I have received a response from National Grid ESO to some of my questions on the Early Outlook for Winter 2022. In this post I update my analysis and add some further commentary on the risks to energy security this winter.
Reliance on interconnectors confirmed
NG ESO has confirmed that it is still modelling for the main Winter Outlook, which will be released in the autumn together with a data workbook. It has also confirmed that the “Other” category from last year has been re-defined – last year this included all embedded generation including storage, whereas this year, most of this has been re-allocated by technology ie embedded storage is now included in the Storage category, embedded thermal generation is in the Thermal category etc. This is what I guessed in my previous blog as the change seemed too large to be an outright change in asset availability.
It has re-iterated that the assumptions for interconnectors are in line with their existing Capacity Market obligations, reflecting the de-rated Capacity Market capacities that are “informed by modelling hundreds of thousands of simulations of Europe considering different weather (eg cold, wind), plant outages and stress tests (eg French nuclear availability)”, as reported in the Electricity Capacity Report published each year.
NG ESO says it recognises the uncertainty this winter relating to French nuclear availability and will continue to monitor the situation. It also confirms that its expectations are that IFA-1 will return in December – the Outlook says that it assumes the full 5.7 GW of nameplate interconnector capacity will be available “at times when GB needs it” – so essentially it is saying that it does not expect that we will need it before mid-December.
Reliance on intermittent generation, here and across Europe
I continue to be concerned about this analysis, and on further reflection, I also worry that NG ESO is asking the wrong question in its modelling. The methodology that underpins both the Outlook and the Capacity Market considers whether there are enough supplies on average to meet demand – average cold spell (“ACS”) demand in the case of the Winter Outlook. I have been consistently worried that the Capacity Market has been under-procuring what we need, and I think the reason for this comes down to the way that wind generation is being treated.
Wind, being intermittent, attracts a large discount in the de-rating process, however, I think even so it is possibly attracting too large a credit in these analyses. It is actually quite likely that ACS demand will coincide with periods of low wind output – high pressure weather systems result in clear, sunny, still weather which in winter is cold and frosty, boosting heating demand. These conditions can also extend across wide areas as seen in September last year and, to a lesser extent, in the on-going heatwave in Europe.
So I think the question NG ESO should be asking is whether there is enough supply available to meet demand on a low wind day, rather than on average. If wind is removed from the calculations altogether, what are we left with and would we be able to meet demand even with all interconnectors importing at maximum capacity?
Then there is the separate question about interconnector availability. As I noted in my previous blog, interconnectors have never been tested in an actual system stress event, so the assumptions about their behaviour are just that, assumptions, which may turn out to be flawed. On 18 July, the 8pm Capacity Market Notice was only withdrawn 9 minutes before the start of the period of potential insufficient supply, with a reduction in exports to France balancing the system.
But, contrary to NG ESO’s assumptions that power prices in GB would exceed those in France in a period of system stress, GB prices on 18 July barely crept above French prices very briefly and not enough to secure imports.
This reduction was enough to meet demand that day so with just this one data point it is not enough to draw conclusions either way, but the fact that the CMN was not cleared until so close to the short period, suggests that things were tighter than we would like them to be.
We also need to be aware that as electric heating is widely used in France, a high pressure weather system covering both countries would see electricity demand rise in France faster and to a larger extent than it does in Britain. In other words, at the time we are short of electricity, France will be even shorter. Prices in both countries will therefore rise rapidly, and if there is not enough generation across the two countries to meet combined demand, then imports from other countries would be needed.
But Germany, the Netherlands, Belgium and Denmark have all followed similar strategies to GB in that they have replaced conventional thermal and nuclear generation with wind power. If they also share the same weather system (which is entirely possible) then they will also be short because their wind will also not be producing. The charts above show the wind output across northern European countries in September last year and July this year (against 2021 installed capacity in each case which may introduce a small error in the numbers).
That leaves Norway, which has low reliance on wind, and an extensive hydro system. But a major uptick in exports since its 1.4 GW interconnectors with both GB and Germany opened last year combined with a dry year, has left Norwegian hydro reserves at close to 20-year lows, with Norwegian system operator Statnett warning of a 5-20% chance of electricity rationing and that Norway itself may need to rely on imports this winter.
