Last year I warned repeatedly that Norway can not be expected to sit passively by while other countries drain its reservoirs and that it may well take steps to restrict exports. I drew attention to comments by Norwegian Prime Minister Jonas Gahr Støre, and Energy and Petroleum Minister Terje Aasland and the fact that prices in Norway had soared since the opening of large interconnectors with Britain and Germany in 2021 with the Government having to subsidise end users to up to 90% of their bills. At the same time, a dry year until the autumn saw reservoir levels fall to 20-year lows. Studies commissioned by the Government pointed at the interconnectors as both reducing Norway’s security of supply and driving up prices.
“We must have control that we have enough power in Norway. The bottom line for this is our own security of supply. We must be sure that we always have enough water in our reservoirs. There must always be electricity in the socket and we must have enough power for our industry”
– Jonas Gahr Støre, Prime Minister of Norway
For months the Norwegian government signalled that it was inclined to act. Last week it announced measures that could indeed see market interventions that would restrict electricity exports in order to protect security of supply in Norway. Legislation will be brought before the Storting that will require producers of hydropower to contribute to security of supply, with new obligations at times of low reservoir levels or “where there is a prospect that reservoir filling may reach low levels”. In its press release, the Government explicitly references the prospect of restricting exports. The measures should be in place before next winter.
Details of Norway’s hydro protection measures have been announced
The mechanism consists of the following measures:
- Creating a legal duty for hydropower producers to contribute to the security of electricity supplies
- Formalising the reporting scheme for hydropower producers from summer 2022
- A requirement that hydropower producers develop strategies to ensure security of supply, allowing access to the energy authorities for the control and supervision of these plans, including the imposition of sanctions where necessary
- Powers for the energy authorities to intervene in reservoir allocation, in situations where there is a real danger of energy shortages
- Clarification that restrictions can be imposed on foreign connections in situations where there is a real risk of energy shortages
“The review of the power situation 2021-2022 concluded that the Norwegian power system is now more vulnerable than before to unexpected events. With the change in the law we are now starting, we emphasize the producers’ responsibility to contribute to the security of supply. It is a tool to better secure the very cornerstone of the Norwegian power supply – our adjustable hydropower.
The situation we now see in the energy markets in Europe can extend over a long period of time. The energy authorities will therefore assess the power situation on an ongoing basis, and use the various steps in the mechanism when the need so requires,”
– Terje Aasland, Minister of Petroleum and Energy
The control mechanism will take an incremental approach, where stronger measures can be adopted if threats to security of supply escalate. The mechanism is explicity intended to ensure the security of Norway’s electricity supplies, and not to reduce power prices.
Norwegian energy authorities already have the right to intervene in hydro production in situations of rationing, however this new mechanism would allow for earlier intervention by the authorities. However, interventions would be strictly limited, and only apply in situations where there is a real danger of a shortage of energy and, it is clear that the producer’s own risk assessment deviates from that of the authorities.
Work on formalising the scheme will begin immediately. Norway’s Directorate of Water Resources and Energy has been commissioned to start the regulatory work, while the Ministry of Petroleum and Energy will start the legislative work. The scheme must operate alongside existing measures for highly strained power situations (SAKS).
While export restrictions are normally prohibited under EU law (and Norway has some responsibility to follow these laws as an EU trading partner) trade rules do tend to allow for temporary restrictions in times of shortages (but not motivated by controlling prices).
“There has been uncertainty about whether and when export restrictions can be used. Here, however, there is room for manoeuvre within EEA law which we wish to use. I would therefore like to make it clear that, for reasons of security of supply, restrictions can be set on foreign connections if there is a risk of energy shortages, also before we get into a rationing situation for Norwegian households and businesses,”
– Terje Aasland, Minister of Petroleum and Energy
The question is whether an EU that is heavily dependent on Norwegian gas is going to get into a fight over access to Norway’s electricity resources while at the same time allowing countries such as Germany to voluntarily close perfectly good nuclear power stations. Norway has boosted gas production in order to support the EU’s quest for non-Russian gas – it could easily pull back to previous norms without violating any agreements.
Norway’s neighbours have reacted with concern
Norway is part of the European common market via the European Free Trade Association (“EFTA”), which also includes Iceland and Liechtenstein. The EFTA Surveillance Authority (“ESA”), which monitors the group’s compliance with common market rules, has expressed “concern” at these proposals, and indicated it intends to enter into discussions with the Norwegian Government.
