Earlier this month, the UK Government completed its latest subsidy round for renewable electricity generation – the fifth allocation round (“AR5″) for the Contracts for Difference (CfD”) scheme. And it has widely been seen as a failure since no off-shore wind projects bid. At all. Only 3.7 GW of capacity secured contracts, compared with 10.7 GW last year. This follows the disappointment from AR4 when only two of the off-shore wind projects in that auction went on to take FID (final investment decision) and proceed to construction. The remainder have either been cancelled or are trying to secure enhanced economics in the form of tax breaks, to make them viable.
The strike price cap for off-shore wind for AR5 was set at £44 /MWh in 2012 prices, which is equivalent to around £60 /MWh today.
They question is, why has this happened?
The Government continues to see the Contracts for Difference (“CfD”) as a subsidy, introduced to support immature renewable technologies until costs fall and they are able to be built on the same basis as other forms of generation. On this rationale, the support level would decline over time until eventually the subsidy would no longer be required. However, after a quarter of a century of subsidies, this rationale no longer holds water: wind turbines are not an immature technology whose costs can be expected to fall based on some “learning” effects.
The reason that developers continue to require support is not because the technology is uncompetitive due to immaturity, but because no investors are willing to fund merchant power projects in GB, and there is simply no other way to lay off risk in the GB power market. Since developers see the CfD as a hedge and not a subsidy, they do not expect the support level to gradually fall to zero over time. They expect it to rise and fall in line with supply chain costs and inflation (although the CfD is index-linked so some of this cost variability is already factored in).
It is this fundamental difference in expectations that has caused the failure of AR5 as far as off-shore wind (which has traditionally been the largest participant in the auctions) is concerned.
Industry groups have criticised the Government for not increasing the AR5 support levels, but they have mis-understood the reason for each side acting as they have. The have failed to grasp that the Government is acting rationally based on its assumptions about the purpose of the CfD scheme, ie that it is a subsidy that will eventually not be required.
“Assuming that government officials and ministers did at least hear the warnings from industry, it must be concluded that either they simply didn’t believe that cost increases were as bad as the industry claimed, or they were prepared to see the AR5 auction fail rather than go through a delay and revision process. Timing may also have been a factor; with the move to annual CfDs, they might have also felt they could manage any fall in CfD uptake in AR5 through future auction rounds rather than make immediate changes,”
– Grace Millman, Regen
Of course, the Government’s assumptions are incorrect. After a quarter of a century, the penny should have dropped that the CfD is not a conventional subsidy. In the REMA consultation, there is some realisation of this as the question was asked: how can capital costs be recovered if the price of the item being produced (in this case electricity) is close to zero? If we are to assume that renewable generators receive revenues based on the short-term marginal cost of their product, then capital costs will never be recovered through the sale of electricity.
That, however, is a problem for the future, since electricity costs are no-where near zero at the moment. Yet still, developers are unwilling to either build on a merchant basis (ie without a CfD) and take advantage of the currently high market prices, or to build based on the CfD price being offered under AR5 or even AR4 for the most part. They cite rising supply chain costs, and indeed, costs have risen, but this unwillingness indicates either that windfarms are simply not competitive to build despite their technological maturity, or that there is a wider structural problem in the market deterring investment.
When we look at what other projects are being built, we can see that the issue is the latter: no large-scale power projects have been built in GB in recent years without some form of subsidy, whether this is the Renewables Obligation, the CfD, or a Capacity Market contract, with conventional generation receiving the latter. Of course, conventional generation is not immature, but it now requires support since its utilisation levels have fallen to a degree that irrespective of the power price, they do not generate for enough hours to recover their costs without additional income. The small number of large-scale conventional projects that has been launched in recent years indicates that capacity prices have been too low to sufficiently de-risk projects for investors.
Criticism of the Government has been severe. One industry source was quoted in Utility Week as saying the Government “really needs a kicking”, while others characterised the auction as a “major setback”, a “catastrophic outcome,” an “avoidable yet deeply harmful failure” and the “biggest disaster for clean energy in almost a decade.” The Government has been accused of failing to listen to developers who warned that the price was too low, however, another source said that developers have complained about low strike prices before and auctions have still succeeded:
“One of the problems is that the industry has cried wolf a lot and now we’ve just seen a wolf. I think that is an issue. But actually, the whole point of auctions is that they do establish the truth.”
The truth is that the Government needs to understand that the CfDs are a hedge and not a subsidy. And there is no reason to expect the strike price of a hedge to decline over time. However, if wholesale electricity prices fell to zero, then it would be both a hedge and a subsidy since price support would be required, to provide developers with a source of income, since selling electricity will not generate the returns needed to repay capital costs, and to provide certainty over income to ensure that income is sufficient over the life of the contract to provide an acceptable return on investment.
This means that the Government has to let go of its ambition to taper renewable subsidies to zero over time. And it needs to be honest with consumers that they are going to continue to pay these support costs forever, with the value of the support increasing as wholesale prices fall below the strike prices, something the Government expects will happen as renewable generation replaces conventional generation. Unless it faces up to this new power market reality, its plans for renewable generation, and in particular off-shore wind, will continue to stall.
I’m inclined to agree that subsidies are here to stay. If that is the case, and the cost efficiency gains in wind are at least bottoming out, shouldn’t the govt step in and build future wind farms on behalf of the bill/taxpayer? I can see some argument for dispatchable generation staying in private hands (for now at least), but what value is the private sector adding?
An interesting point – I was thinking something similar as I read the article. However, the answer to your final question is efficient project management. See HS2 for contrast.
Zero.