Some analysts have suggested that the critical NO2 region, to which the interconnectors with GB, Germany and others are connected, may actually have a 20-50% chance of rationing. Norwegian ministers have signalled that they may consider restricting electricity exports as the situation in the country is becoming increasingly sensitive both physically and politically, with various politicians now calling for curbs on exports.
While a similar situation exists in the gas market where Britain must compete in the international markets for LNG, in gas Britain has two distinct advantages: it has LNG terminals which Germany in particular lacks, and it has more money relative to countries such as Pakistan, India and Brazil, who will lose access to LNG before we do. So while there is also a limited global supply of gas available, there is relatively more gas available than Britain could ever consume, and we are well placed to outbid many of the countries that typically buy this gas. While that is a horrible calculation, the reality is that as a rich country – which we are, however much it may not always feel like it – Britain can outbid many other countries in the global gas market.
The European electricity market is a different story. GB’s electricity demand as a proportion of northern European electricity supply is a much larger proportion than its share of the global gas market, and the countries with which it is competing are not significantly poorer. Could Britain outbid Germany, France, Belgium and the Netherlands for Norwegian electricity if it came down to it? NG ESO is assuming that prices in GB will exceed those in the other countries and electricity will therefore flow into Britain, and that the interconnectors will all perform as expected under their Capacity Market agreements.
But those agreements allow for a financial penalty in the event of non-delivery, and while that might under normal circumstances incentivise availability, it does not actually help if the electricity does not materialise. Prices in GB might not be higher than in all these countries if they are also short at the same time. And as prices rise, at some point they could go higher than the non-delivery penalties under the capacity contracts, making it cheaper for the contract holders to default and pay the penalty than to deliver.
National Grid ESO does not appear to have adjusted its methodology to take account of the changing market backdrop across Europe. It has apparently not adjusted the interconnector de-rating factors, and is continuing to rely on its un-tested assumption that Britain would be able to secure imports at full capacity at times of need.
That the models suggest the capacity margin will be a touch higher than last year despite the closure of around 4 GW of coal and nuclear capacity does not stand up to scrutiny. It is difficult to avoid the conclusion that the system operator is, at best, suffering from confirmation bias – ignoring inconvenient evidence that does not support its pre-conceived notion that “everything will be fine”. The early outlook does not pass the sniff test and should be amended.
All the talk of outbidding, doesn’t show linkage to the price businesses and individuals will pay – i.e. picture is already grim but if they have undercalculated, by how much. My monthly energy DD is £270
That’s a compicated question. Most of the time the wholesale component of electricity bills is based on gas prices and these will be much higher this winter. There will be times when we need to use all available domestic generation, which will increase prices, and then on a few occasions we might find outselves very short and in a bidding war with other countries. The big risk in those times isn’t cost but blackouts which although they also carry a serious economic cost, present a risk to life which is more important.
The ESO analysis is flawed on many levels.
The extreme and growing teliance on generation which is weather dependent across the EU. The fact that we are overdue a harsh winter with blocking anticyclones which give rise to super cold conditions and still winds for many days where demand is between 30 to 50% higher as wind and solar go to near zero output. That under such high demand the grid struggles to transport power due to congestion/constraints which regionalise the need for balancing. That interconnectors are useless when EVERY high population country in Europe has a deficit of production and market incentives are useless when there isn’t the generation capacity or transmission capacity available. Lastly when severe cold hits generation in western Europe it suffers from a lack of weatherisation meaning meaning auxiliary plant air ducts and fuel lines freeze and the generator starts to under produce or fail completely. Further those wind turbines that have icing protection turn on heaters and become additional system load. To.be honest the derating system falls apart with extreme cold. We will be into load shedding.
At least the CCGTs are dispersed across the network unlike wind is concentrated on East side of UK or in Nth Scotland and suffers from constraint issues and consequential costs already £525m on thermal management since 1.4.22.
I’d say bigger issue for us is lack of gas storage coinciding with a blocking high is going to risk CCGTs being vulnerable to forced switch off to protect domestic gas and no king coal to come to the rescue anymore. Still never fear the diesel peakers will be able to step up and earn silly money.
Personally a national blackout would be good outcome as that will make people wake and really ask what the hell has been going on.
Pray for mild, wet and windy weather
They know what the market conditions are likely to be this winter and know that its different.