“Any measures that may lead to restrictions on the power market in the European Economic Area are of concern,”
– ESA spokesperson
Others have also reacted with alarm at the proposals. Johannes Bruun, a director at Danish network operator Energinet, has been quoted in the press saying “the whole narrative in Norway is wrong”. But the Norwegian Government appears to be determined, noting that Norway’s electricity system is unique in Europe, depending on a resource which can run out and not be replenished until the weather allows.
In Britain, there is a strong rejection of the idea that it may be dangerous to reply on imported electricity. Fintan Slye, Chief Executive of National Grid ESO recently told me that he saw no prospect of Norway ever restricting exports to Britain, while Cordi O’Hara, president of National Grid Ventures which co-owns the interconnectors says there is “a clear recognition that our interconnectors to Europe are mutually beneficial.” I suggest that both pay much closer attention to what Prime Minister Støre and his Energy and Petroleum Minister have been saying over the past year: Norway has had enough!
Time to re-think the approach to interconnection
It is clear that TSOs love interconnectors. They allow them to defer investment in domestic generation and transmission capacity, having the benefits of those assets when needed without the downsides of having to pay for them (or get their domestic consumers to pay for them). They often also participate in the economics of co-owning those interconnectors, presenting a clear conflict of interest (in Britain, the separation of the TSO from the ownership of transmission assets helps to mitigate this risk, but no such separation exists in other European countries).
But there are two risks that have been ignored so far – what if a connected country cannot supply electricity when needed, and what if it decides it doesn’t want to? Somewhat bizarrely, despite assuring me that Norway would never restrict electricity exports, in the same conversation, Fintan Slye told me he was worried the EU may refuse to export gas to Britain when needed, threatening our ability to generate electricity from gas. Indeed the official reasoning behind both the coal contingency and Demand Flexibility Service was the concern over access to gas supplies.
Countries may not be able to export if they lack surplus electricity. In France, prolonged nuclear outages have turned the country from a habitual exporter to an importer, while Norway has had very public concerns over reservoir levels in the southern NO2 region for most of the past year. The other risk is that with many European following a wind-led energy transition, at times of low wind speeds, many countries may require imports at the same time, exceeding the capacity of exporting countries to fill the gap.
It seems unlikely that we can continue on the current track of automatic cross-border flows based on short-term price differentials while countries make decisions about generation and transmission capacity at the national level. This is leading to situations where citizens in one country are subsidising the choices of governments elsewhere, which is unfair and likely to be unsustainable.
If NG ESO worries that the EU might restrict gas exports why is it not at least similarly worried about Norwegian electricity exports? Everyone wants to have their cake and eat it, but what if the bakers decide not to play any more? Better to make sure the market works for everyone than to pretend there are no problems, but it does not appear that many people are willing to take Norway’s concerns seriously despite the fact that it is literally bringing forward legilsation to restrict exports in order to protect domestic supplies. Ignoring this is something we may come to regret.
Oops … & there was us thinking ‘johnny foreigner’ would always keep “Blighty” powered at all times !
Today was a mild day, yet we imported 11.7% electricity
Norway is wise to look after itself first.
According to Nord Pool data (https://www.nordpoolgroup.com/en/Market-data1/Power-system-data/hydro-reservoir1/NO/Hourly/?view=table) reservoir capacity is above what it was a year ago and NO2 is significantly higher than last year. Mind you i get there issue as they have very limited alternative generation if they run out of water so not unreasonable but you do have to wonder whether they really thought through agreeing to all the interconnectors. A cursory glance at the NSL graph would suggest its c 70% import 30% export i wonder if the German one is similar.
Yes, the autumn was wet and reservoir levels have steadily improved, but reaching 20 year lows in the year after the interconnectors with GB and Germany opened rightly in my view spooked Norwegians.
Statnett has export data per country here: https://www.statnett.no/en/for-stakeholders-in-the-power-industry/data-from-the-power-system/#import-and-export
Overall exports were 65% of the time in the past year. It looks as if Norway imports more from GB than Germany but that’s just from looking at the chart. I think you can also download the data if you want to check properly.
During last summer when the water levels were low the power flows were almost always from UK to Norway thus helping them to avoid further depletion of water reserves.
Cake and eat it comes to mind.
As a long term Norwegian resident I can fully understand the national concerns. Norwegian society and industry is totally dependent, and was established, on cheap hydroelectric power. There is no alternative. Even though Norway is Europe’s largest gas producer the domestic use is zero. Not only that, but, in recent years offshore gas production and compression have become totally dependent on electricity from shore, the gas turbines that previously powered the platforms have been decommissioned. There was a real danger last autumn that gas exports could be restricted due to lack of available HEP capacity.
