UK Electricity Part 3: Wind and Solar

Guest post by Alex Terrell and Andy Dawson:

Part 1 of the series on 2050 electricity demand provided a “high electrification” scenario where the average electricity demand was approximately 72GW, but peak demand on exceptionally cold days could reach 121GW.

Part 2 described how this demand could be fulfilled with a nuclear supply model. In Part 3 we have used the same demand model to show how this could be substantially fulfilled with wind and solar power; though relying on significant amounts of storage to match supply and demand, and gas (or biofuel) capacity to operate when storage is insufficient. A number of different scenarios are explored, with the preferred scenario laid out below, adjacent to the nuclear scenario for comparison.

The main source of energy is wind power, with a capacity of 280GW “land-wind” equivalent. If all of this wind power is offshore, due to higher capacity factors it would equate to 200GW.

Variations to the model have been trialled but do not improve on the solution or are infeasible:

  • Adding realistic amounts of extra storage reduces the amount of gas that needs to be burnt, but makes no difference to the gas capacity required.
  • Adding tidal flow and tidal lagoons in place of wind to the mix results in only a limited reduction in gas usage, and should only be done if it is cheaper than wind power.
  • Converting surplus electricity to hydrogen and back again presents problems of storage and capital equipment.
  • Converting surplus electricity to synthetic hydrocarbons could provide a route to a low carbon supply, but requires development of carbon capture technologies and significant capital expenditure.

There are far more variables to consider than in the nuclear model and therefore further permutations that have not yet been modelled. We have avoided a focus on costs because:

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

It is an easy task to add costs to the model. Agreeing on the costs though would be a more difficult challenge.

Model considerations

The demand target

Part 1 of this series modelled demand and identified 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.

This model already includes a reasonable amount of demand reduction under cold weather, high demand conditions. Therefore it is assumed that supply must meet this demand curve under all circumstances. It is acceptable – though economically damaging – to over produce and waste electricity. It is not acceptable to under produce, especially when people are relying on the electricity supply for their heating.

The Demand Model also assumed some heat is provided by district heating. In a nuclear scenario, we can assume that a small proportion of houses have the bulk of their heating provided by district housing. Wind and solar cannot provide such heating, so we have assumed that:

  • There is a greater deployment of solar heating – including vacuum tube technology that is expensive, but can provide water heating in freezing conditions.
  • The gas that is used is to some extent used in domestic scale fuel cells. These operate at a similar efficiency to the best CCGT plant, but at a domestic scale, their heat can be used more easily. Hence a large proportion of homes get some heat from these units.

The use of these technologies could be modelled further based on a variety of assumptions, but we have assumed they are neutral to the demand model.

Renewables data sets

For the renewables scenario, we have only considered wind and solar, with gas (or diesel or biofuels) back up that we aim to minimise. These are currently the only large scale renewables deployed for electricity generation (with the exception of biofuels). We have modelled the addition of some tidal based upon a mathematical model of tidal output over the month.

With the nuclear scenario, we considered 20 years of weather. However, with wind and solar, we have to match the weather with the historical capacity factors of wind and solar. National grid data sets record wind and solar output, and wind and solar capacity, so we can calculate a capacity factor. However, this is only reliable over the last few years of large scale deployment.

We have therefore used the National Grid records over the years 2012 – 2015 inclusive, to derive four years of wind and solar capacity factors on a half hourly basis. This data provides estimated figures for embedded wind and solar generation that does “not have Transmission System metering installed”. As such, it is national grid’s best estimate. Crucially, it also provides an estimate of installed capacity, allowing a capacity factor for wind and solar to be calculated on a half hourly basis, covering the geography of the United Kingdom.

We merged this data with the HadCRUT data for central England, and our demand model based upon the HadCRUT temperatures. We therefore have, for each day over a four year period, the computed demand, the solar capacity factor and the wind capacity factor.
Over these four years, the following minimum, maximum and average capacity factors were observed for wind and solar, and modelled for tidal and for demand:

Table 1 – Wind, Solar and tidal capacity factors 2012 – 2015. For the purposes of the model, demand and tidal capacity factors are assumed to be level over the course of the day – which will of course require storage and demand shifting to be covered later.

The average capacity factors shown are quite good – given that solar is generally assumed to give 10% in the UK, and Germany’s onshore wind fleet achieves a capacity factor of 16 – 18%.

The capacity factor of wind will increase as more and more wind is built offshore – current offshore farms achieved about 37% capacity factor in 2014, compared to 26.1% for the embedded (presumably all onshore) wind farms. It is not clear whether the distribution of capacity availability will improve – for that we would need to evaluate daily output from offshore wind only, and National Grid does not break this out.

Without evidence that output is less variable, then we can assume that future offshore wind is worth 37/26.1 (= 1.43) times as much as onshore wind. So, for example, 280GW of “onshore” capacity could be replaced by 200GW of offshore capacity.

A note on variability

We have often seen comments along the lines of: “Demand is variable anyway, so the variability of wind and solar is less of an issue”.

Clearly this is not the case. Coupling up a variable supply to a variable demand is more difficult than if one of those if steady. This is especially the case if the variability of the supply is greater than the variability of the demand. To measure the variability, we use the coefficient of variability, defined as the Standard Deviation divided by the Mean. The grid watch data for 2015, and our demand model for 2050, allow the following Coefficients of Variance to be calculated:

Table 2 – Coefficient of variation for demand, wind and solar outputs

Currently, demand has a fairly low Coefficient of Variance of 13%. In the 2050 “high electrification scenario”, it is increased to 19%, mainly due to the seasonal demand of heating. Wind and solar outputs however have Coefficients of Variance of 57% and 65% respectively. Combining wind and solar improves matters a little bit – the combined Coefficient of Variance falls to about 47%. However, the supply variability is still significantly more problematic than the demand variability.

Over production with renewables

To power the UK predominantly with renewables, it will be necessary to over produce and spill (or export) some of the surplus power. The following table shows the amount of production over a 4 year period – based on 2050 demand and 2012 to 2015 capacity factors – for given amounts of wind and solar capacity. The figures are as a percentage of demand, averaged over a four year period.

Table 3 – Percent of demand fulfilled by different levels of wind and solar over the course of a 4 year period.

For a base case, 280GW of wind capacity and 100GW of solar capacity would produce 121% of the UK’s electricity demand, over the four year period.

Wind and solar correlation

Wind capacity factors in the UK are higher in winter – and therefore negatively correlated with temperature. Solar is obviously positively correlated with temperature.

Figure 2 – Correlation of wind and solar capacity factors with temperatures

Wind power is actually over correlated with reduced temperatures – in that it will over produce in the winter and under produce in the summer. Whilst this is a good attribute for the UK, the random element of wind means this is not always the case, and in particular the correlation may not continue at very low temperatures.

Figure 3 – At very low temperatures, the correlation no longer holds, and is indeed (non-significantly) “positive” (which is not what we would like).

We have used data over the years 2012 to 2015, but as an anecdotal point, the capacity factors of wind and solar on Monday 20 December 2010 were 14.1% and 2.4% respectively. This was the coldest day over the last 20 years – with an average temperature in central England of -7 degrees C. If this temperature is experienced in 2050, then according to our model, demand for the day would be 2,905GWh.

Our base renewables supply model assumes 280GW capacity of wind power, and 100GW of solar capacity. On average, this produces 20% more than demand. However, based on the weather conditions of our coldest day, it would have produced 1,007GWh, a shortfall over 24 hours of 1,900GWh.

Renewables scenarios

Base case: Wind, solar and gas

Any shortfall can be made up with gas, or an alternative storable fuel. This could be biofuels, if available in sufficient quantities. However, biofuel might be needed for aviation, shipping and long haulage freight, so, as with the nuclear capacity augmentation, we assume gas will be used. Storage can also help, as discussed later, but in the first instance we will assume no storage beyond that needed to level daily demand.

How much gas? Figures 4 and 5 show daily winter and summer supply applied to the 2050 demand model. This is based on calculations every 30 minutes, assuming that demand is levelled over the course of 24 hours.

Figure 4 – 2050 supply and demand based on winter 2014/2015 weather, with 280GW of wind capacity and 100GW of solar capacity. If there is a shortfall, it is made up with gas (shown in red). If there is a surplus, it is lost.

Figure 5 – 2050 supply and demand based on summer 2015 weather, with 280GW of gas capacity and 100GW of solar capacity. This is calculated on 30 minute intervals – within a day, there can be both excess of renewables and a shortfall made up with gas.

With varying amounts of wind and solar, the % of demand that is fulfilled by gas (or diesel, coal, or biofuels),and the capacity required based on 4 years of weather and capacity factor data, is shown in the following tables. These are based on 4 years of settlement period data, covering over 70,000 data records:

Table 4 – Percent of demand fulfilled by gas over a four year period, with storage.

Table 5 – Gas capacity required to ensure supply based on four years of weather patterns, assuming no storage and demand levelled during the day.

We see that in this instance almost the peak demand has to be covered by dispatchable capacity. Our base case characteristics are shown below:

Table 6 – Base case scenario

Our base case shows gas making up about 20% of supply, and 41% of supply being wasted (or exported). Clearly not a satisfactory end model!