As such they should also model a worst case scenario.
That is what I find so baffling about this. Apart from not updating the interconnector assumptions, they look at whether ACS demand can be met with average generation, but if the cold weather is caused by a system that dampens wind output then surely they should be modelling that.
As a layman, I have no idea of the relative size of the numbers but if the BBC/ITV were to broadcast a request to domestic electricity consumers to postpone high-power consumption tasks such as ovens and washing machines till the forecast peak had passed, does anyone have any back-of-envelope calculations on how much demand that would reduce?
Also I read a proposal that ‘background’ electrical devices such as fridges could be automatically switched-off temporarily during these peaks, possibly by sensing the frequency struggling. Again is this tinkering in the noise of the electrical demand or are the numbers worthwhile?
I think that getting people to voluntarily load shift out of the eveniing peak would have a significant impact. I have no idea if austomatically turning off standby devices would work – how would someone upstream of the meter know what devices are connected behind the meter even if there as a smart meter in place. That seems like something that might be developed for the future but doesn’t exist yet.
Peter, as a layman, suggests something that is firmly in the ‘experts’ plan – NG ESO’s “A Day in the Life 2035”. They require extensive customer participation, smart tariffs, smart devices, automation, seamless interactions between participants in dynamic markets, millions of assets and actors all in a system wide database,flexibility at local levels. They do however issue a warning about the “bull whip” effect – a modern market economists term. Victorian steam pioneers knew about this and before the death of outdated engineering this was called positive feedback. The ESO’s utopian dream is a hugely complex and unique control system with limited feedback. A vast computer game that will require everyone’s total involvement to avoid being hit by high prices or darkness. Demands will crash in based on dynamic price signals for other demand to crash out on flexibility frequency control signals. Whip crack away. Yahoo!
Roughly if peak demand from homes (residential sector) could be shifted away then you might expect peak demand to drop 30% (perhaps even more , but I am ignoring demand spikes due to social interactions like football halftime) from the residential sector , and this is the dominant demand sector in the evening. However, you can only put off eating for so long so demand won’t be shifted for long , and you can expect a spike once you tell people they don’t have to wait anymore. Sadly, I expect you can only ask the public to do this once or twice before the novely of it wears off and they ignore you. If this lack of generation is weather related then this sort of strategy won’t work as weather tends to last a few days to weeks, and people won’t bear with you.
Internet-of-things turning off of appliances automatically to serve the grid is nearly here as a technological reality. There is however no compensation to the owner for this service. (or reversely they are not currently penalised for not doing it) so I doubt it would be popular. BTW, smart meters CANNOT turn off your appliances or your home electric, that requires purpose built appliances.
In October last year I analysed the Gridwatch wind data from 2011-2021 looking particularly at the variability of wind. I found that the median generation was 18% of installed capacity while for 25% of the time output was only 10% of capacity. Incidentally, there seems to be hardly any trend of increasing output as more modern bigger turbines are installed.
The chart is here: https://twitter.com/peter_mott/status/1453389321944412160
Hi Peter, That’s interesting, thanks for the analysis.
The CM de-rating factors for wind in the T-1 auction (https://www.emrdeliverybody.com/Capacity%20Markets%20Document%20Library/Electricity%20Capacity%20Report%202021.pdf#search=electricity%20capacity%20report) are:
Off-shore wind: 11.33% (14.5 GW at the end of 2021)
On-shore wind: 7.81% (11.3 GW)
So the weighted average de-rating factor would be 9.79%, as as you say, output was below that level 25% of the time.
I’m also interested in whether the data suggested any variations over time. I have seen suggestions that wind intensity is falling (with some indications that the proliferation of wind turbines is making this worse).
I regressed Load Factor againt Installed Capacity and Weather, The idea was to see whether as installed capacity increased the performance got better (more offshore, better bigger turbines).
But only 8% of the variation is explained by the installed capacity, 26% by variability in the weather and 67% by other factors.
Your analysis as described will skew the result very low for the offshore wind component. Further, there hasn’t been much onshore wind installed since Cameron ordered the government to “cut the green c**p” in 2015, so the onshore component doesn’t reflect modern turbines and heights either.
See https://energynumbers.info/uk-offshore-wind-capacity-factors for individual offshore wind characteristics.