As a Brit I find it naive that national energy strategy assumes there will always be power available from the interconnectors!
Ordinary Norwegians must be wondering what’s happened to make their energy suddenly so expensive, when it’s all home grown.
It looks like over the last couple of months, the UK has both imported and exported electricity in roughly equal amounts (I went back to Dec 1st on the website you helpfully provided a link to).
I thought the idea (if not the practise) of this Norwegian interconnector was to allow imports from Norway when wind power is lower and exports to Norway when wind power is high. In theory, shouldn’t that not impact on Norwegian energy security/prices?
Thanks
Richard
Most of our exports have been to France not Norway, and we still often import even when it’s windy…look at today for example (https://www.gridwatch.templar.co.uk/) it’s very windy but we’re importing at the max from Norway while exporting to France. We do sometimes export to Norway, but often those exports are at night. Because Norway cannot easily pump water to restore reservoir levels (only 1.4 GW of its 33 GW of hydro has pumping capacity) imports only displace hydro generation and if the imports happen at times of low demand they are less useful.
Also, the interconnector trading with Norway is Day Ahead only – there is no within-day re-trading, so it’s a lot less efficient than it could be.
Thanks Kathryn – had no idea about those issues with the interconnector and Norwegian Hydro.
All the connectors to Norway are two way. Every time UK exports wind power or France exports nuclear to Norway, Norway can conserve a quantity of hydro water capable of generating the same quantity of electricity as Norway has just received, so that some of the Norwegian internal country demand is satisfied by the foreign imports instead of by hydro water.
In times of Norwegian hydro water shortage, the power export rules should specify activation of a “tit for tat” provision that the Norwegian exports over an interconnector should be no more than the Norwegian imports over the same interconnector in the same year.
If the Norwegian hydro water shortage is acute enough that, without imports and exports, Norway would not even have enough water to supply power to the whole of Norway for the year, then a “3 for the price of 2” rule (or whatever ratio is necessary) should apply – Norwegian exports must be no more than 2/3rds of the imports over a given interconnector.
There should also be some sort of market so that the foreign grid operators at the other end of the interconnector can trade Norwegian hydro export rights between interconnectors. The rights should terminate each year at some sensible time, such as just before the big Norwegian snow melt, perhaps.
If it is true, then that is probably the reason why exports of Norwegian hydropower to UK are unlikely to be suppressed – the UK may well provide enough of its wind power surplus to Norway to cover the expected imports the UK is hoping to receive from Norway.
This hydro export control mechanism should be on top of the normal pricing mechanisms, though it would clearly affect pricing too.
The flows on Norway’s interconnectors last year were 65% exports vs 35% imports. Yes, imports can displace the use of water, but if they occur mostly at night they won’t be of much use. But the key issues if that once the water is gone it cannot be replaced by any human action which is a pretty unique situation in electricity generation. So Norway’s reservoirs can be drained but it cannot replace that electricity with imports because the interconnetor capacity is too small even if prices skyrocket prompting imports for economic reasons.
Another factor is that we often import from Norway even when it’s very windy here, eg today – max imports from Norway despite high wind, either because we have to curtail some of our wind production due to lack of network investment or because Norwegian hydro is cheaper than GB gas generation. And we’re exporting to France, something which might become a market feature as the French nuclear fleet ages (currently only one new reactor is in the pipeline and who knows if EDF will ever manage to finish it…).
Also the Norwgian interconnectors only trade DA whereas the French ones re-trade WD.
So although the cables can flow in both directions, it doesn’t mean there aren’t significant asymmetries in the way in which they operate, and unless these are addressed, I think Norway is correct to protect its resources.
According LCP Energy ( https://enact.lcp.energy/ ) we have already constrained off 32GWh of wind today which is more than NSL can transmit in 24hrs yet its running full import because the fact our transmission system is being out run by more and more wind being added without parallel investment in the transmission system.
This is one of the reasons I include transmission as well as generation when I talk about interconnectors replacing domestic investment.