Storage and intra-day variations

Adding a bit of storage to the calculation will improve matters quite quickly, as intra-day variations can be accommodated. However, storage provides diminishing levels of return.
The model caters for excess production to go into a storage reservoir, and this can then be returned. The assumed round trip efficiency is 75%, which is typical for pumped storage. That will also be fairly accurate for distributed battery storage, where there are losses in conversion from AC to DC to chemical energy, and back again. Based on this model, gas usage and required capacity were evaluated for different storage amounts:

Figure 6 – Gas usage and capacity versus different storage amounts

We need to stress that the horizontal axis represents vast amounts of storage. By comparison, Dinorwig has less than 10GWh. Thirty million households, each with a 30KWh battery, would provide 900GWh. In Sustainable Energy without the hot air, David MacKay asked whether Britain could store 1,200GWh with pumped storage – the answer, with a lot of difficulty:

By building more pumped storage systems, it looks as if we could increase our maximum energy store from 30GWh to 100GWh or perhaps 400GWh. Achieving the full 1200GWh that we were hoping for looks tough, however

What Figure 6 shows is that realistic levels of storage have no impact on the thermal capacity required. Based on the demand levels of Part 1 – and wind and solar output from 2012 to 2015, we will need about 104GW of thermal capacity in 2050.

We may actually need more than 104GW. When the storage is empty – which it will be at times – the full capacity is required. The 104GW is based on 4 years of capacity factors, but we need the supply infrastructure to cater for exceptional circumstances. In practice, that will probably require 115GW of available capacity. As in the nuclear scenario, some of this will rarely – if ever – be used, and could be provided by diesel or “mothballed” coal plants.
Although storage can’t alter the required backup capacity, it can improve the amount of fossil fuels burned. Figure 6 is recast below using realistic amounts of storage.

Figure 7 – Gas usage and capacity with realistic storage amounts. The red line indicates a potential inefficiency in running gas plant on a cycling basis.

Note also that we will need significant storage amounts – probably over 100GWh – to enable Combined Cycle Gas Turbines to run for extended periods at optimal efficiency. Otherwise, their efficiency goes down and emissions go up, as appears to be happening in Ireland . The effect of this inefficiency would be to increase the amount of gas consumed, as illustrated by the red line in Figure 7.

Intra-day demand management modelled as storage

The model above assumes that demand is levelised over the course of the day. As discussed in Part 2 (the nuclear scenario), with smart heating systems and a high thermal heat capacity in homes and offices, this is quite feasible.

We can use the same mechanism to shift demand for a renewables scenario. It is more complicated to implement, as heating will applied at – from a user perspective – random times of day, as opposed to regular times. We can model this time shifting as a virtual battery, with the following assumptions:

This is in effect allowing the temperature of homes to be lowered by 1C to store the equivalent of 450GWh of electricity. We can add in commercial buildings, subtract those who refuse to participate, add in those who are prepared for a 2C temperature change etc, etc. For the model, the result is storage – but only available when heating is applied.

Electric Vehicles for storage

Electric Vehicles could in principle provide large amounts of storage, and provide this, vehicle to grid (V2G). 30 million vehicles each with 50KWh of available battery storage could provide 1,500GWh of storage. There are however some issues to overcome.
The first issue is that car owners will not want to provide electricity to the grid if this reduces the life of the battery (it’s an expensive battery, as it’s optimised for weight and power). If the average 50KWh battery needs 50KWh per week (for a 300km range), then 1,000 charges should be enough for 20 years, which is about the lifetime of a car body. Only if the battery life is substantially greater than 1,000 full charge-discharge cycles (over 20 years), will owners accept V2G.

There are then some engineering issues around the grid not being designed for V2G, the need for DC to AC inverters, and the need for the vehicles to be plugged in whenever they’re not being used (as opposed to just at night, in the nuclear charging scenario). These can be solved, but the biggest issue is one of human behaviour. If there is a shortage of energy, vehicle owners will refuse to give their stored energy to the grid, unless they are 100% sure that they can get it back, and they can only be sure if there is standby capacity. Without the reassurance of standby capacity, they will horde energy, just like people horde fuel when there’s a refinery strike, and like people used to horde food in times of famine.
That means V2G can make no impact on the amount of standby capacity required, though it could play a role in reducing the usage of the standby capacity. We could probably assume that some – though not all – owners will join V2G schemes in return for lower tariffs.

Assumed Storage levels

How much storage would a 2050 renewables based supply model require? Any assumptions can be made, and Figure 7 shows the trade-off between storage and gas usage.

Further modelling assumes the following level of storage:

  • 500 GWh from demand shifting – mainly of heat. This is only available when the daily average temperature is below 12C.
  • 500 GWh of conventional storage. This could consist of:
    • 200 GWh of V2G (10 million vehicles offering 20KWh each)
    • 200 GWh of batteries – for example 10 million 20KWh power walls.
    • 100 GWh of pumped storage

With 280GW of wind and 100GW of solar, this reduces gas usage to 12.8% of demand, as shown in Table 7.

Table 7 – Base case scenario with storage.

Adding tidal to the mix

Tidal power could in theory complement wind and solar as its output is not correlated. It is also reliable and predictable far in advance, which wind and solar are not. However, it is still intermittent in two specific ways:

  1. On a daily basis – the peak output from any installation will occur twice per day, with a period of zero output also twice per day.
  2. On a monthly basis – Spring tides are separated by a period of 14.77 days. Typically the neap tide is 40% of the spring tide, and therefore the extractable energy is close to the square of this – or 16%. In practice, it will be less than this as parasitic losses may be constant.

We assume that issue 1 can be resolved by adding storage. This is made feasible by two factors:

  1. The timing of high tides varies around the country.
  2. Tidal lagoons will provide peak power at low and high tide. Tidal flow will provide peak power at mid-tide.

The amount of tidal resource available is not yet known, and depends to a large extent on the costs that can be tolerated. If we assume a capacity of 40GW and a 18% capacity factor (as per the Swansea Tidal Lagoon Scheme), and, to slightly simplify things, that all spring tides are equal, then the daily output varies between 35GWh and 320GWh, with an average of 173GWh per day. This figure is in line with the tidal resource estimates by MacKay and others.

The extra storage required is impossible to calculate without knowledge of the sites and their distribution, and the mix of flow and lagoon, but is likely to be on the order of 1 hour of supply, or 40GWh. This is additional storage to the model.

Figure 8 – Daily electrical energy output from 40GW of tidal capacity. The average output of this is 7.2GW, or 2.7KWh per person per day. This is below the 5KW/person/day estimate of Mackay, but we need to consider what is economic. It produces 10% of demand.

Compared to wind power, tidal has a lower capacity factor – estimated at 18% based on the Swansea Bay data. It is also probably – though it’s early days – more expensive. However, it does have two advantages:

  • Even at neap tide time, the 40GW of tidal produces 35GWh in a day. On a “bad wind day”, 40GW of wind capacity might produce 15GWh or even less (40GW x 1.5% x 24 hours = 14.4GWh).
  • It is not correlated with wind or solar power (as far as we know). It is unlikely that “bad wind days” will coincide with a neap tide. (However, “unlikely” also means “possible” – this factor helps reduce gas burnt – but does not reduce gas capacity).

If we replace 40GW of wind power capacity with 40GW of tidal power capacity (and the extra tidal storage), and apply the outputs to the model covering four years of weather capacity, we see some marginal improvements.

Table 8 – Model output with 40GW of tidal capacity added to replace 40GW of (onshore) wind capacity.

Compared to the wind / solar solution alone, we see marginal improvements:

  • Reduction in gas usage from 12.8% to 12.2% of demand
  • Reduction in average carbon intensity from 80g/KWh to 76g/KWh.
  • A reduction in spill from 34% to 28%

Figure 9 – Daily production, demand and storage figures based on the winter of 2014/15. Note that 1,000GWh of storage can be consumed in a day.

Given the marginal improvements, it probably only worthwhile investing heavily in tidal energy if it can provide electricity more cheaply than wind. On that basis, significant tidal is probably not viable even in a renewables world.

The preferred model

The renewables preferred scenario therefore consists of:

  • 280GW of wind power capacity (or 200GW if offshore). This would occupy at least 20,000km2, and perhaps closer to 70,000km2 based on wind farm densities in the North Sea. The majority of this would be offshore, and the majority of that in the North Sea.
  • 100GW of solar capacity. Hopefully, most of this could be accommodated on domestic and commercial roof space. If in fields, these would need to occupy about 2,000km2. (As with wind farms, most of the land can still be used for agricultural purposes).
  • 500 GWh of electricity storage, or the equivalent of about 50 Dinorwigs.
  • 500 GWH of thermal “electricity equivalent” storage, used as Demand Side response (demand shifting).
  • A thermal fuel (gas, coal, diesel or biofuels) infrastructure with a capacity of 110GW, providing 12.8% of the electricity supply at a capacity factor of 9%. A large proportion of this is domestic / local scale fuel cells, providing combined heat and power.