The point is that the offshore wind installed by the end of 2011 (would be age 10 years 5 months in the chart in the link) has no offshore wind farms with a recent 12 month (June 2021 to May 2022) capacity factor over 34%, and lots well below that, while almost everything installed since then has a recent 12 month capacity factor above 34%, excludes small demo wind farms and the couple of farms only just commissioned where there is an obvious issue with the ultimate final capacity being specified as soon as any generation started, but before all the turbines have actually been installed!
This has the two effects on your median figure
1) the lowest CF wind farms are present in all years while the higher CF wind farms only feature in the figures now, yet what we want to know is the likely median CF now, not the median CF in the 2016 mix roughly (it isn’t quite that, of course).
2) the installed capacity of the older wind farms is a lot less than the newer wind farms, so the older wind farms are punching well above their weight in the early years. Or put another way, the early years are punching above their weight given that the wind power capacity then was a lot less than it is now.
It is difficult to counter that low skew completely without using figures from individual farms, which you can download from Elexon after getting an ID, but the processing is complicated as it uses a RESTful web services interface. I have Java code which does this.
There is a slight issue that the Gridwatch figures don’t include a number of the wind farms connected to the distribution network (those not separately metered). The Elexon individual wind farm figures have a similar issued, but the Elexon summary figures are correct, I believe (and certainly considerably over the sum of the individual wind farms).
The energynumbers total UK capacity factor by year chart does show an increasing CF over the years, but again, it doesn’t show you the CF for the newer wlnd farms independently. There is roughly 1.5 times as much wind capacity to install by 2030 as exists now, and the CF of it should be spectacularly high. The evidence is that the Dogger Bank CF is likely to be 60%. See https://www.ge.com/renewableenergy/wind-energy/offshore-wind/haliade-x-offshore-turbine. Further, some of the 15 GW of Scottish floating offshore wind projects further offshore, which have recently signed leases, could reach a 70% CF based on the map of wind power density per swept rotor area – see https://www.azimuthproject.org/azimuth/show/Wind+power. Some of it is in >1,200 W/m^2 regions compared to Dogger Bank which is in an area of 900-1,000 W/m^2. Although the figures don’t directly translate to CF, even with similar turbines, the CF should be considerably higher than that for Dogger Bank.
We will know about the Dogger Bank offshore wind CF some time in 2023 when the first phases go live.
None of this affects the minimum output from UK wind, because all UK wind is within the 1,000 km characteristic length of a weather front, so it can all be low output at similar times on occasions. However, you can’t use the figures skewed low in your chart to challenge NG ESO assumptions without first correcting for the issues above.
Peter, the de-rating systems used are quite flawed in general, and whilst we could quibble based on a year’s worth of data from a given number of wind farms and if done on a European scale this could give you some indication of how quickly the European nations as a whole might draw down there gas… assuming various weather pattern/wind scenarios from October through April next year along with scenarios for LNG delivery rates and politics on the other pipelines etc. I think the more interesting point is the extreme weather not seen in 20 years. A large blocking high in 2010 meant that every available nuclear and thermal generator down to the last diesel was hooked up to the grid to pump in power. The European Grid itself was stretched to the limit with every major line at capacity. Britian was exporting full over our interconnectors; France could not meet it’s own heating load with domestic nuclear and was calling on its neighbours with a record 60GW of demand. Britian also had a record demand. The ESO also saw real issues with generators falling off the system due to lack of weatherising. CCGTs had coolant pipes freeze and air intake points freezing, resulting in shortfalling against PN/instructed level or complete failure and shut down. At the morning pickup after one exceptionally cold night, units that had been operating at low load failed to pick-up, others scheduled to start didn’t come onto the network, and those instructed to startup and replace them also failed to start. The ESO got to first stage load reduction (voltage reduction instructions to DNOs)… but that was in an era when France had reasonable nuclear capacity, Europe and GB had lots of gas storage and lots of nuclear and coal capacity as well. What was noticed was that the wind-turbines on the system were actually not generating but drawing lots of MWs to keep their nacels and blades heated to stop ice forming. I think that this winter if we get a large anticyclone covering much of western Europe, we will all be in serious trouble. The gas network will struggle to keep feeding generation and domestic load. As I said above under this scenario looking at average availability and load-factor/de-ratings of domestic generation and assuming interconnectors will deliver support is cloud cookoo thinking.
