective.

      Pumped hydro is very expensive and ineffective. Any other type of energy storage would be more expensive.

      The worst option of all is to close old nuclear plants; doing so would increase emissions and total system costs. Their life should be extended if practicable.

      To achieve the same CO2 emissions intensity as France in 2014 would require a £70/t CO2 carbon price plus ~4% increase in total system cost.

      A £70/t CO2 carbon price alone would not be sufficient to drive the required changes in the electricity system to achieve the government’s target.”

    • Andy Dawson says:

      It’s a good piece of work, Peter, and one I’ve recommended to others elsewhere. However, my objectives were a touch more limited – a simple feasibility demonstration to counter claims made by the anti-nuclear lobby!

  6. Leo Smith says:

    Andy: what happened to CANDU?

  7. Gaznotprom says:

    Brilliant article & comments!

  8. A C Osborn says:

    The only thing wrong with the article is that there is no need for “decarbonisation” at all until FF prices make it uneconomic or stocks are close to exhaustion.
    It is based on a false hypothesis and increased CO2 is doing the whole world a great service, which even the BBC reports.

  9. RDG says:

    All I see are paradoxes. Example: Fossil fuels are cheap yet we cannot afford them. In fact the “renewables” crowd has shifted from being complementary with natural gas turbines to eliminating fossil fuels altogether because its so “cheap” (solar growth is exponential). Apparently cheap ng powering houses and cars is a falsehood as well.

    Something doesn’t add up. Either the interconnected central bank model is not reporting accurate numbers (much greater debt) and is very insolvent or the big oil fields are about to enter rapid decline due to advanced oil recovery methods pushing forward increases and maintaining production for as long as possible. Perhaps both.

    I guess if the current economy is axing workers with automation because we are broke, it begs the question: whats the point of nuclear reactors if we cannot afford coal fired electricity? Its as if the entire fossil fuel powered housing stock is a writeoff. Surely nuclear isn’t an option in that case.

    I bet a lot of Germans are leaving the Energiewende and are headed to the Caliwende. California has sun, Germany does not.

  10. Pingback: What Energy Policy | windfarmaction

  11. publius says:

    A while back, I did a little algebra, & came to the conclusion that feeding a constant load from a non-constant source was economically unappealing, if not ludicrous — that serving a 1 GW load with wind at 30% capacity factor would require a pumped-storage facility with a generating capacity & annual generation roughly equivalent to Hoover Dam (which probably means a great deal more to an American). See here :

    I’m surprised, though, not to see a discussion of nuclear district-heating schemes, as advocated by Diamant. Con Edison in New York has had some success with getting building owners to install chiller systems driven by absorption-cycle heat pumps fed from their New York steam system, thus greatly improving its annual utilization factor, & curtailing the summer peak electrical load.

    Realistically, of course, a programme for large-scale new nuclear build on this scale would probably not all be done with existing reactor designs. If Bennett Lewis of AECL is to be trusted, for instance, at roughly 1500 MW(e), the heavy-water investment per kW(e) of a CANDU can be reduced from about 800 to about 150 grams, & the pressure-tube design concept is very favourable for series production.

  12. stone100 says:

    Is there any hope that nuclear could combine well with liquid air energy storage? Liquid air energy storage perhaps could make use of the waste heat from nuclear plants.

    • Andy Dawson says:

      As compared to pumped storage?

      Do the numbers. Why would it be smart to use a system that’s got huge thermodynamic disadvantages, as compared to the low hanging fruit of a week proven system.

      This is where we’ll miss David McKay. Numerical common sense

      • stone100 says:

        Liquid air energy storage would avoid the need for beefed up interconnectors to the suitable pumped hydro sites in Scotland. They claim that 70% round trip efficiency is possible from liquid air energy storage. That would be competitive with pumped hydro wouldn’t it?

        • Euan Mearns says:


          Refs please. And perhaps a summary of the thermodynamics wouldn’t go amiss.

          • stone100 says:

            The key thing is that a cold store (such as a gravel bed) stores cold from the evaporation stage and reuses it for the liquification stage and also that the evaporation stage makes use of what would otherwise be waste heat from a thermal power station. Nuclear and fossil fuel power stations currently throw away GW of waste heat. This harnesses that energy.
            There is a 5MW pilot plant in Manchester due to open later this year that will work in conjunction with a landfill gas power plant. It is only testing the evaporation stage though since it uses waste liquid nitrogen from a liquid oxygen production facility. Obviously that is a low hanging fruit and there is not an unlimited supply of waste liquid nitrogen.

          • Alex says:

            That sounds like interesting technology.

            However, if we move towards an electric future, then heating and vehicle charging are sufficiently flexible (without V2G – Vehicle to Grid), that the demand can be made fairly flat over the 24 hours period. So, we don’t need much CES, beyond the pumped storage we have. (We need the pumped storage for the very fast variations).