The output from the model is reproduced here with a side by side comparison to the nuclear base case from Part 2.

Table 9 – Preferred renewables and nuclear scenarios side by side. The slight difference in demand is due to the fact the nuclear scenario was based on 20 years of weather data and the renewables scenario on four years.

We can also vary wind and solar capacities based on this storage amount, to see how this affects the shortfall that needs to be made up with gas.

Table 10 – Gas/Wind/Solar trade-off table assuming 500GWh of storage and 500GWh of heating storage

The emissions of 50.7 Mt compare 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 highly contentious.
Indicatively, this would take up the following amounts of space:

Figure 10 – Indicative map showing the area occupied by the wind farms (in green) and solar panels (in yellow – though the panels would be spread over domestic and commercial properties)

Using hydrogen or synthetic fuels?


From Table 9 above, we can see that we are over-producing by 34%, which is currently wasted (when it’s windy in the UK, neighbouring countries won’t want more wind generated electricity). Can this be used to provide a “hydrogen economy” – either one based on hydrogen, or on synthetic fuels, thereby:

  • Eliminating the need for fossil fuels for electricity
  • Contributing surpluses to provide fuels for vehicles, aircraft and shipping

To do this, two requirements need to be fulfilled:

  1. (Over-production) X (round trip efficiency) > thermal demand. We see from Table 9 that our over production is about 217,000 GWh per year. To produce the 81,000 GWh of electricity that is from gas would need a round trip efficiency of 37.5%. That is not far off what is feasible – we may need to increase capacity by a small amount.
  2. (Electricity-equivalent storage) > (annual storage needs).

Figure 6 shows that if we have 35,000 GWh of “electricity-storage equivalent”, we don’t need to burn any fossil fuels. We can actually get away with less than that if we’re prepared to import fossil fuels in exceptional circumstances. If we’re not prepared to do so, then we actually need a lot more storage, as the consequences of running out of energy are severe.

A solution with hydrogen

The principle advantage of hydrogen is that it can provide large amounts of energy storage – in its liquid form. A 50,000 GWh store would require 2.1 million tons of liquid hydrogen, with a volume of 27 million cubic metres. Storing this volume of liquid hydrogen would be problematic to say the least – an optimal solution might be a network of over 400 tanks, each 50m in internal diameter, and storing up to 5,000 tons of liquid hydrogen. The heat gain would amount to some tens of MW across all sites and would probably not require any cooling beyond that required for liquification. Each site would probably need a source of water for cooling and warming the hydrogen. 5,000 tons of liquid hydrogen has the explosive potential of a small nuclear bomb, so the sites would need to be secure and remote. A possible location for many of the hydrogen storage facilities would be offshore, near to the giant wind farms that provide them with energy. This would also help reduce the transmission costs.

The principle disadvantage of hydrogen as an energy store is that it is inefficient. The process of making it by electrolysis, liquefying it, and then using it in a fuel cell to make electricity is about 36% efficient.

If we increase the amount of solar power capacity to 140GW, then our standard model now looks like this:

Table 11 – Production for hydrogen storage. The excess amount (“spill”) is converted into hydrogen, and then used to provide the “gas”. We have assumed a nominal 12g/KWh “excess” for electricity from hydrogen.

Evaluating storage needs on a 30 minute time base and starting with 48,000 GWh, the storage profile over a four year time frame is calculated.

Figure 11 – Storage amounts for a hydrogen store. GWh are expressed in terms of electrical energy, not chemical energy, assuming 60% conversion efficiency.

From this chart, it would seem a storage size of about 50,000 GWh would be required.

Some considerations:

  • Facilities are needed to convert the hydrogen to electricity at a rate of 105GW, and to electrolyse water at a rate of 180GWe (putting 110GW into the hydrogen store). In 2014 electrolysis uninstalled capital costs were estimated at US$400/KW, with replacement every 10 years. This implies a cost of about £6 billion per year for the electrolysis equipment.
  • Storage of the hydrogen is a major engineering and security challenge, with 400 sites – mostly offshore – each storing 5,000 tons of liquid hydrogen.
  • A hydrogen infrastructure has never been attempted at even a fraction of this scale. The construction and management of the storage facilities would be massive undertaking.

Synthetic hydrocarbons

Based on this, if it is feasible to produce hydrogen from surplus renewables (or nuclear), then it would make more sense to produce synthetic hydrocarbons, using CO2 captured from sea water. The US Navy has prototyped the production of synthetic fuel, using hydrogen produced from electrolysis, and CO2 extracted from sea water. The Fischer-Tropsch process can produce methane or liquid hydrocarbons which can be stored easily in sufficient quantities to even out seasonal demand. It does however lower the overall efficiency of the process.

It should be noted that if we are using solar power to produce transportable hydrocarbons, then it doesn’t make sense to be doing this in the UK. The solar panels would perform better in the desert – and this could be any desert in the world. However, for the context of this document – a UK based renewables scenario – we will stick with 280GW of wind and 140GW of solar (perhaps we can “replace” 80GW of this solar with 25GW of desert solar). If we assume the efficiency of electricity to hydrocarbon conversion is 50%, and from hydrocarbon to electricity 60%, then our storage profile changes.

Figure 12 – Storage amounts for a hydrocarbon store. GWh are expressed in terms of electrical energy, not chemical energy, assuming 60% conversion efficiency.

Due to the lower efficiency, we have dropped a bit below zero. But that is not a major issue as there will still be natural gas available to make up a shortfall.

It would make sense to produce a variety of hydrogen and hydrocarbons, including:

  • Hydrogen, for short term (up to a week) storage and electricity production.
  • Compressed methane, for longer storage (up to a few months) and electricity production, as well as supplemental heating.
  • Liquid fuels for long term storage and exports to the transport sectors.

A synthetic hydrocarbon storage system will require the development of a cost effective synthetic fuel production infrastructure, extracting huge quantities of CO2 from sea water, as well as approximately 105GW of electrolysis capacity. The cost and feasibility of this cannot yet be assessed. However, if renewables prove cost effective enough to make deployment of 280GW of wind and 100GW of solar feasible, then it would make sense to follow through and produce synthetic hydrocarbons using the excess production.

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115 Responses to UK Electricity Part 3: Wind and Solar

  1. Plolov says:

    Simply outstanding. Ever since I became aware of the nuclear vs. renewables debate, these are the sort of hard numbers I’ve been wanting to see. How does a grid, composed mostly of renewables, work in real-time and meet demand over many years?

    My thanks and admiration for taking on a task that government and academia have unaccountably shirked. If this blog ended tomorrow, then it would have succeeded in bringing more light to the UK energy debate than anyone since the late, great David MacKay.

    The only thing missing is cost estimates for the renewables and nuclear scenario. How far do wind and solar costs need to fall to match all nuclear case? Will this be addressed in part 4?

  2. wolsten says:

    Impressive piece of work. A couple of questions:

    1. Has your area requirement taken into account wind shadow impacting performance on that scale?

    2. If we are going to make synthetic hydrocarbons with large amounts of CO2 would this detract from the need to reduce emissions by switching to this complex renewables approach?

    • Alex says:

      @ wolsten,
      1. When I had my project in offshore, I figured out from Danish papers that the maximum capacity you could have in a large wind farm was 10MW/km2. Since then, we are seeing that the very large offshore wind farms are spacing themselves out even more – to avoid losing even a few percent shadow impact.

      In the article, the green box is about 60,000-70,000km2, for 280,000MW, so over 2km2 for each 10MW turbine.

      2. Yes. You’d have to question whether it would make more sense to burn fuel as we do now, and extract CO2 from sea water, and sequestrate it under ground. However, the overall approach is to electrify as much as possible.

      • wolsten says:

        Hi Alex,

        I wasn’t thinking it should be sequestered but that depending on the energy input to the process (I have no idea about this) then it might be considered a form of CO2 recycling along the same lines as biomass – though I understand that biomass has gone out of favour in this respect. Therefore, if the concern is rising atmospheric CO2, would this process be able to make a significant dent in the overall balance?

  3. Joe Public says:

    Another interesting piece, Roger. Thank you.

    1. Under ‘Tidal’, you state:
    “On a daily basis – the peak output from any installation will occur twice per day, with a period of zero output also twice per day.”

    Zero output occurs 4x daily.

    Swansea Tidal themselves state that useful generation occurs only for 14 hours per day.

    2. A few days ago, Paul Homewood wrote a piece ‘Replacing Natural Gas’

    In the comments, I pointed out the enormity of the task:

    “Current max electricity demand is ~58GW; Maximum heating demand is ~350GW

    In comparison, phenomenal quantities of gas are already stored.

    Existing (2016) gas storage facilities = ~51.15TWh

    Withdrawal capacity ~1.926 TWh/DAY Duration up to 67 days

    We have proposed additional storage projects (2016) for 79.2TWh

    Even in the winter, extract from storage makes up only a small proportion of GB’s total gas supplies. Most is from linepack.