We have several times reached the situation where domestic transmission from the North is inadequate to keep France and London supplied. It led to the very costly import on NEMO at almost £10,000/MWh and to pleas to reduce contracted exports to France. National Grid recently discussed this and their other plans to multiply their asset base and business by supporting renewables and net zero objectives.
https://www.current-news.co.uk/news/etys-2023-predicts-widespread-renewable-growth-but-transmission-concerns-amounting-in-the-south-of-england
Of course the BritNed interconnector was built to replace the Greenpeace/Goldsmith prevented Kingsnorth D coal station, connecting at Kingsnorth. At least the Dutch built a replacement coal station the other end of the line at Maasvlakte, but that had been under threat in recent times from the EU and Dutch anti coal push. UK consumers have been landed with the extra cost.
In response to “It doesn’t add up…”
According to EMBER’s 2022 analysis and 2023 forecast report at https://ember-climate.org/app/uploads/2023/01/Report-European-Electricity-Review-2023.pdf the expected return of coal generation over winter 2022/23 has been very much a damp squib.
EU coal generation rose 7% in 2022, but was concentrated in the early part of the year, while coal was down in Q4 2022 (p8).
Apparently the 26 EU plants with 11 GW of capacity extended or reactivated had only an 18% load factor in Q4 2022 (p17).
A further 11 GW of coal plants in the Netherlands and Italy had capacity or load factor restrictions removed, but the four Dutch plants originally restricted to 35% operated at only 45%, compared to 65% in Q4 2021. The Italian plants ran at 30% which was the same as 2021.
EU coal imports were 65 Mt in 2022 vs 45 Mt in 2021, but two thirds of the 2022 imports were not burned but stockpiled (P18).
And no EU country is changing its coal phase out dates, despite a few extensions for a year or two to mitigate against gas shortages and high gas prices.
And all this was despite reduced hydro output due to rainfall, and nuclear output due to the ongoing German phase out and French problems with cracks in (standby?) cooling systems.
Meanwhile wind and solar rose to 22% of EU supply, with solar up a record 24% (p23). Solar delivered 12% of EU power May through August when the pressure was on the most, and the 2022 average was 7.3% vs 5.7% in 2021.
The Netherlands generated 14% of supply from solar – around 14 TWh, compared to UK’s 11 TWh. A few spot checks show most of the imports to UK May through August on BritNed were during the daytime, so there is an excellent chance that UK was importing more solar over BritNed during this period than coal power.
You have to look at the operation of the MPP3 coal station. It is right next door to the BritNed HVDC converter. Any time it operates and BritNed is exporting its power goes to BritNed. Only if its output is less than BritNed export can any other source contribute to BritNed. There is no way for its output to be routed anyhow else. It only gets to contribute to inland supply if BritNed is not exporting, or is exporting less than MPP3 output (in which case 100% of export comes from MPP3).
There are good reasons to suppose that MPP3 was operated much more than other coal stations. It is the newest and most efficient. It is right at the mouth of the river, with its coal yard directly filled by the largest bulk carriers, making its import costs the lowest. If there is a renewables argument it will be about the amount of biomass cofiring.
Also note that Dutch exports to Belgium and Germany were somewhat higher than those to UK. Dutch solar farms are much better placed to feed those exports.
https://resdm.com/solar-farms-in-nld
And that Ember is a green propaganda outfit, which always slants its work accordingly.
@It doesn’t add up
I doubt that Ember is fiddling the figures it puts out.
When considering whether MPP3 is supply most of the power exported to UK over BritNed, physical proximity isn’t a good argument. The Netherlands is a small country and presumably has a well connected grid. So grid losses will be low and physical siting of plants and loads should be far less of an issue than for the UK.
Further, coal plants in the Netherlands are subject to the ETS which prices in carbon, in a similar manner to the UK scheme. A few years ago ETS credits were too cheap, but these were mopped up somehow, and the ETS does now cost coal plants significant money when generating – carbon prices in 2021 and 2022 were up significantly. The EU was talking about making extra credits available because of the gas shortage, but “borrowing” them from future years so cumulative CO2 emissions didn’t increase.
The best way to determine whether MPP3 was mainly supplying BritNed power would be to take the generation from MPP3 and do a time slot correlation with BritNed exports to the UK. That would tell you whether MPP3 is fired up specifically to provide exports to the UK. My guess is that it would not be, because the carbon taxes would make that uneconomic, except at critical (rather than just daily peak hour) times, when most generation to hand would be active.
Anyone have the MPP3 time slot generation data? I could probably get BritNed data from my Elexon downloads (which ignores interconnectors at present) and analysis.