I need to read up on the full NG ESO capacity planning process. It would make sense for capacity calculations to be based on full simulations, rather than a sum of derated capacity. But it is difficult to see how you can hold auctions for capacity without some sort of crude derating process to determine who should win. I imagine you would then iterate with the results to see what is missing then go out and procure that.
UK solar (best in summer) is complementary to UK wind (best in winter). In general, a blocking high/anticyclone isn’t a good example of a weather condition that may cause capacity problems, because the air is clear, so solar PV output should be high. With appropriate storage that could be smoothed over into the evening peak.
However, in winter the days are shorter. And the UK only has a third as much solar PV capacity as it needs to properly complement the wind capacity installed, so that you can more or less add together the capacity factors to tell what the gaps to be filled are. Further, there isn’t much storage on the UK grid yet. None of this helps this winter, and something like 4 GW of coal capacity has been removed from the capacity records over the last year which may or may not still be around to be used in practice.
But Germany already has huge solar capacity, mainly without storage. And a lot of gas storage which should have a similar utility to grid battery storage if there is enough gas generation capacity
Texas had huge problems with freezing in the 2021 [day after] Valentine’s Day [not chain saw] Grid Massacre, mainly down to lack of winterisation of generation (mainly gas) and also lack of winterisation of the gas supply grid, which will not change because the gas producers made a fortune at that time. But you would hope UK and Europe would be able to regulate to impose suitable winterisation.
There must be some European grid liaison group which commissions simulations of the performance of the European grid, including the UK, which could be tapped into to determine how much or how little UK would be able to rely on interconnectors in a very cold anticyclone. That would surely be the sensible way to plan.
Surely the power required to stop a wind turbine from freezing is inconsequential compared to the normal average output, and inconsequential compared to the rest of the grid supply. I am not convinced that zeroes in the Elexon data actually mean zero output through an undersea grid cable connection – some of the zeroes in the data look a lot like computer data problems to me, but I’ve not looked as far back as 2010.
The loss of available capacity in Texas in Feb 21 was largely due to falling wind and shutdown of natural gas compressors when poor grid management led to a cascading series of plant tripsfor the most part. Winterisation would not have solved those problems. There was no wind to drive the turbines, and once the gas compressors were blacked out, no way to restore capacity. Incidentally, the Texas system is necessarily resilient to production losses, relying on storage to maintain gas supply in the event of hurricanes, so gas production losses were not critical, and lack of weatheeisation of onshore gas gathering facilities was not a critical factor for supply, albeit some producers missed out on some spectacular prices.
The fundamental problem was inadequate dispatchable capacity, which led to excessive risk taking by ERCOT who should have started imposing orchestrated rotating blackouts instead of completely running out of capacity reserve, which meant that losing one plant rapidly led to many more in a cascading trip with rapidly falling frequency., only halted by the automated disconnection at 59.3Hz, which in turn cut off fuel supply to some of the stations that remained on line, making recovery impossible until demand fell back..
In response to It doesn’t add up…
There were a variety of causes of the Texas Feb 21 outages, but they were pretty much the same as in February 2011.
The root cause issue was the lack of coordination between ERCOT and the gas suppliers. The gas supply is regulated by the Texas Railroad Commission (which regulates oil and gas but not railroads any more), and ERCOT is regulated by the Texas PUC. This is a political turf wars issue ensuring it is very difficult to resolve the problem long term, which is why February 2021 looked remarkably similar (but far worse) than February 2011.
The FERC/NERC report is summarised at https://www.ferc.gov/news-events/news/final-report-february-2021-freeze-underscores-winterization-recommendations. It says:-
“43.3 percent of natural gas production declines caused by freezing temperatures and weather, and 21.5 percent caused by midstream, wellhead or gathering facility power losses, which could be attributed either to rolling blackouts or weather-related outages such as downed power lines.”
Further, although Texas does indeed have extensive gas storage facilities, roughly one third of the discharge capacity of these facilities were disabled during storm Uri.
There was also a considerable issue from the fact that the gas suppliers had not registered all their installations as essential, so ERCOT did not know where electricity service had to be protected to them.