    • Alex Terrell says:

      @ Joe – it’s my article (with help from Andy Dawson). Roger picked up some errors, but not this one.
      1. Yes, you’re right. Peak generation will be at two high tides and two low tides, so zero on the four bits in between. This makes day levelling “half as difficult”, but doesn’t impact neap/spring variations.
      2. On replacing gas demand, Part 1 covered that. The primary assumptions being
      i. Insulation improvements continue at current trends
      ii. Heat pumps are used, mostly at a CoP of 3.
      iii. It’s possible to shift heat production in homes over the course of 24 hours.
      Adding the bit on hydrogen/synthetics brought us back to these gas numbers – the storage numbers in the article are in terms of “electric GWh”, rather than “thermal GWh” and are similar to Paul Homewood’s proposal.

      • Joe Public says:

        Thanks. And apologies for mis-attributing the post!

      • Joe Public says:

        “iii. It’s possible to shift heat production in homes over the course of 24 hours.”

        Surely. “It’s NOT possible to shift heat production in homes over the course of 24 hours.”

        That’s why the old Economy-7 electric storage heaters were so impractical. (Except from the ‘leccy generators’ point-of-view)

  4. gweberbv says:

    Thanks a lot for sharing this detailed analysis.

    I think your model with respect to the wind production is a worst case scenario because offshore wind (and when we are talking about much more than 50 GW of installed capacity, this means that most of it will be offshore or it won’t be there at all) should be less variable than onshore wind. Unfortunately, I can only refer to German wind production data but I guess that the situation in UK should be not too much different:
    The green area areas are onshore wind production, the blue areas indicate the offshore production (for January 2016). It is obvious that the offshore production is more stable.

    Maybe you can do a trick to your UK wind data: Set a maximum value for power generation of the existing data and curtail everything what is above this value. Decrease this upper threshold until you reach at a capacity factor of 35% (or whatever value you think is reasonable). By this you eliminate the upper part of the production peaks that are typical for onshore wind and replace them with straight lines which are more common for offshore wind. It is not perfect, but probably the best you can do. Then you can scale up this modified wind production data set to the amount of GW installed wind capacity of your model.

    I would also like to point out that even onshore wind behaves much more nicely when one takes into account the smoothing on a continental scale:
    Nobody knows at the moment, how the European transmission system will look like in a few decades from now. But if only the interconnectors within the first and the second ‘cap and floor funding’ window of OFGEM will be built, UK will have a transmission capacity to its neighbours of about 15 GW already by 2025.Thus, there will be the potential to smooth the domestic renewable production to a certain extend (assuming that the direct neighbours of UK also increase there transmision capacity to their hinterlands).

    • John ONeill says:

      Gweberby, your chart showed wind over 20 European countries varying from 14% to 41%, almost 3x. So two thirds of the total capacity would need to be available as dispatchable backup, since peak demand is at night, so solar wouldn’t be using the lines. Presumably if you took a longer period than 5 weeks, and shorter averaging than daily, the variations would be more extreme. That’s not a good argument for building the enormous grid that would make such long distance transfer of wind power possible.

      • gweberbv says:


        when you look at individual countries for the last few weeks, you will find that wind ouput – even averaged over a few hours – is between zero and ‘something’. So, your variation factor is not a mere 3 but quite close to infinity. Having a powerful grid that extends a few thousand km in each direction is prerequisit for seriously considering wind penetrations above – let’s say – 30% (unless one can somehow access huge storage capacities).

    • Alex says:

      I agree it is somewhat pessimistic. The model assumes that if onshore wind is delivering 2%, then offshore is delivering 1.4 times that, ie, 2.8%.

      That is probably a pessimistic sceanrio, but without half hourly capacity factor data for the UK’s offshore fleet, I can’t assume otherwise.

      The UK wind situation will be different. German onshore CF is useless – 16-18%, so extrapolating from that to offshore’s 37% is not the same as for the UK. The UK’s onshore generation is almost all coastal – because the UK is almost all coastal – so a lot of the benefits of being “offshore” are – compared to Germany – already realised.

      Interconnectors can help – but only to a point:
      1. They’re needed on a massive scale. Within countries like the UK, this happens – we see Scotland’s average demand can be met from the English interconnector. But this doesn’t apply for the UK.
      2. They add another point of vulnerability
      3. If the UK is desperate – people freezing etc – even if Germany is “getting by”, they’ll still be running down their reservoirs or batteries. Will a German politician accept the advice of experts and say “Yes, we can help Britain out, as we only have a 10% chance of facing similar blackouts ourselves”.

      It would help more if the interconnectors go further – Saharan Sun, Turkish hydro and Icelandic hydro won’t be correlated with UK wind. But then we add more costs and more risk and points of failure.

      • gweberbv says:


        contact this guy:

        It seems he has the necessary numbers for UK offshore production:

        I would love to see an rerun of your analysis with an ‘offshore only’ assumption.

        • Alex Terrell says:

          I’ve dropped Andrew Smith an e-mail.

          As you say, to construct the lines in the chart here, he must have the numbers.

          Interesting how straight the blue line is and the fact that it almost goes through the 100,0 point.

          I’ve constructed the same line on the data I have:
          Note that to the right of 20%, both lines are fairly straight and come reasonably close to 100,0.

          If I extrapolate the straightest portion of my line to the X=0 axis, I get about 45%. On his curve – – I get about 65%, about 1.44 difference.

          That would imply that a straight forward multiplication of the CF is not too inaccurate – at least at the theoretical level – especially since we are most bothered by low capacity factors (what the right hand side of the load duration curve looks like).

      • OpenSourceElectricity says:

        Well, as the model is power sales over the border are forbidden – which is as if in the nuclar model it would be required to mine all uranium in UK.
        The existing grid already allows to use turkish power – connection capacity from the european grid to turky is 8GW, as well as power from italy, the western North south connector in germany will improve access of UK to power from the storages in the Alps or from Italy a lot.

        • Alex says:

          “Through interconnection with Greece and Bulgaria Turkey can import 550 megawatts of electricity and export 400 megawatts.”

          If you think getting GW of electricity from Turkey is more reliable than importing small amounts of Uranium from one of dozens of countries (or taking it out of sea water off Cornwall) ……

          If there’s a shortfall in western Europe, nearer countries will suck up Turkey’s exports in the blink of an eye, at the expense of countries further down the line. Who’s at the end of the line? (OK apart from Ireland).

          • OpenSourceElectricity says:

            Well you will find that the capacity entsoe is calculating – bing availabe whith n-1 criteria for systems + corridors and at the worst case of power production and consumption in the grid, and real transport capacity differe a lot, so often trade between countries are far bigger than the official capacities.
            typical examples from french-german border – the major pwoer lines from germany to france pass e.g. along Cattenome and Fessenheim if I remember right. If those two power plants produce at maximum capacity, the additional power which can be sent to the area deeper within france from german territory is low, if these two power plants are producing less, several more GW can be sent over the border.
            The transport capacity to turky as I have read was via 3 corridors and amounted to 8GW (which I did not check in real life at the border) physical flows over the border often exceed the nominal entsoe-capacity at the turkish border as Entsoe-Data shows.

            In the distance like Turky is towards UK, there are also dozends of countries which could deliver electric power to UK. And why should greek /bulgaria have a big need for electric power synchronus to UK and maybe one or two neighboring countries? The assumption becomes more and more unlikely with each county you expect to be in lack of electric power, and soon surpasses the propability of all nuclear pwoer stations in a country breaking down at the same time. At the moment increased power flows from germany in western direction are often compensated by reduced pweor flows towards hungary and increased power flows from poland and sweden. Or if spain exports to France, this is often accompanied by exports from portugal to spain.

    • It doesn't add up... says:

      Here is a chart of the mylly data for most of this year to date:

      (click to see a fuller version in a new tab)

      Lots of variation, even on a Continental scale. The standard deviation is about half the mean.

  5. tom0mason says:

    A massive increase in wind comes with the cost of maintenance, off-shore more so.

  6. Euan Mearns says:

    I have the back of my envelope out to get a handle on Capex:

    Wind: Enercon E82 = £3.1 million for 3 MW = £1.03 million / MW
    Solar: £5000 / 3 kW (expecting to get corrected here) = £1.67 million / MW
    Nuclear: KEPCO APR 1400 = £3.97 billion for 1455 MW = £2.7 million / MW

    Wind: 280 GW * £1.03 million / MW = £288 billion
    Solar: 100 GW * £1.67 million / MW = £167 billion
    Nuclear: 85 GW * £2.7 million / MW = £230 billion

    If we assume 60 year life for nuclear and 20 year life for wind and solar, correcting the latter to 60 years:

    Wind = £288 billion * 3 = £864 billion
    Solar = £167 billion * 3 = £501 billion
    Total = £1365 billion or 6 times more expensive than nuclear

    The different load factors are to large extent accounted for by the massive over-capacity of the renewables model.

    • gweberbv says:


      the last German-Danish tender for PV projects came in with PPA prices below 6 Eurocents/kWh:–denmark-gets-50-mw-of-german-tender-with-bids-of-538-euro-cents-kwh_100027030
      Insulation in Denmark should not be too much different from the south of UK, I guess.