Time to abandon wind power
Unless the generating source can.provide firm power then they should be entitled to nothing. That wind is even allowed in the capacity market auctions and awarded contracts albeit at a low level for now is s8m0ly mind boggling and an insult to engineering common sense.
Let those that really want ‘green energy’ from intermittent sources be on interruptible contracts, when the wind doesn’t blow or the sun doesn’t shine it’s lights out for the righteous. When little Johnny can’t have his tofu casserole reality might prevail. Until then the market is broken.
The right way to compare different power scenarios is not to ask for firm power, but to ask for bids to supply a fixed proportion of variable UK demand, perhaps based on a 20 year profile of demand. After all, UK demand is not constant, so the grid has no requirement for constant power. That is basically where Helms got it wrong in one of his policy recommendations.
That means a system with weather dependent variable renewables to supply cheap power most of the time, supplemented by periods of power from backup generation can meet the reliability requirements. The backup generation has a low capital cost, but a high fuel cost, such as the cost of natural gas or green hydrogen. Batteries can be used to reduce the average cost of power by smoothing periods of surplus and short durations of shortage, thus reducing the cost of expensive back up fuel.
Demand side response can be part of such bids. If a load can be postponed indefinitely (such as electric arc furnaces which work in batches), then it can provide the equivalent of backup generation with expensive fuel costs, and can reduce the required capacity of such backup.
An excellent article. We need to bang Eds together (Miliband and Davey) until they read this piece.
Intermittent renewables will always require subsidy or some sort of price support.
When it is very windy, they produce most energy and it’s not uncommon for spot prices to fall to zero. Lots of generation at low or zero prices leads to low or zero revenue.
Conversely, when it’s calm and next to no production, spot prices rise, sometimes dramatically. However, low or zero production even at high prices leads to low or zero revenue.
So of course they need guaranteed prices: the economics are and always will be dodgy.
Exactly. The question no-one seems to be even asking is how come windfarms still need subsidies when electricity prices are high, yet somehow we expect them not to when electricity prices reflect the SRMC of renewables ie close to zero. And the result will be that consumers will not realise the benefits of “free” electricity because some sort of income stream that is not from selling £0 – priced electricity is going to be needed.
Surely the definition of subsidy is relative to some other form of electricity supply.
If a renewable grid with backup provides fixed price wind power, much cheaper on average than a natural gas plant would provide, then there is no subsidy. As Kathryn says, wind power provides a hedge, not a subsidy. Perhaps you should extend the definition to the variable costs of a natural gas plant – the wind farm has to provided cheaper power when the wind blows than the fuel and other variable costs of the natural gas plant for there to be no subsidy. So it is “avoided cost” that is the bar for comparison, not “full cost” – because the capital cost of the natural gas plant has to be provided, whether it is generating or not. Fortunately, gas plant capital cost is only 20% of the cost of an offshore wind farm of similar capacity.
It is unlikely, under new electricity market arrangements resulting from REMA, that wind power will be allowed to bid into the current wholesale power market auctions, as this is meaningless. The wind farm provides “must take” power when the wind blows and no power when the wind doesn’t blow. It would be an utterly stupid market design to allow wind farms to compete against each other by bidding for 30 minute periods when no other type of generation is required to fully satisfy demand.
The much better form of market competition is at build time. Auctions for fixed priced contracts, such as CfD auctions which are effectively fixed price, are a much better way to go. Then the real-time competition is for backup power, not cheap weather dependent power.
Excellent ‘in a nutshell’ summary – thank you
I’m having difficulty viewing comments on this. I can only see the one from Ox, although if I look at a different article I see other recent comments listed. Clicking on those links just takes me to the comment by Ox, with the other comments not displayed.
It should be working again now. Apologies – I had some behind-the-scenes clean up work done and it caused a glitch that should now be fixed.
An excellent article.
It shows clearly that energy providers are so detached from paying consumers they don’t understand the logic of ‘keep paying’ ever increasing bungs is not accepted – it is the hallmark of a failed industry. I don’t care if the bung is a subsidy or a hedge – this is on a massive upward trajectory with completely unreliable output.
Time to move on.
The most illogical thing about the government CfD AR5 auction maximum cap of £44/MWh (all in 2012 prices) on offshore wind is that it was significantly lower than the £52/MWh cap on onshore wind.
Onshore and offshore wind are positively but not perfectly correlated. New offshore wind is likely to have a capacity factor of 55% vs 25-30% for onshore wind. Offshore wind can generate at many times when onshore wind can’t, while the reverse is not true. Offshore wind is thus much more valuable than onshore wind. Logically, offshore wind should have a higher auction maximum cap at times when there are supply chain issues with either or both.
You can’t make the same comparison with the solar PV AR5 cap of £47/MWh. Solar PV is negatively correlated with wind power, as solar clearly generates at different times to wind. UK solar is much stronger in summer, and only available during the daytime, while UK wind is much stronger in winter and a little stronger at night. The two are thus complementary to each other in times of generation. There is thus no obvious basis for comparison of the maximum caps between solar PV and either onshore or offshore wind, given they are completely different technologies.
The reason why there were no offshore wind bids was because the wind industry were asking for CfD prices to be two and half times higher than the current level.
See the press release issued by the renewableuk website dated 04/07/2023.
This blows out of the water the idea that wind energy is cheap, not that it ever was, never mind taking into account its chaotic intermittency meaning that it cannot reliably power anything.
You are misinterpreting the contents of the press release. What is says is
“The budget for fixed-foundation offshore wind alone would need to be at least two and a half times higher than its current level to maximise the capacity which could now be secured in this year’s auction. ”
It is talking about the CfD levy control framework budget, not the total strike price of the offshore wind. They were asking for an increase of £140m per year for the CfD budget. For offshore wind power at £44MWh (all 2012 prices) that would buy you only 3 TWh of electricity per year, whereas 7 GW of offshore wind at a capacity factor of 55% would generate roughly 33 TWh of electricity per year.