Sorry. You are wrong. There is basic physics involved here. Power can only flow in one direction at once between nodes on a transmission line. The power station is on the artificial Maasvlakte port island at the entrance to Rotterdam port areas at the mouth of the Rhine. There is ONE set of power lines leading away from it heading inland from the switch yard that also has the connection to BritNed HVDC. The power station output must go to one or the other, or both. You can see it all in satellite view and street view. You cannot have the situation where the power station is feeding the inland market while BritNed is being fed by other sources. Only if the power station is shut down or producing less than the total export can there be a contribution from other generation, which will be the difference between the total export and the power station generation. The fact that the BritNed often operates continuously at a constant load is well, suited to MPP3 operation as baseload.
Whilst you are correct that EU ETS imposes a tax on coal fired production, it has consistently been less than the UKA cost. Moreover, because MPP3 is more efficient than other coal fired stations – it claims up to 46%, making it more efficient than OCGT and fully competitive with CCGT – and cofires biomass which is EU ETS exempt, the impact of carbon tax is not as severe as you are assuming by a long way. Old coal is around a third efficient. Finally, coal has been consistently much cheaper than gas, even for old power stations paying carbon taxes. Any diminution in coal running is about politics and quotas, not economics: the UK could have saved several £billion by running its old stations as baseload. Incidentally, MPP3’s cooling water is used to provide LNG reheat across the dock at the GATE LNG terminal.
I am sure EMBER take care to source data accurately. However, it is clear that the way they present it always emphasises green perspectives. Any time they are free to make assumptions they do the same thing, such as their recent study claiming that the UK could achieve 100% renewables without significant storage or any interconnector imports. Dig, and you find that their wind generation is assumed to be “just right” with no extended Dunkelflaute, and very high capacity factors.
View on a laptop or in landscape format:
https://goo.gl/maps/beZ3RwptxYAMVkte9
On the left – MPP3, chimney active in June 2022. Straight ahead, MPP2 that it replaced: the lit green plug relates to – to the right: BritNed HVDC converters, and switchyard, transmission connection inland. There is another coal fired powerstation now described as owned by Onyx that connects a couple of km further on. It had been slated for closure, but was rescued to provide support to the grid last year. It is also high efficiency, and biomass cofiring.
https://www.onyx-power.com/en/locations/power-plant-rotterdam/
@It doesn’t add up
Sure, you are correct about the physical flows of power on the grid connections around BritNed and MPP3 that you describe, but that is not the point.
Power lines (and grids) effectively net off flows between nodes. This is great for overall efficiency, as power that doesn’t flow through a line isn’t subject to transmission losses. But the netting off doesn’t actually change the contractual arrangements for power – who is selling it and who is buying it.
What is important is who is contracted with whom for the power flowing over BritNed. For instance, if the UK NG ESO contracted in a PPA with a solar farm in Holland (or even an onshore or an offshore wind farm in Germany) to take all its output at a fixed price, then that is the commercial arrangement over BritNed. Whether MPP3 is generating or not would then be irrelevant, unless it is involved in the contracts. Thus MPP3 would only be generating when someone else contracted that it should do so, and thus is buying the power. If that second contract were not active to supply power at any moment then MPP3 would not be generating – and would thus not depend on the BritNed flows. This is only an example, of course.
So far you haven’t presented any concrete evidence that the contract for power exported to UK via BritNed has anything at all to do with whether MPP3 is actively generating or not. It is more likely to be price which determines the contracts for power to flow over BritNed into the UK grid than anything else.
Firing biomass is great, and should indeed reduce carbon taxes, but both coal (plus carbon costs) and biomass are generally more expensive than typical (non Putin energy war era) wholesale prices of gas generation. That is precisely why UK coal usage dropped from 40% in 2012 to 2% or less over the last few years. It was economic forces, not political forces. The absolute UK coal ban in 2025 is entirely related to climate. – which you seem to describe as “politics”. Coal generation has roughly twice the CO2 emissions of natural gas, at 1,000 gm CO2/kWh vs 500 gm/kWh. With some biomass firing that would be regarded as coming down by the EU.
Yes there was a period some years ago when there was a surplus of ETS credits and they were cheap as a result. And there has been some “pull forward” of ETS credits from the future, intended to assist in the response to Putin’s energy war – but these will reduce the supply of credits and increase the price in the future is my understanding. And ETS and UK scheme carbon credits have been at similar prices recently.