            There is a problem that heating is not needed in the summer. So we have 20GW less demand in summer than in winter. Can CES help with that? I think not.

            If we introduce a significant element of renewables into the mix, then we do need significant storage on a 24 hour basis – and more problematically on a weekly/monthly basis. In this case, then CES with nuclear plants sounds like a reasonable solution, though I would prefer someone to develop high temperature hydrogen production.

            Of course, the wind advocates will claim that the cost of the CES is entirely down to nuclear, and should therefore be lumped onto the cost of nuclear (After all, it’s next to the nuclear plant! – Which is why the UK’s diesel plants that have recently won capacity auctions really ought to be sited next to the wind farms they support).

          • stone100 says:

            I just found this: Y. Li, H. Cao, S. Wang, Y. Jin, D. Li, X. Wang, et al.
            Load shifting of nuclear power plants using cryogenic energy storage technology
            Appl Energy, 113 (2014), pp. 1710–1716
            Abstract To balance the demand and supply at off-peak hours, nuclear power plants often have to be down-regulated particularly when the installations exceed the base load requirements. Part-load operations not only increase the electricity cost but also impose a detrimental effect on the safety and life-time of the nuclear power plants. We propose a novel solution by integrating nuclear power generation with cryogenic energy storage (CES) technology to achieve an effective time shift of the electrical power output. CES stores excess electricity in the form of cryogen (liquid air/nitrogen) through an air liquefaction process at off-peak hours and recover the stored power by expanding the cryogen at peak hours. The combination of nuclear power generation and the CES technologies provides an efficient way to use thermal energy of nuclear power plants in the power extraction process, delivering around three times the rated electrical power of the nuclear power plant at peak hours, thus effectively shaving the peak. Simulations are carried out on the proposed process, which show that the round trip efficiency of the CES is higher than 70% due to the elevated topping temperature in the superheating process and thermal efficiency is also substantially increased.

  13. stone100 says:

    Is it obvious why the UK hasn’t chosen the APR-1400? The UAE seemed to think it was the best choice of the available reactor designs. In Korea, they actually have an APR-1400 completed and running and apparently are on track with building the others. Am I missing something?

    • Andy Dawson says:

      The UK hasn’t “chosen” any design – it’s open to proposals by developers to build reactors, subject to them passing the Generic Design Approval (GDA) process, securing a site and then completing the (not overly complex) site specific approval process – the complexity is in the GDA.

      No developer has made an application to enter the APR-1400 into GDA.

      So far as I can see, the design would need some revision to pass UK(and EU) safety standards; the containment requires a separate shield structure outside the pressure bearing containment. Beyond that, I can’t see anything major – it’s already got the requisite levels of redundancy in the safety systems (“N+2”), has a vessel cooling system which should prevent melt-through, and has some “passivity” built into the design, although not as much as a “best in class system like AP1000.

      It’s a very competent design; simpler than an EPR, but still very much evolutionary.

  14. steve says:

    You did not include the Finnish consortium option at Fennoviola for a modified Russian design VVER which, according to World Nuclear Assn will produce at £40/mWh and has been approved within the EU. The design is well tested and EOn started the process. Could you explain why this much less expensive option is not considered for Hinkley, Bradwell and others when the Finns have given up on EPRs? There must be some reason.

    • Alex says:

      The main reason is that the VVER isn’t planning to go through FGDA approval.

      The reason for that is because it’s acceptable to have a Russian designed power plant in the UK, largely due to fears of energy security and Russia’s attempts to restart the cold war.

    • Andy Dawson says:

      As Alex has stated, because no-one’s submitted VVER for GDA. Incidentally, there’s no such thing as “EU approval” – that’s only a general statement of compliance with a number of design requirements, not a full PSA and so on.

      At headline level, I’ve no particular reason to think there’d be a GDA issue, except Rosatom doesn’t have any particular experience of taking designs through western safety accreditation processes. I’ve a feeling that there’ll be some tension with STUK, the Finnish equivalent of the ONR. Looking at where else VVERs have been sold, and with Russia’s lack of an independent regulator, I doubt very much there’s a proper documented safety case yet in existence.

      CGNPC is in a similar place with it’s Hualong proposal – except they’re partnered with EDF to support the design through UK accreditation. In fact, there are notable similarities between Hualong and the AES-93 variant of VVER.

  15. steve says:

    The VVER seems to be partnered by EON in Finland and I doubt they would have started the groundworks if safety approval was in doubt. I read somewhere that the Germans were half way through building similar reactors when Mrs M had another of her moments and went for lignite. It would have been useful to have a competitor costing half as much as the EDF edifice. Perhaps EOn could partner in the UK. The cold war seems to be a result of two competing sides and they still meet and shake hands when it suits them. The site is owned by EDF, using RBS loans, but we could always give ourselves planning permission for an adjecent site.