The implication is that the industry was asking for the AR5 offshore wind auction cap to rise from £44/MWh to £48/MWh, and not from £44/MWh to £110/MWh.
A £48/MWh offshore wind auction cap would have been been pretty reasonable, given that onshore wind was £52/MWh and is less valuable. The solar PV cap was £47/MWh.
The government was pretty stupid not to accede to this request, putting in jeopardy 33 TWh of low cost electricity per year from 2027/8 onwards.
Kathryn,
I wrote the comment above starting “You are misinterpreting..”.
I think there must be a glitch in the web site code, as it must have defaulted to Steve’s name in the comment above, rather than mine, and I didn’t spot it that time round – only the next time around.
Feel free to delete it and I will repost it.
Peter Davies :
If I’m not correct that the wind industry wanted a two and a half increase in their CfD price then why were there no AR5 offshore wind bids with Vattenfall cancelling its AR4 Boreas project citing a 40% increase in costs?
In fact, do you know please the CfD price the wind industry wanted if it wasn’t two and half times the AR4 figure of £37.35 = £93.37 (2012 prices) ?
Is the Government really worried by losing 33 TWhrs of low cost electricity per year which represents just 10% of electricity generation especially when I notice anyway that electricity prices often go negative, presumably when it is cheaper to export at negative prices rather than pay constraint payments? It doesn’t make sense.
Why is onshore wind “less valuable” ?
BTW, I don’t believe offshore wind is capable of a 55% capacity factor.
Sorry, but suggesting offshore wind developers wanted a strike price two and a half times higher is completely off the mark. All they were asking for was an administrative strike price set at reasonable level reflecting significant supply chain inflation (way above headline inflation) over the last couple of years (in the range of 20-40%). Instead, they got (inexplicably) by far the lowest ASP of all technologies, and an ASP broadly in line with the last allocation round from a couple of years ago, before this significant inflation occurred. Even just setting the ASP for offshore wind in line with onshore wind (20% higher at £53/MWh) might have allowed at least some offshore wind projects to submit a bid, locking in a strike price which would have still been below forward wholesale prices.
Martin Namor :
We ae constantly being informed that renewables are 9 times cheaper than gas, so I am at a loss as to the reason why we even need to be continuing with subsidies for renewables.
If we do still need the CfD system for AR5 then it is inexplicable why we have no bids for offshore wind, and worse still, completely no transparency on the price requested by the wind industry. We only know the CfD price they have rejected.
It is surely necessary for the wind industry to publish the price they require (if two and half times the AR4 2012 price of £37.35 = £93.37 is not correct) as the Government has a legal requirement to achieve net zero CO2 emissions by 2050 and we are told by the UN’s climate committee that spending on renewables needs to increase 6-fold?
Why the secrecy?
We need to know how much this will cost.
To John Brown:
JB said “the wind industry wanted a two and a half increase in their CfD price”
If you go back to the source document for the industry comment, then the relevant phrase is that “The budget for fixed-foundation offshore wind alone would need to be at least two and a half times higher than its current level to maximise the capacity which could now be secured in this year’s auction.”
The explanation for what this means requires a little knowledge of how the CfD process works, which is explained below.
The “budget” referred to is the CfD “subsidy” budget, which is not the same as the “strike price”. For the AR5 auction, there is a define budget for the “pot 1” technologies which are: Energy from Waste with CHP, Hydro (>5MW and 5MW), Remote Island Wind (>5MW), Sewage
Gas, and Solar Photovoltaic (PV) (>5MW). They are the more mature technologies.
See https://assets.publishing.service.gov.uk/government/uploads/system/uploads/attachment_data/file/1124052/cfd_ar5_core_parameters.pdf.
Pot 2 is for less mature technologies.
Also in the link above is a list of “administrative strike prices” in 2012 pounds, which was £44/MWh for offshore wind and £52/MWh for onshore wind. These are the maximum bids which will be accepted.
Now see link https://assets.publishing.service.gov.uk/government/uploads/system/uploads/attachment_data/file/1175988/cfd-budget-revision-notice-allocation-round-5-2023.pdf.
This specified a final CfD AR5 annual budget for pot 1 of £190m per year from 2025/6 onwards. This represents a nominal annual subsidy for the whole of pot 1. It is this £190m per year budget that the industry suggested should be multiplied by x2.5 in order to get to the assumed 7 GW capacity of offshore wind bids.
More on 55% capacity factor below. But, for now, assume 42% which existing UK offshore wind farms using smaller turbines achieved June 2021 to May 2022 – see https://energynumbers.info/uk-offshore-wind-capacity-factors.
7 GW likely cap at 42% CF is roughly 3 GW average generation. Multiply by 8,760 hours in a year and you get 25 TWh per year of generation.
If you now work out the budget cost of 190m per MWh it comes to £190m / 25,000,000 MWh = £7.6/MWh. A lot of the pot 1 budget will go on onshore wind and solar, so the subsidy contribution to offshore wind will be a lot less than this. But pretend offshore wind gets all of it.
Clearly £7.60/MWh is not the strike price of offshore wind, which is capped at £44/MWh. The industry wanted the CfD budget increased x 2.5, which would mean adding a proportion of another £11.4/MWh. So the maximum cap for offshore wind would then become £44 + £11.40/MWh = £55.40/MWh (in 2012 pounds). Clearly this is not 2.5 times the expected strike price (AR4 was £37.50/MWh, so 2.5 times that would be £93.7/MWh). In other words, going back to the definition of the CfD budget means that the industry was asking for something less than a 25% increase in the maximum strike price, not to multiple the strike price by x2.5.