The only way to assess whether a proposed net zero system reliably meets demand is to simulate the system using actuals, and that is what invariably happens nowadays. For instance here is a report on simulations of a 2050 UK grid, using time-correlated actuals shows that various options for a UK grid involving wind, solar, various quantities of nuclear, grid battery storage and green hydrogen backup will reliably meet predicted demand. See https://spiral.imperial.ac.uk/bitstream/10044/1/88966/7/EFL_Net%20Zero%20GB%20Electricity_White%20Paper.pdf.
And here is a write up of my own simulations of the Texas ERCOT grid using scaled time-aligned actuals for demand, wind output and solar irradiance from 4 sample places used to projects two-axis tracking solar output – https://judithcurry.com/2017/05/14/electricity-in-texas-is-100-renewables-feasible-part-i/.
Perhaps you would like to point precisely to the evidence that the EMBER projections are not based on simulations of actual demand aligned with (scaled) wind and solar generation?
I have already pointed to the evidence that EMBER’s work relies on unicorn assumptions. Download their spreadsheet and you will find their worst case average annual capacity factor for onshore wind is 31.75% and for offshore it is 48.9%. Now try comparing that with data from Energy Trends on quarterly capacity factors actually achieved back to 2010 and you will see that as an annual average those assumptions are higher than the best historical performance, and bumps up wind output ~50% compared with real worst cases. Is that really a realistic basis for modelling? The solar worst case is likewise an exaggeration of reality. They pick a gas price from last August, during the spike caused by the shutdown of Nordstream as the basis for their gas costing. Utterly unrealistic greenwash propaganda. Note that their report refers to consultations with the Climate Change Committee – i.e. this is propaganda in support of the CCC narrative.
Imperial may have made some effort to model demand, but it is frankly redundant given that they are assuming 140GW! – yes GW of short duration batteries to help with balancing, huge amounts of DSR, plus 40GW of guaranteed available generation and storage at the other end of interconnectors. Not that assuming just 3 cold days in January represents a proper test of system resilience. They have some interesting cost assumptions too: batteries – half price! No cost for inverters and installation. Offshore wind dirt cheap. Their work was likewise motivated by providing CCC propaganda. Helped fund their grants, no doubt.
The contractual arrangements for power have to reflect the physical realities in the end. You can’t just buy power in the Netherlands and sell it in the UK and assume that it works. You need capacity on the interconnector. Even then, the process of auctioning capacity may mean that your supposed supply position has in fact been netted off – it is even possible for the physical flow to be in the opposite direction under the netting process. Effectively, you will have been deemed to supply into the Netherlands, and someone else is supplying your UK offtake. Your contract becomes purely financial, with the system operator clearing house (Elexon in the UK) being the counterparty for the purposes of physical supply matching and imbalance charging or credit. Of course, it is likely that it would be more profitable for you to sell your power in the Netherlands and buy alternative supply in the UK more formally if the flow is in the reverse direction. That may depend on what you can recover from relinquishing your interconnector capacity.
Much of the BritNed capacity is actually traded intraday Trade is indeed driven by price differentials, but those in turn are often driven by constraints. We have seen imports on BritNed and NEMO essentially as a way of being able to export to France, because we lack internal transmission capacity. to supply the South and France from our own generation. Constraints on the capacity of other routes into France have been driving the trade.
@It doesn’t add up
You said, “EMBER’s … worst case average annual capacity factor for … offshore [wind] is 48.9%. Now try comparing that with data from Energy Trends on quarterly capacity factors actually achieved back to 2010 and you will see that as an annual average those assumptions are higher than the best historical performance.”
Only a few of the existing OSW farms have turbines in the 8-10 MW range, the rest being smaller.
For future CFs (capacity factors), you cannot rely on historical offshore wind capacity factors based on far older, far smaller offshore wind turbines than the turbines that will be installed from now on.
UK has only 14 GW of (the older) offshore wind turbines installed right now, and the the 2030 target is 50 GW. That means 36 GW of newer and larger turbines will be installed, and the CF from them is expected to be a lot higher. So the characteristics and placement of the newer wind farms will swamp that of the existing in the final CF average.
The Dogger Bank A OSW farm going live this year and subsequent OSW farms will be further out, tapping stronger and more consistent winds and using 13-15 MW 260m turbines.
A map of existing and future OSW farms can be found at https://www.windenergynetwork.co.uk/wp-content/uploads/2021/03/A1-Map_Issue-57-WEB.pdf.
There is an independent view of CF for wind farms available from the Global Wind Atlas at https://globalwindatlas.info/en/. This is paid for by the World Bank, incidentally, so is likely to be a good objective source of information.