The criticism of wind is a red herring. Given you can’t rely on variable wind to provide generation at any point in time, there’s not a lot of point in winterising it in Texas.
There is an issue with winterising gas plants, which caused most of the ERCOT problem. One good way to do it is to enclose them, but if you do this you lower their thermodynamic efficiency (because of less cooling from the enclosure) at the summer peak. Since the summer peaks had always been bigger than the winter peak up until 2021, then it looked like a good decision not to enclose the gas plants – until suddenly it wasn’t!
There’s also an issue of knowing what demand would have been, if a lot of it hadn’t been suppressed. So no one knows for sure how high it could go next time.
There were large numbers of vested interests involved with the production of the official reports, which is why they are mainly whitewash. Although gas production was clearly interrupted onshore it was not critical to the loss of supply. Stored gas is dry gas, so stories about wet gas are also nonsense. The loss of pumping was critical. Much of the storage is in the Houston area, as this map of end Nov 2020 storage by county reveals
The conversion of pumping from gas powered turbines to electrical power let the problem slip between the cracks. It was all working fine until the multiple trip and automated load shedding. A more controlled shed would have allowed problems to have been identified and perhaps handled. But lose almost 10GW in a second, and it’s out of control.
Lack of winterising of plants did not cause most of the problem. It was a contributory factor, and arguably the straw that broke the camel’s back. The first and foremost problem was a capacity shortage. They had a demand forecast of 75GW and only 69GW of dispatchable capacity to meet it. They ran that capacity flat out with no reserve as the wind died back, and the loss of one station was enough to cause the cascading trip that knocked out everything else. I documented it all at the time with the frequency trace and other data from power traders’ info systems on which stations were knocked out. Reported the essence on WUWT and NALOPKT.
In response to It doesn’t add up… 9 August 2022 at 4:52 PM
For the Texas Feb 2021 blackouts, there was no prior expectation of a demand of 75 GW as you claim. That figure was the estimated peak demand with the benefit of 20:20 hindsight.
From the Magness Feb 24 “Review of February 2021 Extreme Cold
Weather Event – ERCOT Presentation” the peak estimated (after the event) demand was 77 GW, compared with 59 GW for the February 2011 event. The temperatures in various locations were down, but the significant difference was the worse wind chill on the first day of the storm, rather than the temperatures.
The final ERCOT seasonal assessment for winter 2020/21 had an expectation with average weather of 57.5 GW of demand, to which was added 9.5 GW of worst case weather prediction to give a total of 67 GW of peak expected winter demand.
Further, your claim was for 6 GW of under capacity as the primary cause. From the ERCOT “February 2021 Extreme Cold Weather Event: Preliminary Report on Causes of Generator Outages and Derates”, for the critical period midday 15 to midday 17 Feb, there was roughly 50 GW of capacity not available, of which roughly 8 GW was “Existing outages” (= “ongoing planned and forced outages as well as seasonally mothballed units.”) and a small quantity of “Various”.
ERCOTs survey shows 6 GW of fuel outages, and 34 GW of “Weather related” (27 GW) and “Equipment issues” 7 GW.
There is very little doubt that the majority of supply loss was due to gas generation not operating when it should have been, and this was reflected in the FERC assessment at https://www.ferc.gov/media/february-2021-cold-weather-outages-texas-and-south-central-united-states-ferc-nerc-and. See the executive summary. It is generally pointless to rely on wind power to deliver firm supply – its big strength is supply cheap energy on average. Thus the majority of the issues by GW of generation were entirely dependent on either gas plants freezing above their rated temperature, or the supply of gas to them being restricted or cut off.
I suppose the hope is that having a large anti-cyclone over the summer, we won’t get hit again in winter. Not the best approach to energy security though…
This is a fair criticism of which I was aware (see my second comment). The fact remains that the characteristics of the wind fleet will only change slowly and the chart shows how it has been so far. Also I just posted the chart for general interest, not as criticism of the NG ESO assumptions.
I had no idea you could get an ID to see what individual wind farms do – can you give me a link to start the process of getting an ID?
Email me at my gmail ID of peter090654.
Mail sent — thanks
I recalculated the chart for period 2018-8-1 to 2022-8-1 . Capacity Factor had improved from 18% to 23%.