JB said, “Vattenfall cancelling its AR4 Boreas project citing a 40% increase in costs?”
If Vattenfall’s costs had increased by 40% since AR4, then, without thinking about it, you might expect Vattenfall would want a strike price increase of 40% = 1.4 times, not an increase of 2.5 times.
In fact there is always an annual CPI uplift in the strike prices. In the year between auctions, the snag is that project cost inflation (dues to war effects) has been 20-40% while the CPI price has gone up by only 10% roughly (at peak). But you can subtract the 10% from the 40%, because Vattenfall would be getting the 10% anyway, leaving 30% project inflation over and above CPI inflation.
JB said “Do you know please the CfD price the wind industry wanted if it wasn’t two and half times the AR4 figure of £37.35 = £93.37 (2012 prices) ?”
I don’t know directly. But a rough guess would be that Vattenfall wanted the 30% by which project inflation early 2022 to 2023 was higher than the 10% CPI inflation. So they might have wanted 1.3 x £37.35 (AR4 strike price) = £48.5/MWh. But the cap was £44/MWh, so the offshore wind projects couldn’t make a worthwhile profit and so no bid. But note if the offshore cap had been the same as onshore wind at £52/MWh, then we probably would have seen projects bidding below £52/MWh.
JB said “Is the Government really worried by losing 33 TWhrs of low cost electricity per year which represents just 10% of electricity generation?”
The 33 TWh of low cost electricity would be replacing 33 TWh of electricity from gas, which was averaging £199/MWh in 2022, and averaging £166/MWh for the 24 months starting July 2021 (when Putin’s energy war really started). These prices may not be repeated, but UK govt BEIS estimated power from gas to be at least £85/MWh from 2025 onwards. If the government hasn’t been hijacked by the fossil fuel industry (persuading them to “lose” the 33 TWh), then it ought to be worried!
JB said “electricity prices often go negative”
Only generation with either a CfD fixed price or a guaranteed subsidy above the wholesale price can afford to bid negative, so these have to be the cause of the occasional negative prices. The CfD fixed price wind just doesn’t care what the wholesale price is, and the guaranteed subsidy above wholesale price still makes a marginal profit provided the negative price doesn’t eat all of the guaranteed subsidy. So these contracts feed negative prices when demand is low and wind output high.
Two things are likely to stop prices going negative in future.
1) The AR5 (maybe AR4 too) and subsequent contracts won’t pay anything at all to CfD generators if prices go negative – whether they generate or not.
2) The NG ESO is converting the grid to a smart grid by the end of 2025 by ensuring stability services do not require any active gas generation. Prior to 2020, the grid needed something like 15% of active gas (judging from the minimum it always had), and would kick off wind power to make room for the gas. By 2025 the NG ESO can go down to 0% gas. I think the 15% of gas wasn’t part of the normal real time power auction, but was part of a balancing/services contract with a separate price, so didn’t affect the wholesale price. So you could get 15% gas while still having a negative wholesale price due to 85% wind, solar and nuclear which are all “must take”.
So there is room for more wind power on the grid, and the most recent contracts can’t bid negative. So it is likely that the periods of negative pricing go away, or at least will be much reduced.
JB said “Why is onshore wind “less valuable”? BTW, I don’t believe offshore wind is capable of a 55% capacity factor.”
See the (quite slow) Wind Atlas at https://globalwindatlas.info/en. On the LH panel click on “Capacity factor – IEC Class 1”. Zoom in a little into UK, and click on the dark orange sea colour somewhere near Dogger Bank. The bottom right rainbow scale now gives me a reading of 0.59 = 59% capacity factor. Zoom out and then click on the coloured area furthest due west of Scotland. The scale now says 66% CF.
The latest turbines are 260m tall and a little away from the slower layer of air a few tens of metres above the ocean surface, so wind speeds are higher. And there isn’t much land within tens of km to slow down the momentum transfer of air moving much faster higher up (jet stream speeds are hundred of km per hour). So some of the giant new turbines in the right place should get over 60% CF.
Dogger Bank A offshore wind farm is going live soon, so we will find out before the end of this year for sure.
Assume 55% for offshore wind and only 25-30% for onshore wind. Clearly the offshore wind has a smaller proportion of gaps you might need to plug with short duration battery storage or backup – both of which cost more than raw wind power. So you need less battery storage and need to burn less backup fuel (which will ultimately be green hydrogen) to plug gaps in offshore wind, compared to onshore wind. That makes offshore wind more valuable – you should be prepared to pay more for it because you clearly end up paying less to firm it up to meet variable demand. Yet the AR5 offshore wind cap was £44/MWh and the onshore wind cap was £52/MWh which is the wrong way around.
You could quantify the additional value of offshore wind with simulations, but that is a lot of work! I have java code which gives me enough Elexon data downloads of actuals for demand and subsets of onshore and offshore wind and solar, but not that much time. One day maybe!
You need a little more knowledge of how the CFD budget process works. The budget is eaten up in the first instance by the difference between the Administrative Strike Price, which is the highest permitted price bid, and the Assumed Reference Price which is the assumed market value of the output, multiplied by the nominal capacity bid and the Assumed Capacity Factor for each technology, all of which are auction parameters in 2012 funny money set by the government. Raising the budget while leaving the other price parameters unaltered does absolutely nothing for delivery if no-one is prepared to bid at the Administrative Strike Price. If there is competitive bidding below the Administrative Strike Price then the budget stretches further, and if there are sufficient bids below the Assumed Reference Price then the budget becomes immaterial. When there is competitive bidding below the Administrative Strike price, then either increases in budget or raising of Assumed Reference Prices would work to increase the ceiling on capacity that could be procured. But with no bids at the Administrative Strike Price, and all solar bids awarded (cleared at the Administrative Strike Price), plus (almost) all of the onshore bids awarded as well (the clearing price was only just below the Administrative Strike Price), increasing the size of Pot 1 might have procured at best a tiny amount of extra onshore wind at the cost of raising the clearing price to the Administrative Strike Price some 71p/MWh higher in 2012 money.