    • Andy Dawson says:

      Your well out of date, Steve. EON’s pretty much on its last legs, and certainly out of the new nuclear game

      • steve says:

        Well, Rolls Royce is reported to have reached agreement to provide safety systems for the VVER at Fennovoima. Google Fennovoima project and go to media. The link doesn’t work. Maybe Rolls would be able to transfer the STUK work to avoid duplicating it for GDA. At 40/92.50+inflation it sounds like a bargain, especially as this and other designs doesn’t have a defective steel reactor casing and valve faults.

        • Euan Mearns says:

          I meant to ask Andy about Rosatom. Is Russian technology really off the menu when Chinese involvement is not?

          • Alex says:

            As I understand it, Rosatom wanted to submit their design for GDA, but primarily to help market the product elsewhere. For now, GDA is limited to companies who want to build reactors in the UK, and for this reason Rosatom was excluded.

            It is unlikely that Rosatom would be able to build a reactor in the current political climate.

            Why does this apply to Russia and not China?
            1. UK currently has better relations with China than with Russia. It doesn’t help that Russia has used it’s nuclear program to murder a dissident in London.
            2. China, unlike Russia, has no history of trying to use energy for political purposes – though it has used – for example – rare Earth metals to try and gain commercial advantage.
            3. As a major supplier of gas, Russia is already in a position to cause energy disruptions in Europe and the UK. China isn’t.

            An interesting question: Hualong was selected for GDA in return for China backing Hinkley C. If EDF wimp out, does that deal still stand? Or does it become important to build Hualongs at Hinkley (and later across France)?

          • Euan Mearns says:

            China, unlike Russia, has no history of trying to use energy for political purposes

            Do you have any examples of this? That is Russia using energy for political purposes.

          • Alex says:

   for a non-Ukraine example.

            Of course, Ukraine is a bigger example. Whether you claim that is down to commercial or political issues is irrelevant, because Russia is perceived as an unreliable supplier where perception of reliability is crucial.

          • Euan Mearns says:

            The spat over Ukraine is clearly 100% commercial. If Russia doesn’t want to supply Ukraine because Ukraine has been steeling gas then Russia must surely be entitled to do so. It is then an act of extraordinary stupidity on behalf of Poland and Europe to try and slip Russian gas in the back door.

            Russia in fact by building S stream and N stream was investing vast sums to circumvent the Ukraine problem. Just that certain European leaders wanted to do all they could to prevent the problem being solved. In fact they went out of their way to make the problem worse that led to the civil war.

            Russia has been an incredible reliable supplier of gas, oil and coal to Europe for decades. Even throughout the cold war. If there are perceptions of unreliability then this comes down to the stupidity of certain European leaders, especially in Germany.

          • Syndroma says:

            Rosatom has an active interest in the UK nuclear market. As soon as the political pressure clears, it’ll proceed with the regulatory processes.

            Actually, Rosatom nowdays never shuns proper paper work, it was one of the lessons learned from the Olkiluoto 3 tender loss.

          • steve says:

            Dave seemed to be willing to shake hands with Vlad when a Syrian peace deal was necessary, but for some reason not when 1/2price electricity is involved-or 2/3price with `APs.Are they really that daft?

          • Andy Dawson says:

            I think Alex is pretty much right, Euan. Past reliability aside, Putin’s aggressive approach puts paid to the idea.

            Two other elements – first, the GDA pipeline is looking pretty full.The ONR had capacity for two processes running concurrently . On current plans AP1000 exits in Q1 2017 (Q2’s my bet) and UK ABWR in Q4 2017. I think that’ll be on time. Hualong’s due to enter on completion of the AP1000 process. The slot vacated by ABWR will be taken either by the winner of the SMR contest, or (if the decision on plutonium disposal goes that way) by PRISM.

            On that basis, I don’t see another slot opening up ahead of 2021/2 at the earliest. It could be later if both PRISM and SMR go ahead – and the wreckage that’s AREVA’s balance sheet makes it hard for them to fund their proposed MOx plant, thus improving PRISM’s chances.

            If I were to hazard a guess as to the next design into GDA after that, it’d be either CAP1400, or something more radical; an HTR or molten salt design.

            Second, although I can’t find anything formal to this effect, it’s my understanding that entry into GDA is limited to designs with a reasonably near term prospect of UK build. That would imply having a site, or at least being in negotiations for one. All the currently licensed sites for New Build are a combination of EdF owned, or NDA. I’d take some convincing that either would be likely to sell to a Rosatom consortium.