      When we calculate this back to installation costs, we end up below £2500 / 3 kW. (Of course, you won’t build 100 GW of PV capacity from 30 million installations with a capacitiy of 3 kW each.)

    • Alex says:

      Time permitting – I’d like to attempt a cost estimate as a Part IV (Andy Dawson has no time this side of Christmas).

      I’m also keen to keep costs separate. The moment we introduce costs, it gets “political” and people lose site of the requirements – parts 1 – 3 were really setting requirements.

      Some points on the BOTE:
      – I’d probably assume a 30 year life for a wind turbine, after which the nacelle would be replaced. That’s more than 50% of the cost – but I’m not sure to what extent.
      – If we have relative solar and wind costs, we can use Table 4 to move up-right, or down-left, to optimise the mix.
      – I think your solar costs are high. Wind might be low (I think this recent Danish wind farm said €1.2 billion Capex for 600MW).
      – Nuclear: Do we assume EPRs? KEPCOs? Westinghouse SMRs? Or take Moltex costs and blow away everything else?
      – Gas/diesel capacity needs to be added. In nuclear, the 37GW is already covered by the UK gas strategy, but 115GW isn’t.
      – Storage costs – even V2G has a cost. 500GWh of storage @ $100/KWh = $50 billion. (I’ll need to write a formula for number of “cycles” – do Li ion batteries degrade with age as well as usage?)

      • Re wind turbines

        I seem to remember from my ECN days that the tower was about 25% of the CAPEX.

        My ex colleague sent this on
        2013 Cost of Wind Energy Review
        C. Moné, A. Smith, B. Maples, and M. Hand
        National Renewable Energy Laboratory

        The farm you are talking about is Kriegers Flak. According to Vattenfall, this is €1.1 to 1.3 billion CAPEX for 600 MW.

      • Paul Gardner says:

        If you are able to undertake an analysis of costs, you may want to consider as an input the latest BEIS UK generation cost estimates, published in November.

        • gweberbv says:

          Paul Gardner,

          the low-cost estimate for PV in 2030 was just beaten by the recent German-Danish auction. Denmark should be pretty much similar to UK with respect to PV.

        • OpenSourceElectricity says:

          If I look for prices for wind and solar in UK, and in danmark where conditions are absolutely similar, the question for a new blog contribution here should be : How does red tape in UK double costs for wind and solar in comparison to Danmark?
          Seems something is rotten today in the state of UK and not danmark…

          • Alex says:

            That would probably mean talking to Vatenfall or Dong analysts and asking them. A couple of points:
            – The pricing for the Danish and Dutch auctions is still not 100% clear.
            – The UK wind auctions have reduced the level of competition as companies control the respective sites where wind can be built. Only one company can build at – for example, Greater Gabbard (The same issue applies to nuclear. Only one company can build at e.g. Moreside).
            – Certainly the Dutch Government has financed all the site surveys and resolved the environmental issues. It’s “who will bid to build X wind turbines on this site”. (This also allows prices to be fixed a year or two later in the bidding schedule).
            – The Dutch wind farm prices don’t include the inter connector, which is a separate subsidy
            – The Danish wind farms are in shallower water. New UK wind farms are going further (more expensive connector) and deeper (into the 25-50m water depth – it used to be 25m was considered the limit, but 5-8MW turbines are economic in deeper water).
            – The highly competitive nature of the auctions removes any prospect of super normal profits. That leaves bidders highly susceptible to cost over runs or poor weather. If maintenance costs on the offshore turbines are higher than expected, this could threaten DONG’s existence. Compare that to Hinkley where EDF has (perhaps) built in budget surpluses and a very high rate of return.

            Certainly a lot for DECC to learn. We’ll have to see what the next set of auctions do.

          • OpenSourceElectricity says:

            Wchich are – among other – exactly the points which should be looked at. E.g. building the power connections seperately and under control of the grid operator allows in the case of kriegers flak the dual use of this connection as interconnector. Since in UK many wind farms are far out in the sea, and the same happens often from the other coalst, this is a model which could be used too at other sites to provide additional connectios.
            How much more or less reserves EDF has in -hinkley point compared to Vattenfall or DONG is unknown. It was the financial manager at EDF who left the company due to financial risks in the project, not the one at Vattenfall or Dong.

          • Alex says:

            It appears the EDF Finance Director has interests in renewable energy projects outside of EDF.

            Which is more risky?
            – EDF has to build a nuclear plant for more money – by far- than anyone has ever spent on a nuclear plant. They have a budget which is based on Flamanville (everything that could go wrong has gone wrong), with extras added on top.They’ve even had spare time to recruit the best project managers, evaluate in detail what went wrong on other designs, and build the whole plant in computer simulations. And even if they spend all their budget, they get a high rate of return.
            – Dong and Vatenfall have to build and operate offshore wind farms cheaper than anyone has ever done so before. Indeed – at half the price that they agreed a year earlier. And all that with not enough track record to know turbine life expectancy, and without their own sea bed surveys. And the competitive auction ensures a low rate of return is built in.

            Both can be done – but it’s clear which is riskier.

            Auctions are great for getting the lowest rate. But they’re bad for suppliers – as I’ve found out. You can build a great cost model, make efficiency gains, and offer a great price. But then you get under-bid by someone who doesn’t understand the costs involved, makes unrealistic assumptions, has cut corners on quality, or is prepared to make a loss on the contract.

            See example from rail franchising:

    • Leo Smith says:

      Offshore wind is three times as expensive as onshore: last project I looked at was £3m/kW capacity.

      With a 25% capacity factor compare with a nuclear plant at say at least 75%, that is comparable to a £9m/kW nuke.

      Which is about where Hinckley point sits.

      Except that Hinckley will last last 3 times longer, and not need nearly as much backup plant or excess grid capacity.

  7. Capell Aris says:

    You might be interested in two papers I have published with Scientific Alliance/Adam Smith Institute
    Wind Power Reassessed
    and on Solar Power:
    These are based on data extracted from aviation METARS covering the whole of the UK, Ireland and northern Europe (over 40 sites in all) over a period of nine years. They deal with many factors such as production variation, duration, capacity factors, variability, capacity factor, and intermittency. The scale and need for interconnectors and dispatchable plant is covered in greater detail in the second paper.

    In addition there are two papers published in collaboration with Colin Gibson criticising National Grid’s Future Energy Scenarios (2016). IN particular, we address Risk of Loss of Supply and Costs. These can be found at:

    • Alex says:

      Thank you Capell. Interesting reading.

      Out of interest, you reference Professor David Last in Acknowledgements. Is that as in “Loran C”?

  8. Seems to me that solar adds hardly anything. Is there a zero solar option?

    • Alex says:

      There’s always a zero option 🙂

      Redoing the Data Table headings to show 0 solar, and setting storage at 500GWh + 500GWh thermal time shift, and no tidal, gives (after 3 minutes computer thinking) this:
      as the demand fulfilled by gas.

      We can see in all these tables diminishing returns. The more solar or wind we add, the less valuable it becomes. So a bit of solar is actually quite useful.

      If we plug in capital costs, it would give us an indication of whether we should move up and right, or down and left, on the data table. (Or indeed up and left, and go for nuclear).

      • Alex

        Where I am coming from is that using pkbach website data, the ability of solar to complement wind (i.e. solar producing when wind is zero or low) is quite poor for Germany and Spain. So I assume for the UK as well. When wind was generating 10% of its max output (or below), solar was only producing 30% of its total cumulative output.

        I am not sure that solar has much use unless it can compliment as it will be produced in a period of low demand. Adding storage can help but only adds to cost and complexity.

        • gweberbv says:


          Germany has now about 40 GW of PV and 45 GW of wind. Still the PV production has a higher market value than the wind production. And this is easy to understand as demand during daytime is always higher than during night time. PV does not exactly match the demand curve because of the consumption peak around 6 p. m., but it comes quite close.

          That PV seems not so impressive in this simulation is probably due to the fact, that with a fully electrified heating sector you have much demand during the winter time, when PV does not contribute much.

          • “but it comes quite close.”
            A small proportion of its developed electricity does. Most of it does not. Further the German peak is winter months 6-8pm. Peaks in the summer are much lower.

          • OpenSourceElectricity says:

            @dono… Peak today is still at 12:00 in germany. High consumption is between 8:00 and 19:00, which can be adopted with quite small amounts of existing storage. Which are used today in the early morning and in the evening. Most likely pumping at noon, although the exisiting data does not wllow to tell if this is happening. But power prices at noon are lower than in the morning or evening, so allowing pumping at noon (and during night)
            If more PV is installed, ans baseload generation removed, price differences will grow, allowing several more GW of pumped storage to be built, for which planning is already finished – making the morning and evening peaks of residual load smaller for all other forms of power generation

    • Alex says:

      Sorry, lightshot link seems out. Try this:

  9. Dave Ward says:

    I haven’t had time to do more than a quick scan through this post, so apologies, but two observations:

    “And could be provided by diesel or “mothballed” coal plants”

    A “mothballed” coal plant is not going to be available to cover shortfalls without substantial preparation taking weeks or even months. If you need these at short notice they will have to be kept fully operational, and (probably) warm to minimise stresses. At best you could probably shut them down during the summer months, and ready them come autumn. Even diesel engines don’t take kindly to being left unused for long periods. Such plant normally have battery chargers, plus cylinder block and/or oil heaters, which have to be powered 24/7/365, all adding to electrical demand. Most failures of standby generators are those which aren’t regularly tested UNDER LOAD!