As an FYI, nuclear power stations have been prepared to bid at negative prices in the days of pool prices before renewables were a thing, and prices even occasionally cleared at a negative level. Your assumptions that negative prices will go away don’t hold up. There is already sufficient renewables capacity on terms (including still even AR3 wind like Dogger Bank and Seagreen to come) that guarantee a subsidy when demand is lower and renewables output is high to ensure that price bids will go negative. That will leave the wind farms without subsidy protection as first in line to curtail (as already happens with those wind farms that have not taken up CFDs and get no subsidy – e.g. Moray East, and wind farms in construction. At best they will get a curtailment payment by undercutting what a subsidised wind farm might demand, but otherwise they will simply have to curtail for no income, and they also run risks of charges under BSUoS. When there is sufficient competition among the wind farms not being subsidised then curtailment payments will erode, while the subsidised wind farms continue to enjoy their subsidies. However, excessive curtailment payments on the Continent will reflect via interconnectors, forcing more UK generation off line and creating a major headache for the Grid. We saw this already in summer when prices went to -€500/MWh due to massive solar surpluses in the Netherlands and Germany, forcing the Grid to pay Dutch solar farms to prevent exports on BritNed. The frequency of negative prices depends on the frequency and extent of renewables surpluses. That will only increase as renewables capacity is added.
The Assumed Capacity Factors are based on modelling done for DESNZ several years ago by their favourite green consultants. They bear little relation to reality. Moreover, fanciful capacity factors are going to get eaten into by curtailment as these new wind farms will be cheapest to curtail. The effect can be quite savage: in 2022, Moray East produce 2,563.8GWh – an average of just 30.8% capacity factor, compared with around 40% for all offshore wind farms. Financially, it did well enough, averaging £264/MWh in the extreme market conditions, probably boosted somewhat by curtailment payments because of the lack of transmission capacity. Actual performance of the newer generation turbines is turning out to be disappointing because they break down more often, and have to wait for repairs, and perhaps because the wind assumptions are turning out to be not as wonderful as modelling suggested. The gradient in wind speed between the tip of the blade at the top and bottom of its travel imposes enormous stresses on the blade and the hub, and sets up oscillating wear conditions. Wind turbine manufactures are discovering the problems encountered by tidal turbines where the stresses destroy the turbines at quite small sizes because of the density of water – not helped by added turbulence from waves above. See Kathryn’s excellent new article for more.
Adjusting the budget does nothing for adjusting the prices. In fact, the budget was increased. What it achieved was a small increase in onshore wind, which cleared very close to the maximum bid price. Solar bids were allotted in full, and there probably were very few onshore wind projects that were rejected – possibly none. It did precisely nothing for offshore wind, which clearly needs much higher strike prices.
None of the capacity factors assumed for the purpose of the auction calculations are realistic, except perhaps solar. They are a device for tying to favour one technology over another, and for PR. When you dig into how the whole thing works, it turns out that one of the key assumptions is the estimated market revenues of the different technologies. The maximum bid prices also matter. National Grid as advisors to DESNZ got that badly wrong. DESNZ buried their heads in the sand: they should really have cancelled the auction when they failed to attract pre-qualifications for offshore wind back in the spring, and looked at the real world. The Irish had an auction that worked at €86.05/MWh cleared price for offshore wind (maximum bid allowed was €150/MWh) in current money. Several other auctions had already failed. Now we have a lot of wasted time, and still no evidence that DESNZ have any idea how to fix it.
John Brown: “Why the secrecy?”
Because the strike price each developer requires to progress to FID is a function of its costs, commercial arrangements with the supply chain, etc., all of which is highly confidential and commercially sensitive.
I would like to know how much of the ‘external’ costs of wind generation are borne by the generators, i.e. back-up, additional infrastructure and storage. These must be a major, and increasing, part of generating costs. I say increasing because we are now getting to the point where wind is generating excess electricity at periods of low demand more and more frequently. As over-generation accelerates this must increase the need for balancing and, in particular, storage. In my mind, therefore, the ‘external’ costs of wind generation will potentially delay or, more likely reverse, the approach of economic viability. This, combined with the uncertainty of how storage technology and costs will evolve over the next few years, must make wind an extremely risky investment demanding very high yields.
Why aren’t you asking the same question about the balancing costs of natural gas or nuclear generation? In fact you need significant active rotating standby power for a 3 GW nuclear plant or a 1 GW natural gas plant too, yet no one ever seems to worry about the balancing costs for those. You could easily lose 500 MW of gas turbine at the drop of a hat, not to mention transmission lines, so the active standby balancing needs to be able to supply at least 1 GW at the drop of a hat. By contrast, losing a couple of wind turbines at 13 MW a go isn’t worth worrying about, though it will happen more frequently.
UK now has 2.1 GW of grid batteries, with a total pipeline of 32 GW, duration 1 to 2 hours. This should reduce balancing costs alike for both conventional generation and wind and solar.
The NG ESO is implementing contracts for grid reliability services by 2025 which means that the grid will no longer require active gas generation when wind and solar output, with or without nuclear, could otherwise meet the whole of the demand. That will reduce the occurrences of having to curtail wind power at times of low demand.