It is sad to see the once rigorous system operator behave in this way. It is desperate not to reveal the fatal flaws in the current plan for a predominately wind and solar future. Averages have no place in a power system as they are in essence energy calculations. In calm winter evening peak conditions solar will be at zero MW output and wind at only a few hundred MW (as recorded outputs show) not at some cleverly calculated average figure. As regards not requiring full inter connector capacity until mid December this is again wishful thinking. The peak demand usually occurs in November, by mid December demand is reduced by the holiday period and then by darkness moving later in the evening. In addition there is usually a capacity shortage in October/November as plant returns late from summer outage.
The flaws will become more apparent as volumes of wind and solar increase but although NGESO claims to have looked at this it is silent on the results other than to say “success is uncertain”.
I agree. I think ESO is increasingly political in its discourse and seems more concerned with not being see as a “block” to net zero than acting as an honest broker, identifying risks and ensuring both BEIS and the industry are aware and can prepare. This will actually get worse when the FSO is set up – as a branch of the civil service it will be even more prone to ideology capture and less likely to give an independent view, despite the whole point being to set up an independent body.
The more ESO cheeleads for net zero, the less I’m inclined to trust its analysis. Unfortunately blackout risks this winter are real, and will not be mitigated by wishful thinking. Come the Spring we might be commenting on the inevitable post mortem that this was all foreseeable unless we have an unusually mild and windy winter…
Rather flippant but true, in light of this, I have spent all of my £400 of govt. energy payments on coal. Needs must.
Not a bad call. We have a small petrol generator but I’m considering upgrading it to diesel since diesel keeps better…
Diesel goes off too, notably there are a variety of bugs that like to grow in diesel creating a horrible slimy mess that engines (or at least fuel filters) do not like.
The best choice depends on what you are looking for:
– Petrol – cheap engines, relatively expensive fuel (very difficult to come by petrol without paying Fuel Duty). Fuel doesn’t keep well.
– Diesel – more expensive engines, cheaper fuel if you use red diesel. Fuel will keep longer than petrol provided you don’t get bugs growing in it.
– LPG – slightly more expensive engines than petrol (most are petrol conversions), fuel cheaper than petrol but more expensive than red diesel, fuel keeps more or less forever (but comes in heavy containers).
If I wanted a backup generator in the ~2kW range for occasional use I would go for LPG every time as I wouldn’t need to worry about the fuel going off (and I’d gradually rotate the fuel over several years by using it in my gas BBQ).
If I wanted a generator in the ~10kW range which I expected to use regularly then I would go for diesel.
How reliable do we expect our supplies to be?
I hadn’t thought about LPG, so that’s interesting. I was basically thinking about getting the fuel from a petrol station, but LPG could be a better option. I don’t have a gas BBQ but know people who do, so that would allow for fuel cycling over time. Thanks for the tip!
An excellent blog and set of discussion points, absolutely rivetting. I work in the Power Generation sector and 3 years ago I installed a 7KVA dual fuel generator because without a petroleum storage licence only a few litres can be stored in cans. LPG cylinders are unlimited. Careful though as the BBQ ones, ironically painted green are not capable of being connected to the generators. The orange Propane ones are for the gennys. It uses 1KG/Hr.
It is my belief that industry will approach HMG with a request for some of them to have an interruptable supply so they can benefit from cheaper tariffs. That way HMG gets to shut them off to save energy….maybe i’ll be asked to run Genny!!
Has anyone modelled the final destination for home heating, which will in the future (so we are told) be predominantly be based on electricity as will be cooking?
Presumably, the demand curve will be drastically changed from the current one depending on the mix of direct resistive, local storage, and heat pump use. Once we reach this “nirvana” it is likely to be even harder to match supply and demand with renewables and so nuclear and storage will be essential.
For renewables to still have a place in electricity production we will need cheap storage. Is there a clear leader (or leaders) in this regard? My own gut feeling, based on what I have read on storage options, is that local thermal, for example domestic storage systems are a good option. One of the perverse reasons for this is that the customer pays for the hardware. Also, has anyone modelled the optimum positioning for wind farms to provide the most consistent and secure wind generation?
❝ My own gut feeling, based on what I have read on storage options, is that local thermal, for example domestic storage systems are a good option❞
In 1961 my mother installed in an old rectory she had bought as a guest house (such places were very cheap then) “night storage heaters”, essentially blocks of concrete with an electric element in them. They turned on at night when electricity was very cheap. Various forms of electric fire bars were needed as well on cold evenings – I remember the two bar one in the living room clearly.