Set the LHS parameter box to display capacity factors for class 1 turbines, and later set hub height to 150m (260m for Haliade X on Dogger Bank A – 220m rotor diameter / 2). Now float over the position of Dogger Bank A, and the tool displays a 58-60% CF in that region.
The Scottish offshore wind farm locations N1-N3 are all at 63% CF according to the tool. You can do better in the far north west of Scotland.
These predicted CF figures from the tool blow your questioning of EMBER’s 50% annual minimum out of the water.
Further, we will know by the end of the year roughly what the Dogger Bank A CF actually will be, as it will be live at £51-53/MWh (in 2022 pounds). All UK wind CF is lowest in summer, and higher in winter, so we need figures for both seasons to decently estimate the annual CF.
You said EMBER’s mention of consultations with the UK CCC is “propaganda in support of the CCC narrative.”
How do you mean “propaganda”? The CCC is legally charged with objective evaluation and recommendation of an affordable UK response to the issue of global warming. UK is responsible for 5% of cumulative historical CO2 emissions. The UK CCC doesn’t do all the donkeywork itself, but defines aims and farms out the detailed work to various organisations, including academia, consultancies and others. The CCC is backed by all UK political parties, and the adoption of a 2050 net zero target at the end of May’s PMship was passed by acclamation – meaning ZERO MPs objected verbally to it to force a vote. So the CCC is hardly “political”.
You said, “Imperial may have made some effort to model demand, but ..”
The Imperial proposal seems to be 140 GW / 200 GWh of (thus) short-duration grid batteries assumed to be £187.5/kWh. So the cost is £37.5bn. 108 GW of offshore wind @ £2.7m/MW will cost around £290bn, and provide power at £48/MWh or less in 2022 prices. So the grid batteries would add roughly 13% to the cost of power based on the ratio of capital costs. Not that high!
Compare the cost of grid battery storage with current crude oil imports of £1.5-2.5bn per month or £18-30bn per year over the last few years. What exactly is the problem here with providing 200 GWh of grid batteries?
And if you don’t want to pay capital up front for it then 37m UK BEVs at 75 kWh is around 2.8 TWh of batteries. If 25% of owners use V2G to enable the grid to manage their BEV batteries between 50% and 100% (with overrides in advance of long journeys), then that provides the equivalent of 350 GWh. Or you can wait for the EVs to be scrapped and pick up 350 GWh in 2 years (1/8th of a 16 year average vehicle lifetime) of ex-EV batteries, probably for a cost of £20-30/kWh.
You said “batteries – half price [assumption]”.
Sodium ion batteries will be in volume production by CATL (world’s largest battery maker) + Faradion this year. They use only commonly available and cheap materials (sodium from sea salt?). No lithium, cobalt, nickel etc etc. How much do you think such battery cells will come in at in 3 or 4 years time,, given Tesla is probably already being supplied with LFP cells by CATL at under $100/kWh? Maybe $60/kWh? The Imperial report uses £187.5/kWh, which allows a huge sum for inverters, environment, grid connections and fire safety, labour etc. Seems pretty reasonable to me.
DSR
An EV with a 300 mile range and a 30 mile daily round trip commute has at least a week of flexibility in when it can be smart charged (at rock bottom prices, if not for free as a reward for participating in V2G). No point in providing short duration grid battery storage for such smart charging. Similarly, heat pump systems with a day of thermal storage do not require grid batteries (not everyone has room in their home, but maybe half will?).
Then there are industrial processes, like steelmaking using electric arc furnaces. Many can be suspended indefinitely after completion of a batch (of a few hours), meaning they don’t need storage or backup in any shape or form. They can schedule around the availability of cheap wind power.
Offshore wind dirt cheap?
There is no explicit statement of the time value of UK pounds in the Imperial study. But it does say the fossil fuel prices were obtained from a 2016 BEIS document https://assets.publishing.service.gov.uk/government/uploads/system/uploads/attachment_data/file/566567/BEIS_Electricity_Generation_Cost_Report.pdf. And this explicitly says its prices are in 2014 pounds.
The latest offshore wind CfD AR4 strike price is £37.50p/MWh in contract 2012 pounds (£48/MWh in Jan 2022 pounds), with annual CPI uplifts. It will surely come down more from that, though maybe not by the 50%, 30%, 50% and 8% per auction we have seen from the last 4 auctions.
It is only an 11% price reduction from £37.50/MWh in 2012 pounds to £35/MWh in 2014 pounds (CPI change factor around 1.05 June 2012 to June 2014). Obviously the 2021 study authors didn’t know the AR4 strike prices when they made their assumption, as that emerged only in 2022.