Further, as the EV charging load expands, this can take cheap wind power at times of surplus, because a 300 mile range EV with a 30 mile daily round trip commute has at least a week of flexibility in when to charge. That is why the Intelligent Octopus scheme offers a 7.5p/kWh tariff, guaranteed for 6 hours per day, nominally midnight to 6 pm, to anyone with a smart meter and an EV which can be smart charged. In practice, the hours can be outside that time, dependent on the times the wind is blowing strongly.
And how is nuclear expected to follow a fixed variable load if it generates most efficiently at maximum full output all the time. Surely you have to cost in some storage, or some peaking gas generation for nuclear too. Else you are just loading all of the balancing costs on to renewable generation inequitably.
What it comes down to is that you should cost the different grid scenarios properly, against a fixed proportion of UK variable demand, and see which ones come out cheapest. That is the only way to get a true comparison of the full grid costs of different technologies. But only rarely are such scenarios properly evaluated.
Peter Davies :
“That is why the Intelligent Octopus scheme offers a 7.5p/kWh tariff, guaranteed for 6 hours per day, nominally midnight to 6 pm, to anyone with a smart meter and an EV which can be smart charged. In practice, the hours can be outside that time, dependent on the times the w.ind is blowing strongly.”
What happens when the wind isn’t blowing for days at a time?
The recently released Royal Society report on storage estimates that we will need 100 TWhrs of storage
Peter, I think very rapidly fluctuating intermittent renewables, particularly when they represent a significant proportion of the generation mix, take far more balancing than steady but relatively flexible combined cycle gas turbines working with admittedly less flexible nuclear because the latter provide reliable baseload power which cannot be provided by wind or solar. Yes balancing may be augmented by the Smart Grid but I remain to be convinced that it’s anywhere near a complete answer.
The Royal Society recently (Sept ’23) warned that 100 TWh (Not TW or GW, note!!) of storage may be required to reach Net Zero.
I’m not saying nuclear is the total answer and I’m all for Net Zero but it’s going to take a very long time to get close to it on wind and solar. In my view there must be far more focus on energy conservation.
I’m still learning on this so great to hear different views!
Would love to know your thoughts, Kathryn.
Peter Davies :
“And how is nuclear expected to follow a fixed variable load if it generates most efficiently at maximum full output all the time.”
RR claim in this video that their SMRs can load follow :
https://www.youtube.com/watch?v=Do0SyBddotA
The French do it with their nuclear, although it does cost extra in maintenance.
Sir David Mackay, physicist and mathematician, Chief Scientific Adviser to the UK DECC 2009 to 2014, who wrote “Sustainable Energy – Without the Hot Air” in his last interview ruled out renewables and recommended nuclear + CCUS :
http://euanmearns.com/david-mackay-the-final-cut/
BTW, all my calculations for the cost of building energy infrastructure show offshore wind to be 2 to 3 times more expensive than large nuclear or even RR SMRs. Hinkley Point C was only expensive because, as Sir Dieter Helm has pointed out in a BBC interview it was double the price it should have been because the Government (Sir Ed Davey) used Chinese finance at 9% instead of the current rate at the time of 2%.
We know what balancing costs are without having to cater for renewables, because that is the history. Some of the cost arises because demand forecasts turn out to be wrong, and some because of failures due to plant or interconnector trips, or loss of transmission facilities. Overall, we were looking at around £5-600m p.a. for a grid with negligible renewables, compared with £4bn now.
In the case of renewables, it isn’t just the odd turbine, but large scale output that cannot be relied on: a weather front moves through, so suddenly we go from zero wind to strong breezes across whole wind farms, and the timing can be critical. The same with a cloud front or sunset interrupting solar. All requiring balancing at multi GW scale. When conventional generation is driven off the network to accommodate large renewables flows, this means there is very little spinning backup. With conventional generation, inertia has been enough to handle plant trips until regulation increases power output to provide cover. Short circuit strength meant that circuits do not get overwhelmed by lightning strikes. Now we have larger contingencies on interconnectors which actually account for the majority of abnormal frequency disturbing trips.
Incidentally, I don’t know what you think 32GW/?50GWh of batteries are going to do other than add to costs. On a 10 year replacement cycle that’s 5GWh per year at around £500/kWh fully installed, or £2.5bn p.a. of cost, plus 25% of throughput in round trip losses (perhaps ~13TWh or £1bn of electricity) by the time you add in the transmission side. Plus a smidge of profit incentive and financing costs on £25bn of assets, even written down 50% on average.
The grid is already operating at minimum inertia levels that are teetering on the brink of falling over: the plan to reduce to about 2 seconds of inertia may prove a bridge too far (the energy in the inertia is equivalent to just 2 seconds of grid demand, giving little time for reaction and no leeway for failure). Already we are down to sometimes as little as 2.5GW of CCGT, so there is not a lot of extra wind that can be accommodated by reducing that to zero, with the main tranche of curtailment currently being driven by transmission constraints. Increases in capacity would soon swamp that anyway. Curtailment is only headed one way: upwards.
A well designed grid has reliable low cost baseload generation, and flex generation that can handle the variations in demand easily and at low cost. See France, with its combination of nuclear and hydro, topped up by some gas and export flexibility. Nuclear was supplying up to 70% of the energy. The aim of grid design should be to minimise overall expected cost over time. That may entail having some flexibility in fuel sources to allow some switching, unless you have very secure supply. But it is very hard to see how a renewables based grid can really work at low cost. I’ve spent a decade looking at the problem without finding good answers.
https://www.current-news.co.uk/moray-east-under-scrutiny-after-using-loophole-to-net-647-million-says-ref/
There’s a whole raft of problems with how the market and contracts are currently working. Someone needs to sort out this mess.