It was a survivable set up, I was there in the foul winter of 1962. One point is that the heaters were big, there was lots of space in that house. They did not heat the water of course. Hopefully climate change will continue to deliver warmer winters.
Yes, storage heaters were a basic but reasonably effective way of storing energy and used a form of time-of-use pricing known as Economy 7 (fun fact: the price signals were delivered to the electricity meters using the longwave carrier of BBC Radio 4 (198 KHz)).
I wrote a post about thermal storage a while back (https://watt-logic.com/2016/07/26/thermal-energy-storage/) – it could do with updating. The trick with thermal storage is that phase changes need to be in the right temperature range to be useful and that the weight / bulk is not un-manageable.
A thermal storage facility using sand has recently opened in Finland (https://www.renewableenergymagazine.com/storage/first-commercial-sandbased-thermal-energy-storage-is-20220707) connected to a local heat network.
There are a various storage technologies in development such as cryogenic (Highview), compressed air and even gravity based (using weights rather than water). Also there are different types of chemical batteries being developed which would have better properties (and be cleaner) than li-ion. I expect that we’ll see a combination of different approaches as none of them currently stands out as a game changer. Thermal and chemical batteries are likely to be the main technologies used in domestic settings (unless something new is invented).
I analysed the wind output in the highest demand half hours for 2015 some years ago. It looks like this
The chances of very low output coinciding with high demand are very high. We saw it again last December in the period of Dunkelflaute ahead of Christmas when day ahead prices ran up to £1,500/MWh and balancing trades were over £4,000/MWh, with all available generation and interconnector imports maximised.
It is really hard to see Continental countries imposing power cuts on themselves to keep the lights on in the UK. I think there will a number of sudden breakdowns at converter stations to allow declaration of force majeure to evade penalties. I suspect the Norwegians have already been exploring the opportunities: there have been long periods where they only made half the capacity available, plus the reported problems at converter stations.
We know already that there are plans to pay up to £6/kWh to domestic DSR participants via aggregators. These will doubtless not be counted as power cuts, but I doubt they will run beyond a small volume anyway. It sets the standard for compensation payments for power cuts not accepted voluntarily. The payment of almost £10,000/MWh recently is equivalent to well over £1bn a day if we pay out on interconnector capacity. Such amounts are not acceptable.
I completely agree. I suspect that we will see appeals to the public to voluntarily reduce demand at certain times of day. Texas has been doing that this summer, and various European countries are already asking people to conserve gas. They won’t get paid for this, but it could reduce the risk of blackouts by shifting load out of the peaks. Given the Government has the ability to send text messages to everyone, you could even get granular with this to avoid everyone in a given area acting the same way, although I suspect it would take them a while to get something like that up and running…Or they can go old school and use the loud hailer vans they used to have to announce things like power and water outages
The other side of the coin would be the French outbidding us: 2GW IFA1, 1GW apiece IFA2, Eleclink for a swing of 8GW in supply.
Its exactly what we need some grown up leadership to explain the facts of life and that if this request is made then everybody doing a little will ensure the lights stay on for everybody. Nothing wrong with that in my world but no doubt certain papers and commentators would go on a mega whinge fest.
Also with exorbitant prices now being predicted there must surely be some natural demand destruction. I for one now don’t leave lights on for effect anymore. Ive had a 100% conversion LEDs where i can. Ive dropped some food products that take more than 30mins to oven cook.
Parents in the 60s had hopes of a future based on abundant nuclear energy and storage heaters at that time were fairly primitive, but so much easier than burning coal in a grate and all the mess that went with it. Since then, technology has improved. Even my 35 year old GEC Nighstor storage boiler will happily store 100 kWh from an overnight charge for distribution round a conventional wet radiator system, losing only 10% of the stored energy per day. The more modern version, made in the UK, is the Tepeo ZEB (Zero Emission Boiler).
The point I am making, however, is that to make the best use of wind, there will have to be a cheap, efficient and safe system for storing energy. It may be that other storage technologies will be viable, but in terms of the conversion and storage cycle, local thermal storage has many advantages.