    “A thermal fuel (gas, coal, diesel or biofuels) infrastructure with a capacity of 110GW, providing 12.8% of the electricity supply at a capacity factor of 9%”

    As for keeping more than twice our current fleet of thermal plant sitting idle in that way – the question is frequently asked: “Who is going to pay for it”? – both in terms of building these stations in the first place, as well as maintaining them in a serviceable condition year round (or at least, most of it).

    It’s been pointed out repeatedly that if “renewable energy” can’t stand on its own two feet there is no point trying to replace the current system. Sooner or later a brave politician is going to have stand up and tell the public that their familiar “always on” way of life is going to change dramatically. So far none have…

    “I’m also keen to keep costs separate. The moment we introduce costs, it gets “political” and people lose site of the requirements”

    Point taken, but proving that a scenario could work is no good if the costs are astronomical.

    • Alex says:

      Thanks for the input. I’m aware coal plants have this mothballing problem (Andy Dawson has explained it to me). Right now, even if gas provides backup capacity, it would still be worth mothballing the coal plants in case of a systematic shock to gas supplies.

      I wasn’t aware on the diesel limitations.

      Regarding twice the current thermal fleet: This is for a 2050 high electrification scenario, which will need higher firm capacity come what may. But yes, running a huge gas fleet at below 9% capacity factor is going to require a big capacity payment. Say, 120GW x £50/KW/year = £6 billion per year.

      • Dave Ward says:

        Alex – the major problem with “mothballing” ANY large rotating machinery is that of bearings suffering “flat spots” and even the shafts themselves warping. Large ships have to turn the propshafts regularly, even when in port, to avoid this. This would (probably) apply to the largest diesel engines as well, considering many big gensets are based on marine engines.

        “I wasn’t aware on the diesel limitations”

        As above, but the heaters are a sensible (essential in cold conditions) precaution against excessive wear on start up, or even to allow starting at all in sub-zero temperatures. Many smaller sets use the starting battery to power the onboard monitoring and automatic shutdown panel. This isn’t a problem if they used on a daily basis, but will flatten the battery if left for a couple of weeks, hence the need for trickle chargers (see below). The fuel itself has long been affected by the dreaded “diesel bug” which feeds on any moisture in the fuel or tanks, and produces a sludge which will block the entire fuel and injection system if left unchecked. Thanks to “Green” policies, the fuel now contains a proportion of “Bio-diesel” which makes things even worse. This is a further problem for plant only used occasionally.

        But it’s no good if the engine starts, and the alternator doesn’t produce any power, or the control switchgear won’t takeover the load – it happens. A further reason for regular “On Load” testing, which all costs money, and often operator input. A friend has backup gensets at his farms, and normally runs them under load every 2 weeks or so. However one test was missed recently and when he pulled the main switch nothing happened. The starting battery was flat – because, as I discovered, a service engineer had forgotten to re-connect the charger…. Fortunately this didn’t occur at a critical time, but just goes to show that it would be utterly foolish to leave the grid reliant on fleets of diesel gensets, without adequate regular testing.

        I remember reading that one of the plants contracted to provide “Black Start” capabilities failed to do the job in South Australia recently…

        • OpenSourceElectricity says:

          Which is why emergency power diesel provide backup power for very low costs. They get the neccesary starts per year this way while even earning a bit of money with it.
          The insulation of the diesel sngines which are kept warm is quite good, so they do not loose that much energy by this. We regulary build systems like this. The bearings can be designed for a non rotating machine, the machines are derived from ships sngines, but not identical. Ususl start up time for the diesels from zero load to full load is 15-30 seconds. without any preparation.
          Coal power in germany – old lignite plants which have the worst possible start up times – is given 10 days to get the empoyees to the plant etc, and about 24 hours to really start it up to full output. Usual mothballed power plants have to get running much faster here to get a contract with utilities.

        • Joe Public says:

          Hi Dave

          “…….the major problem with “mothballing” ANY large rotating machinery is that of bearings suffering “flat spots” ”

          Heck, large rotating machinery doesn’t even need mothballing to suffer brinelling. All our windmills are designed to give the illusion of production, by rotating slowly during lulls, to prevent brinelling.

          • jfon says:

            If you’re designing plant specifically for rarely-used backup, would it be worth having a vertical axis of rotation ( as is done with hydro ) ?

      • Andy Dawson says:

        Actually, those are very fair points. For coal (or any steam plant), you’ve a cone to keep it “cold”, or if hot to have it “barring” that means slow rotation to prevent hogging or sagging in the rotating plant. The energy cost is minimal, but it does mean having the plant fully manned and operable at any time it’s hot. Dave Ward, below sets out part of why, although from my recall, the warping of the turbine shafts is the biggest issue.

        And yes, the diesel comments also ring true. I recall an anecdote from a nuclear sector colleague who’d worked on the very extended commissioning process for Dungeness B. They’d done a simulated test sometime in the mid eightiesfor an emergency requiring a start of the back up diesels. From what I recall, something like two of the dozen stress fired up – half what was required. Entirely down to long periods of sitting idle.

        • Alex says:

          Can nuclear power stations now get paid to use their diesels as capacity? And would this provide an excuse to turn them on a few times per year?

          This part 3 model shows that UK renewables is going to be heavily reliant on “flexible thermal fuels” for their capacity – and it seems diesels are the cheapest form of capacity.

          If there is say, 20GW of diesel, at the lowest tier of supply (e.g. running 24 hours per year) then there will need to be some way to spread the load, so that each diesel can be fired up once per year.

  10. steve says:

    Thank goodness someone has made an independent stab at working out the consequences of government policy. It is interesting to compare 280GW with the large expansion of offshore to 2020. The Green Investment Bank document fills out the enormous cost of their plans.

    Note. page 6- 10GW by 2020, page 12 23.46 by time all projects finished.
    Page 13- the area of the farms is shown and the area for 280GW would fill the UK side of the North Sea. Page 23- the strike prices are between £140 and £155, but on page 29, they are hoping for £100.( Perhaps they haven’t picked up on what Dong are charging the Dutch.)
    Page 33- £45bn already spent on infrastructure since 2010 and 21bn more by2020.

    A further thought. What happens if we have another Great Unpleasantness with another country which has undersea drones and blows the cables up over a few days?

    The life of the investment is 25 years but in a North Sea salty and very windy environment would not 15 years be hopeful. Navigating a ship through will be interesting. Will they be allowed to tie up to a mast in a gale?

    Lastly. Should ‘district housing’ be ‘district heating’?

    • wolsten says:

      Gordon Hughes at Edinburgh university was talking about an onshore turbine having a life of about 12-15 years from memory. Two of our local wind farms have had fires leading to replacement turbines. One within the first three months of operation and one three years after startup, the latter has also had two new gearboxes in 8 years. A singleton near us has been out of action for a couple of months. It’s hard to imagine offshore being more reliable though perhaps we are just unlucky!

      • Alex says:

        If we do a part 4, we’ll have to factor this in.

        I think the manufacturers are hoping for 20 years. In the Dutch auction, Dong are guaranteed a price for 15 years. If they fail at 5 to 10 years, then Dong are in serious trouble.

      • Joe Public says:

        Gordon Hughes’s paper “The Performance of Wind Farms in the United Kingdom and Denmark”

        The late Prof David MacKay disputed some of Hughes’s findings in his “On the Performance of Wind Farms in the United Kingdom”. Particularly the age-related rate of performance deterioration.

        • Alex says:

          This from Mackay is interesting:

          It suggests a hypothesis that performance drop off is worse in winter. It will be the case that in winter, broken turbines don’t get fixed till the weather improves to allow access.

          • Andy Dawson says:

            I’ve argued this before, on the Guardian pages, but damn all happens on a planned basis on the exterior of oil and gas platforms offshore between September/October and April/May in the North Sea. From what I gather, it was much the same on Morecambe Bay.

            A big platform like any of the Forties installations, Miller, Magnus or God knows what is a massively more stable placement, and better sheltered than the nacelle of an offshore wind turbine. It’s also a far easier place to helicopter into, or get a tender to.

            Bluntly, I’d be staggered I’d significant repair work can happen for half the year.

          • Paul Gardner says:

            Agreed. These factors are already taken into account by the professionals in Vatenfall, DONG, SSE, SP etc.

        • wolsten says:

          I take the point of that analysis Joe though I don’t believe that MacKay factored in the sort of operational issues we see here.

          Scout Moor Wind Farm was commissioned in 2008 and has had a whole turbine replaced due to fire and two have had new gearboxes, the key part of the turbine mechanically. I have looked at the annual data (downloaded from and it was impossible to see for certain the impact of these events. Certainly the gearboxes were replaced impressively quickly, less than a week in each case. The fire caused a downtime of several months for that turbine but even that was impossible to identify.