  16. Paul says:

    Thanks Andy for a very illuminating post. What are your thoughts on the S. Korean technology options (OPR-1000 and APR-1400). A recent study seemed to indicate these were the most cost effective reactors

    • Andy Dawson says:

      I’ve commented above on APR1400. It’s an attractive design, sensibly simplified (twin loop instead of EPR’s four), and it complies at face value company with UK standards apart from needing a shield building around the containment.

      It’s worth saying that there’s now no shortage of highly competent designs from Asian vendors on the market (sometimes with western partners, sometimes without). Of the top of my head I can think of the Korean PWRs, two Mitsubishi designs (one a collaboration with Areva), ABWR variants from Toshiba and Hitachi, Toshiba-Westinghouse’s AP1000, Hualong and CAP1400 from China (derived from Framatome and Westinghouse designs respectively), at least five SMR concepts (one that’s definitely going ahead as a floating plant), the HTR that’s being built at Shiadowan, and Chinese collaboration to bring the Terrapower TWR fast reactor to market.

      It’s fair to say that unless one or other of the SMR or MSR designs is a runaway success, the centre of gravity for developing nuclear technology has moved to Asia.

      • Bryan Chesebrough says:

        Terrific post Andy – and by the way, the responses demonstrate that the UK overall has a much healthier discourse on Nuclear Energy than much of what goes on here in the USA.

        I tend to agree with your comment:

        “It’s fair to say that unless one or other of the SMR or MSR designs is a runaway success, the center of gravity for developing nuclear technology has moved to Asia.”

        Although I do think that SMR and MSR designs might just be runaway successes, both of which have significant development players in the UK, USA and Canada.

        Additionally there has been a greater number and more substantive legislation in the US regarding Nuclear Innovation in the month of April 2016 than in the prior 3 decades.

        In the House of Representatives:

        H.R. 4084 – The Research and Development Capabilities for Advancement of Nuclear Energy Act

        H. R. 4979 – Advanced Nuclear Technology Development Act of 2016

        And in the Senate:

        S 2795 – Nuclear Energy Innovation and Modernization Act

        Hopefully this will hasten the re-boot of Advanced Nuclear activities here in the USA that have been initiated albeit struggling for some years now.

        I encourage all of your commenter to visit the websites of:
        Third Way and The Breakthrough Institute, although I have a feeling many may already have.

  17. Edward Kee says:

    Andy: Thanks for this. Engineering economics look good. but who would build this? Would the UK government add PSH to one of the EMR-incentivized reactors? Is this a recommendation for some other country that still has a regulated/government utility that can undertake long-term planning?

    • Andy Dawson says:

      The honest answer is “I’m not sure”. Certainly the market as it stands doesn’t seem conducive to new pumped storage build. The Coire Glas and Sloy schemes are fully consented and approved, and yet their owner (SSE) hasn’t committed.

      Part of the issue may be similar to what’s emerging in the German market. There, pumped storage operators are (counter-intuitively) struggling to coexist with high levels of intermittent renewable penetration. Solar reduces the market for daytime PS production, but in summer only; wind is near random. The economics of PS require frequent discharges of as high a proportion of capacity as possible, to reduce the fixed cost contribution to the unit cost of output. Asking PS to effectively operate for only half the year (solar) or sporadically (wind needing large amounts odd storage that might be called on infrequently) is not viable.

      One thought occurs however, as I think about this issue.The UK’s use of a CfD mechanism should be supportive of storage. The price guarantee means that it will be highly attractive for primary generation operators to produce even when spot market prices are low, which should make surplus generation at times of low demand available to recharge storage. If the storage is itself outside the CfD mechanism, it’s able to take advantage of those high spot prices without a government claw back. It also means that primary generators under CfD have little incentive to boost output (if they were able).

      Following on from that, I think I need to rework my analysis of the cost impact of PS on the system. Having done crude previous numbers on PS, it’s obvious the two primary drivers of cost are capital and finance cost on one hand, and the cost of electricity losses in the round trip process. My initial numbers had been simply done on the basis of the PS operator paying the full CfD price. I no longer think that’s the case.

  18. Is that the Andrew Dawson I used to know at BE? If so, how and what are you doing these days?

    Sorry to come to this article so late – I’ve been very busy this last week; but a great article, very thought-provoking.

    • Andy Dawson says:

      I’m afraid not – my time in the Industry was with the former NNC, and later with Nuclear Electric (my employees of the time, PA Consulting, advised NE on selection and implementing an IT system for maintenance and asset management. So I was part of landing you with “Passport” – sorry!)

  19. Joris van Dorp says:

    Nice analysis.

    Would you comment on the viability of adding even more nuclear, for synfuel fabrication and proces heat? The intent being to maximise nuclear toward 100% of energy while remaining competitive?

    Would you run the cost estimates for such a plan on the assumption that nuclear electricity comes in at ~ $2000 /kW, nuclear process heat at $1000 /kW and nuclear district heat at $500 /kW?

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