It is ridiculous that the government insists on private companies taking on risks, when we need security of supply. If companies effectively take on those risks, then we all have to pay the risk premium that companies will add on to ensure that they get a return. This results in higher bills and costs.
A privatised industry adds costs such as risk premium, shareholder return and regulation functions (costs), which nationalised industry does not carry. Using the highest priced generator to set the market price also adds to the costs to the customers.
I can think of many more ways a privatised market could be made to work, but it appears we have the worst of all worlds where to ensure private companies get a decent return, it has been at a loss to the customer.
I suppose that nationalisation doesn’t work when you can get a whole industry walking out, giving blackouts and no power, or three day weeks, if wage demands are not met. It is not surprising that Margaret Thatcher found privatisation so appealling, with extra money for the treasury.
Is there anyone competent enough to get the system working such that customers get lower bills, with an understanding that the companies providing the essential life-blood power of the country will get a lower risk-free return?
How about pricing the electricity to the lowest market price, then having additional payments to support those that cannot survive on that lowest market price, where there is a national grid organisation that pays those additional payments, and then gets charged to all the electricity customers.
That would stop all this nonsense of wind farms and solar farms delaying taking up their CfD contracts to get the vastly inflated wholesale price for the electricity.
CfDs only work if the wholesale price is low when the wind farm/solar farm starts generating, and they see it as a financial imperative. They don’t work when the wholesale price is much higher and the generators have a few years to decide whether or not they wish to take up the CfD, and can price their income at a much higher wholesale rate.
CfDs are a good idea if they are legally binding with no other payment mechanism available.
There is an obvious conflict of interest, and things just haven’t been working in the electricity customers’ interests.
The electricity market could be designed in many different ways, but somehow we have got the worst possible system.
Where is Ofgem in all this mess? Aren’t they supposed to be regulating the market, or is it only the utility companies that bill the customers are the only ones getting regulated? Don’t they have any responsibility for the generators, the power companies actually generating the electricity?
Isn’t this the biggest reason why no offshore bid for AR5 was received is because any developer didn’t have the option to defer the CfD actualisation date to maximise revenue generation like previous rounds? Mind you given the futures market is forecasting an average of >£100ish/MWh for next few years and probably beyond so presumably a developer could construct at their risk don’t have to wait for an AR process to come along but they don’t!
Isn’t security of supply being managed through the CM system payments which offshore wind can participate in albeit at a down rated capacity despite no guarantee that it will be available like a CCGT.
Reality is the system is sub optimal already with too much wind now that even on medium wind days it can’t be utilised and has to be constrained off (nearly 50GWh only a couple of days back according to wind-curtailment-app-ahq7fucdyq-lz.a.run.app/ ) Adding even more wind is only going to exacerbate that problem and consequential extra costs.
My view is this so called failure is a good moment to stand back and take the time to work out the best way of achieving the NZ goal and im pretty well sure it needs a CEGB MkII to take the lead and then invite in the privateers in a cordinated way.
PS: Many thanks to Kathryn for providing these thought provoking articles and all comment contributors as whatever your views get rounded opinion from all angles is very informative.
Personally I see this as a good outcome as it should give impetus to stand back and take until any new generating asset has to bear the full cost of getting it power to where its needed we will have a sub optimal system.
Nicholas, the reason no offshore wind project bid in AR5 is much simpler: the strike price cap set by government was just too low to allow any developers, even the most efficient, to recover their costs, including a reasonable risk-adjusted return, following the significant inflation experienced in the supply chain for offshore wind over the last couple of years. The only realistic alternative to a CfD would be a PPA, which is a route some developers are starting to explore, but given the size of most offshore wind projects these days (from hundreds of MWs to several GWs), it might be impossible to find a sufficiently large off-taker or a sufficiently large number of off-takers to fix the price for a sufficient portion of the overall project capacity. Building projects of this size without any revenue certainty (be it from a CfD or a PPA) is just impossible, as no lender or investor would provide funding to the tune of hundreds of millions or billions purely based on a projection of future wholesale prices, as outturn prices might ultimately turn out to be significantly lower, bankrupting the project.
The problem with the electricity market is that we need vertically integrated companies that generate and sell electricity to consumers that aren’t contaminated by the “wholesale” pricing mechanism.
Unfortunately we have not got a real market for electricity, where customers can go to different generators who actually make the electricity, and then pay National Grid for the transport of that product to the customer, we can only go to an “agent” that doesn’t actually make the product/service that we are buying.
A similar sort of market would be like buying a car, where there are many different parts manufacturers, but whoever builds the cars (our agent) doesn’t buy the cheapest components at the right quality, they look around the market and charge us as customers the highest price that any manufacturer is asking for each component, even if there are cheaper suppliers on the market.
We don’t get a cost effective car, we get a very expensive car, that could be built cheaper at exactly the same quality.
We do not have an electricity market, we have an electricity cartel.
I don’t know how the government sees a CfD only as a subsidy, as there are two components to it, where it only pays out to the generator if the wholesale price is lower than the strike price, but the generator pays back if the wholesale price is higher than the strike price.
The construction of the contract is as a sophisticated financial instrument that provides hedging against the possibility of loss, but also caps the maximum income (profit). This effectively gives a very specific financial return that is fixed at the start of the contract. This does not allow any variation, i.e. abnormal events i.e. risks and associated costs, if not added in as a higher strike price right at the start will not be very forgiving and could result in a loss i.e. going bust (bankrupt) if you don’t have sufficient financial backing, unless you have plenty of statistical analysis i.e. previous experience to support the strike price being set.