          Another wind farm further away has been “re-powered”, replacing smaller turbines with larger ones. Thus looking at the output data alone it is very difficult to distinguish gradual degradation against a background of catastrophic failures or re-powering. If the lifespan is assumed to account for replacing whole gearboxes every few years then fine, but it’s a bit like the chap with the old broom he’s had for twenty years and only replaced the handle and the brush on occasion.

          It’s difficult to see how, in an unsubsidised world, such a failure rate would be economically viable, whether gradual or otherwise.

          Today I can see about 100 turbines from various vantage points around Rochdale and only one is turning, presumably on such a calm day to prevent “brinelling” as you mention elsewhere.

    • Alex says:

      The linked document – page 12 – shows UK projects in 2014 –
      Existing: 4GW
      Under construction:1.7GW
      Funded: 5.1GW
      Consented: 7.4GW
      In planning: 5.2GW
      TOTAL: 23.5GW.

      Slow progress towards 280GW.

      Interestingly the E&Y ratings on slide 8 have the UK consistently as the most attractive place to do business. Given the cost discussions in this thread, that’s hardly surprising.

  11. Professor Tony Trewavas FRS says:

    Gordons estimate for half life of turbines at sea was something like four years based largely on Danish experience and as Wolsten indicated replacement of on shore turbines 15 years.These have been criticised of course but tidal has the inevitable difficulty of lifting it off the sea bed to repair and then costs????
    So far as I am concerned costs are crucial. I am still waiting for DECC to estimate the damage in money terms to countryside by erecting turbines. There shouldnt be a single one in Scotland and what is there is a tribute to Salmonds nationalist stupidity. No politician should be allowed anywhere near anything to do with electricity supply. At least we know something about nuclear costs, Hinckley Point is surely an ultimate maximum. Gordon Brown in a fit of ideological madness sold off Westinghouse, their PWR are near half that of EDF. So we know what good nuclear will cost. Why bother with wind or solar there’s enough uranium in sea water to last thousands of years once we have used up the extensive land based reserves and then of course by then thorium will surely emerge. Cost should be the ultimate determinant other things being equal and nuclear costs is half that of onshore wind and a third of that erected at sea once other costs of construction maintenance and integration are incorporated.. Just a reminder that there is a good relationship between the cost of electricity and economic activity.

    • Paul Gardner says:

      The latest UK Government estimates of generation costs were published on the BEIS website in November. By 2020, onshore wind and large-scale PV costs are equivalent to CCGT (with assumptions about gas and carbon prices), and by 2025 they’re the cheapest options available for new generation.

  12. renewstudent says:

    Nice study, as far as it goes. But I see that some offfshore wind projects are achieving around 40% annual capacity factor.s Why do you use a 27.5% wind utilisation factor? That may be fair for on shore wind, but you only seem to adjust the capacity needed if its all offshore down by 80GW.

  13. Svend Ferdinandsen says:

    Denmark is often mentioned when talking of penetration of wind and solar.
    We have not achieved that by ourselves but because we have really large connections to our neighbors, that happens to have a lot of hydropower to compensate for our variating sources.
    And our electricity demand is less than the daily change seen in Norway and Sweden.
    Storage is an expensive way to replace fossil fueled power generation. You need extra capacity for the EV sources, and you need more or less the same capacity from storage or conventional.

  14. Excellent article Alex. It is so nice to finally see a systems viewpoint of the whole grid.
    For the (nearly) no net CO2 emission scenario I expect one would want to store to CO2 emitted when burning and then over time use that stored CO2 to recreate your fuel. It doesn’t change this paper significantly but when you get to costing it may be cheaper to provide a bit of CO2 storage rather than extract very low concentrations of CO2 from the ocean.

    I hope w/in the decade we can see low cost nuclear offered by several vendors (including Moltex and Thorcon).

  15. ristvan says:

    The storage estimates are necessary but make little sense. For example, using 10 million EVs as grid storage means they cannot be driven when used for that purpose. And, driving them means they are discharged and need to be recharged. As UK wind intermittency (prolonged periods of low wind) is associated with winter high systems that can move slowly withmpersistence,, even if the scenario calculations were right the logic isn’t.

    • Alex says:

      Figure 7 allows you to make your own estimates of storage.

      500GWh is feasible – though expensive. The more storage added, the lower the rate of return (the green line slope reduces).

      As for vehicles – some will never agree to V2G schemes, some will. Our “first car” sits in the garage almost all the time. We use it for holidays (that’s a tough one to electrify – might need a range extender), and maybe for short trips every third day when the “second car” is out. It would be ideal for V2G. I could offer the grid a 25-100% state of charge, 90% of the time.

      Other cars might be driving all the time – or parked out of reach. So I’ve assumed a proportion, but it is only an assumption.

    • Alex says:

      To add a bit more – how this pans out with self driving cars is unknown. We could have an extreme scenario where the only cars are only 5 million automated taxis, available on demand. After all, I doubt there are ever more than 5 million cars in use at any one time.

      And 5 million automated taxis is a more efficient solution than 30 million private cars, but it rather blows apart the V2G business case (let alone the auto manufacturers).

  16. Euan Mearns says:

    I just want to notify that my web hosting service wants to increase charges from £239 to £1036 per annum on premise of increased traffic that does not tally with what I see reported by WordPress. I told them to FO. So if the blog disappears you know why. A very f*cked off Euan

    • Grant says:


      Have they invoked the usual “Brexit” excuse?

      I note that all suppliers – especially those with subscription models – seem to be bent on gouging prices to keep the UK “in line with European prices”.

      Total rubbish of course sine that was not the policy back the last time that the £/EUro exchange rates were similar to the recent lows and the rate seems to be creeping back to where it has been for much of the past few years.

      The trouble it that when these companies are market dominating multi-nationals there are few other places to turn.

      Worse still …. they probably pay very little tax AND they will have seen their local (UK) costs decrease compared to other locations.

      Time to find their weak spots I think.

    • wolsten says:

      There is a lot of competition out there since there are no subsidies in the information superhighway. Nice to have a traffic problem though!

    • Dave Ward says:

      I saw a “Blog data limit exceeded” (or similar wording) a few days back. I retried 5 minutes later and had no problem getting the site.

    • steve says:

      My son’s website has to pay per google click. It could be that your blog is attracting a lot of interest from people like me who like to find what is really going on and don’t trust government. I am sure readers could find the extra £800 if necessary. I haven’t paid yet because I hate creating accounts with paypal and don’t buy from sites that use it. If you gave an address we could send a cheque. Extra traffic could mean more advertising income. Ask Donald if he would like to advertise his golf course and send some of the comments on windfarms. He could afford £800.

      • steve says:

        Sonny just phoned about a payment to his site. He said there are a lot of other hosting sites including wpengine. I looked and they had some bad reviews and someone said they pay commission for good ones! Google analytics on costs extra but this is only used by marketing companies.I have been advised to ask someone under 30 if I want to understand how it works. Suggest you edit this one. Best of luck.

    • Euan,

      I have been using a dedicated server with these people for years. ($110/month)

      I suspect you would be better off with the VPS option ($25/month)

      There is no way that your traffic can be more than 15TB/month

      I know nothing about WordPress, but these people seem to:

  17. David McCrindle says:

    Both the nuclear and renewable options (or a mixture of the two) set out here are completely unrealistic. The would require wholehearted government commitment (probably including renationalisation of the electricity supply industry). We have a government which believes in delivery by tinkering at the edges with private sector incentives and changing its mind about those every couple of years. I can’t see this changing in the immediate future, given the other things the government has to worry about.

    It would also require a very authoritarian approach. Forcing people to invest in heat pumps for domestic heating, or change over to electrical cars can only really be done once the grid capacity is there and even then would prove unpopular (just look at how politically difficult it is for the government to nudge people towards electric cars by increasing fuel duty).

    Such a political change will only occur if there is serious stress on the current system (including fossil fuel supplies) which significantly affects peoples lives, remembering that rolling domestic load shedding did not bother people that much during the miner’s strikes of the 70s. We adapted and got used to it.

    In conclusion, unless there is a very large increase in fossil fuel prices, we are not going to meet the governments CO2 reduction targets, though some progress towards them is possible.

    • A C Osborn says:

      How much of the country’s infra structure depended on Computers in the 1970s?
      How many Hospitals were so Electronically sensitive in the 1970s?
      How many people used the Internet and ATM’s to get their money in the 1970s?
      Sorry mate the world has drastically changed since the 1970s and blackouts of any length will be disastrous today.

      • David McCrindle says:

        You are right, in which case one hopes that those responsible for safety and business critical systems have taken steps to provide local back-up. Hospital diesel stations for example. Safety critical systems had back up even in the 70s.

        My point was that 2050 is only 34 years away. If we are to build 85 GW of nuclear, 200GW of offshore wind plus gas back up, or some mixture of the two by 2050, then we need to be starting that now, and in a big way.