If the government sees these sophisticated financial instruments just as a subsidy, then we need a better government that can actually understand the way CfDs work.
Surely there are plenty of knowledgeable civil servants who can explain how they work to less well-informed ministers?
A CfD acts as a subsidy and a hedge simultaneously when the wholesale price is below the value that allows the generator to make a profit. i.e. a hedge is where you set up a financial option of some kind that if the price moves such that you could make a loss, the option then provides a return in those instances. This acts as a subsidy in those instances.
But, when the wholesale price goes above the strike price, the government, (or whoever the contract is with) gets the income from the difference in the higher wholesale price and the strike price. i.e. acts as an income cap for the power generator.
Thus for the generators it is a combined hedge (subsidy) & income cap.
If you want it to work, a realistic strike price has to be set where the generator has a reasonable expectation of profit at an appropriate level, and a common understanding of the costs and income and profit of each generator.
The strike prices of CfDs can only decline if the costs are declining, but who is actually measuring the true costs of each renewable generator. LCOE calculations are an indication, they are not real world costs and income.
It appears that even Kathryn is a little confused over the issue…..read her article again where she tries to say a hedge is not a subsidy.
“The truth is that the Government needs to understand that the CfDs are a hedge and not a subsidy. And there is no reason to expect the strike price of a hedge to decline over time. However, if wholesale electricity prices fell to zero, then it would be both a hedge and a subsidy since price support would be required, to provide developers with a source of income, since selling electricity will not generate the returns needed to repay capital costs, and to provide certainty over income to ensure that income is sufficient over the life of the contract to provide an acceptable return on investment.”
There’s the CAPEX (with borrowing costs) and OPEX to pay for, which requires a known annual income, and known costs to generate a known (expected) profit.
The wholesale price does not have to fall to ZERO, it can be above ZERO and the generator could be making a steady or mounting loss.
The problem is the inherent variability of electricity prices in a free-market, where in one year the price of electricity can vary significantly in a normal year, and if you get negative pricing, how fast will the generators go bust?
It appears that the government likes the generators to take all the risk, which unfortunately if you are dealing with inherently variable income from inherently variable power source such as solar or especially wind, and a variable wholesale price, the financial aspects could be quite brutal and unforgiving.
If the government changes the terms and conditions of payment, it can turn what was a profitable strike price into a loss. A CfD strike price has to take into account curtailment, and all possible events and terms and conditions. If the government only sees them as a subsidy, it is not surprising that no one wishes to be involved with such incompentence…….a sure way to financial ruin.
A nationalised industry does not have to deal with highly variable wholesale pricing that a privatised market based on competition with different generators with highly variable fuel pricing causes. A nationalised industry sets its own price, taking all its own income, costs and investment needed into account.
It appears that the government and Ofgem don’t actually understand how other markets and sophisticated financial instruments actually work, and is why we have such awful electricity pricing and contract setting mechanisms.
Of course, the bidding for sites that brings money into the Crown Estate, under the leasing arrangements means………..higher electricity bills, because who pays for the cost of the leases eventually……….the electricity bill payer…….it is a cost temporarily born by the developer, but is just another cost that has to be passed onto the electricity bill payer……..that has to be financed by interest charges……another part of the increasing cost of electricity.
It is interesting how the government so easily slips in a tax on electricity, but it is dressed up as a lease for the land.
If you have ever wondered why electricity might be getting more expensive, we have got several very clever mechanisms where the government isn’t being open about the effect of how the different markets and building the renewable capacity is affecting bills.
The lack of extended logic and financial analysis is woeful.
Renewable electricity would get cheaper if the government didn’t start to use it as a means to get extra income and tax from the developers, which back-fires because it eventually lands up on our bills.
KISS……keep it simple stupid………..how much more complex are they trying to make this than it really needs to be?
With all the sophisticated financial analysts needed in each company to measure financial performance and risks, there’s another raft of extra employees needed to manage the financial aspects, not of current financial performance, where a normal company would work out how much it has cost to make the product, add on a profit margin and charge that to the customer, they are, by virtue of making these CfD contracts for many years, necessitating the employment of whole new company functions that with a normal manufacturer wouldn’t be necessary.
As far as I can see, the whole electricity industry is turning into a massive make-work programme, far more complex than it actually needs to be.
Perhaps if it was investigated more carefully, it would be seen that it’s not the shift to renewables that is increasing the price of electricity, it is the complete financial restructuring and employment restructuring of the industry with many more functions being created due to the increasing complexity of how the system is being managed.
This is price increases by management cost, not the basic fundamental physical cost of producing electricity.
Come on Kathryn, this should be something that you should be shouting about, i.e. how the land leasing is increasing our electricity bills, especially when the developers have to add the financing costs on top.
And so where does that end up in a contract?
A higher Strike price for a CfD.
Is the government actually brain dead?
In reply to Nicholas Lewis, who suggested a CEGB mkII: Our hopes and aspirations can only lie with the Future Systems Operator, that is being consulted on and being defined and will actually be able to resolve all the problems that currently exist.
https://www.ofgem.gov.uk/energy-policy-and-regulation/policy-and-regulatory-programmes/future-system-operation-fso?sort=publication_date
Hopefully they will employ sufficiently experienced and broadly experienced personnel, and be able to give the strategic planning and be given the regulatory powers to deal with the complex issues and to get the electricity market working efficiently again.
There has to be an organisation that has a strategic overview, that understands the impact of different pricing mechanisms, can make things work, and start to build synergies and efficiencies back into the system. Perhaps there is some sense after all, where the last few years have displayed the inadequacies of the current system.