        There is no political driver for that now, and perhaps there won’t be, unless we are subjected to the disaster you describe.

        What will probably happen is that we will bumble along and eventually realise that the 2050 target for CO2 reduction is not actually achievable and so will still be burning fossil fuels at levels well above the target.

  18. Rob Slightam says:

    domestic fuel cells?, on nat gas means steam reforming, gas cleanup, fuel cell(expensive metal electrodes?) all in a box the size of an existing combi boiler.

  19. Alex says:

    This exercise could be done for other countries – data permitting – which might have different amounts of solar and wind resource.

    But Germany will have troubles. Take Figure 10, add 25% to the green area to account for Germany’s larger population. Then see how it compares to Germany’s offshore resource.

    Not good…..@ Euan – how is Kitegen coming along?

  20. Paul Gardner says:

    I’ve come late to this: apologies if I’ve missed previous comments. In a system with this enormous amount of wind and PV capacity, it would appear possible to use the substantial surplus renewables production to produce gas (hydrogen or methane), as discussed, but then use that gas (almost immediately) to substitute for some of the current UK gas consumption. Currently, UK gas consumption in winter (when most of the surplus will occur) is substantially greater than electricity consumption. There would be an efficiency saving (by avoiding reconversion to electricity) and also much less hydrogen storage capacity would be needed than is calculated here. Of course, the results for carbon intensity of electricity production would be worse, but that’s not the objective: the objective is the decarbonisation of energy supply, of which a large part is currently gas. I have found the following useful:

  21. Peter Farley says:

    Alex and Andy
    I spend a lot of time on energy and this is one of the best posts I have seen anywhere. However a couple of suggestions which may make a difference, I am not sure how much

    Power to heat.
    a) A COP of a heatpump of 3 sounds a bit low the best quality domestic Japanese units are 5.5 or so (depending on ambient) but some large commercial systems are up to 12.
    b) in warm climates the output from solar hot water systems can be up to 95C so the storage units are fitted with tempering or mixing valves. If the “boilers” in residences were fitted with about 400L of storage which could be heated to 90C that is around of useful thermal storage 2-3 days heating load for a well insulated house. Similar ratios can be obtained for commercial or institutional buildings
    c) Other materials such as silicon or molten salts can have much higher storage density and orders of magnitude lower cost than batteries.

    In total it is not inconceivable that a day or possibly two of total heating demand could be stored economically

    Capacity factors:
    One of the key developments in wind turbine design is the reduction of specific power (bigger blades) which means that capacity factors are steadily climbing, so that newer offshore farms are approaching 50% now and NREL suggest onshore plants will be reaching 60% by 2030. The obvious implication is less capacity is needed but the more subtle one is that generation at low wind speeds is much higher therefore the period of time where generation is substantially below nameplate is much shorter and hence storage/backup capacity (though not power) is much lower.

    No one knows lets just say that the oldest operating commercial wind turbine is 42 years old and the oldest operating nuclear power plant is 46. Although many wind turbines are being retired before that time. It is often because of obsolescence rather than failure. For example a 1997 windfarm in Spain with 67 turbines has just been replaced with 9 turbines with the same total peak power rating but 50-70% more annual energy. However all the old turbines are still in good working order and are being offered on the second hand market. It is also true that gearbox and bearing manufacturers have learned a thing or two about the real duty cycles of wind turbines so one would expect current generations to last much longer

    Energy efficiency:
    I don’t know how much your forecast demand takes energy efficiency/de-industrialisation into account but it is not unreasonable to suggest that a focus on energy efficiency could reduce total per capita demand by 30-40% by 2050 or perhaps more. The current energy system uses about 15% of generation to run fuel handling cooling, fuel freight, mining and processing

    V2G. I agree with your assessment that V2g is a very slippery concept but the average electric vehicle has 3 days storage so just making sure before forecast poor weather that all vehicles are fully charged and reducing charging demand to 10-20% of average for 2-3 days can suppress demand significantly

    • Alex says:

      Peter, thanks for your comments. Some thoughts on them:
      Heat pump COPs: Andy had lower levels and I revised them up a bit. But I notice a big difference between the COPs in the manufacturers’ literature, and the real world experience. For example:

      Solar heating: There is a host of things that can be done with solar heating. I love the concept of taking summer heat and storing it underground – either:
      – Warm heat from black asphalt surfaces – heating the ground to 30C, and using a heat pump in the winter, or
      – Hot heat from solar collectors – heating the ground to 70C, and just using the heat directly in winter.
      The big problem is that this is very expensive to retrofit to old properties, and new properties barely need it. The same problem applies to district heating.

      Other materials: In part one we talked thermal capacity of the building. The cheapest concept is to take an old brick building with solid masonary walls – perhaps a 200 ton house – and externally clad it with insulation (and seal it and use heat exchangers for ventilation). Then you have a building which will lose less than 1C in 24 hours. For that, the UK urgently needs a replacement for the “Green Deal” to encourage these sorts of retrofits, and probably a loosening of planning restrictions.

      Capacity factors: Good if these can go up, but without numbers, we can’t assume the “AWOL time” is any different.
      gweberbv suggested I contact Andrew Smith – His web site seems to use offshore capacity factors but also claims not to have them!. However, his load duration curve has the same form – just a steeper slope, than our data gives:

      On V2G, part 1 assumes that vehicles are charged more often at weekends and over night – generally when being used less. In part 2 (nuclear) vehicles and heating are the main means of levelling demand over the course of the day.

  22. stone100 says:

    It’s not clear to me why you only use 500GWh-equivalent of thermal storage. I (naively I guess) was thinking that the best way to decarbonize would be to have ALL space heating and water heating dealt with via seasonal thermal stores (such as in Drake Landing) with solar heat collectors and top ups from excess wind electricity. Also massive reductions in the amount of space heating by using super-insulation/ heat exchanger ventilation systems etc. Nuclear could then be used to provide electricity for all other uses and electricity storage (eg pumped hydro and perhaps nuclear coupled liquid air energy storage) could be used for load following with that nuclear supply.

    • Alex says:

      See my response above. Inter-seasonal heat store has wonderful potential, but is very difficult to implement on a retrofit basis. See my comment above.

      If I were building a modern street, I would make the pavement and street out of black asphalt, and pump the heat into an area of bedrock over the summer, for use in the winter. The problem is that I’d then super insulate the houses, so they don’t actually need that much heating, making the whole thing uneconomic.

      What is economic is using the building as a storage heater. Whilst that is a huge improvement on the old fashioned storage heaters of the past, it’s still not an inter-seasonal solution. (Though I did see on Grand Designs a huge house made of cob – mud and straw – which looked like it would have enough heat capacity for months. They even put the polystyrene insulation on the outside).

      • stone100 says:

        Thanks for the explanation. I’m still puzzled about the difficulty of retrofitting a district inter-seasonal heat store. If a housing district had a Drake Landing style borehole heat storage facility, then couldn’t hot water just be piped to each house? I’ll take your word for it that this can’t be done cost effectively but it amazes me that doing that isn’t cheaper than having huge electricity generating capacity and electricity storage.

        • Alex says:

          Someone commented somewhere that BEIS had estimated the distribution costs for district heating at about £8,000 per household.

          The main cost is in laying the pipeline in the street, and then pipes to each home, plus pumps and meters and valves.

          An inter-seasonal store would have the same costs, plus the boreholes, plus:
          – For a hot store (70-80C) vacuum collector tubes on the roofs (as Drake Landng uses)
          – For a warm store (30C), the costs of either heat pumps and/or underfloor heating (which of course come with a new build).

          As said, if you’re building a new road and houses, then it would be pretty cheap to lay the piping for solar collection and distribution.

          This company has done a lot in this area:

      • steve says:

        The problems concerning thermal underground storage and heat pumps used in high density housing is covered in McKay’s SEWTHT. Unfortunately the volumes are insufficient and would cool off too soon. Sorry i don’t have my copy and refs with me.

        Regarding the proposal that a masonry 225mm wall will enable a 1deg C drop in 24 hours, I have 2 victorian terrace houses with insulated external walls, double glazed and draughtstripped as well as possible, and a 9″ brick party wall and solid brick partitions. In theory, the party walls only lose heat if the neighbours house is colder. In my case, I turn the heating down 3 degrees when I leave for a while and if I come back after 24 hours it is 3 degrees cooler, then it takes half a day to warm up. Perhaps the thermal capacity calcs need checking and windows, doors and air change should be included.

        As previously discussed the problem of imroving the high proportion of older properties is enormous and little is being done about it.

        • Wookey says:

          The sensible thing to do is knock them all down and build passivhouses instead. I was surprised how fast you make back the extra carbon from the demolish/new build (from a Scottish study about a decade back). Unfortunately this is not very popular with residents who like their houses, even though they are deeply inefficient and they’d like the replacements more.

          • gweberbv says:

            Are you kidding? For 50,000 to 100,000 bucks you can equip a single familiy home with a new floor heating system, insulation on the walls and the roof, new windows and a lot of other stuff that will significantly reduce the heating demand. What are costs for tearing down the old one and building a new house? 350,000 + X?

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