So the pricing in the study is effectively relative, but consistent between offshore wind and 2014 fossil fuel generation prices, as far as I can see.
Interconnectors
By 2050, much of the interconnector capacity will be required to export UK offshore wind power. By 2030 70% of UK power will be from offshore wind (assuming only a 55% CF for everything new from here on), depending on the actual demand increase. There will be many times of surplus – Norway can generally take wind power to save hydro water.
If Norway pairs up low-high pairs of hydro lakes, builds more tunnels, and more generation, it could convert to a huge PSH facility for northern Europe with no additional dams needed – only tunnels and pump/generator houses. It could thus be exporting a lot more power on demand when wind power is scarce (having previously received surplus wind power in return). This would help a lot in justifying the “firmness” of an interconnector feed to the UK.
In any case, the interconnector feed is not mandatory – there are other ways of providing this power at crucial times. The question becomes how much you would be prepared to pay for complete independence from the massive European synchronised grid. It can’t be answered now, but surely will become apparent at some point.
It is getting to be an abuse of the comment space here to go through each of your latest items in detail, but they are all not proper answers. For example, Tesla Megapack grid batteries are now around $500/kWh in volume. 140MW of batteries implies 140 GW of transmission to match, all competing for some peak price window because of short duration, all at low utilisation for enormous cost. I checked the MERRA 2 derived data from Staffel & Pfenniger which shows that the “worst year” chosen by EMBER is in fact only marginally below the average of the past 40 years, and a long way above the worst which is in fact 2010. Why didn’t they use it? etc.
I’m happy for the comment space to be used for debates between readers. This blog has attracted a surprsisng amount of attention – it’s my most read/reacted to blog on LinkedIn ever by a huge margin. The question of data sources, bias and reliability is an important one…
Ben Pile produced an interesting analysis of the origins and funding of EMBER here.
https://twitter.com/clim8resistance/status/1671499832844771330
Impeccable deep green pedigree. Not an independent thought in their ashes.
@It doesn’t add up (comment 21 February 2023 at 4:09 PM)
Since Kathryn doesn’t object, if you have responses to points from me above, you should at least take one or two and give details.
You said, “140[G]W of batteries implies 140 GW of transmission to match, all competing for some peak price window because of short duration, all at low utilisation for enormous cost. ”
This is a strange thing to say. 140 GW of grid batteries implies peak demand of 140 GW maybe, or possibly even 140 GW of generation. But it doesn’t mean 140 GW of transmission.
One of the known benefits of grid batteries is to be able to smooth transmission links. Lets talk about MW rather than GW to make an example more realistic. For simplicity ignore battery losses (Tesla Megapacks are around 7.5% AC to AC losses for 4 hour storage).
For, say, 150 MW of peak demand the peak 24 hour average demand might be 125 MW. So you can have a 125 MW link with a battery of 25 MW at the load end, and run a 125 MW transmission line at 100% during the peak day, yet still service a peak hour load of 150 MW.
As for the cost implications, on page iv of NREL’s battery report at https://www.nrel.gov/docs/fy21osti/79236.pdf, the 2030 cost of 4 hours of grid batteries is estimated at $600-1,000/kW (i.e. $150-250/kWh x 4).
If you don’t have the 25 MW of batteries, then you need 25 MW more despatchable generation – say OCGT which might come in at $750/kW. Then you also need 25 MW more of transmission line, and I have no idea how much that might cost because it depends on distance.
At these levels of cost you certainly have to look carefully at the options and their pros and cons for supplying an extra 25 MW of power on an exiting 125 MW line, to support 150 MW of peak load, because you can easily construct scenarios where either upgrading the line or adding a battery at the load end would be cheaper.
As for the funding of Ember, the twitter criticisms of Ember and David Attenborough read more like conspiracy theories than an objective analysis of Ember’s proposals.
I prefer to look at real world data over manufacturer’s unsubstantiated claims. Here’s the performance of Tesla megapacks at the Hornsdale Power Reserve a.k. the Big South Australian Battery as measured by NEM:
https://i0.wp.com/wattsupwiththat.com/wp-content/uploads/2023/05/Hornsdale-Performance-1683419034.5253.png
Mark I eyeballs suggest that cumulatively it is running at about 80% round trip, and despite the investment in major expansion in 2020 it appears that recent performance has been consistently somewhat below that. Moreover, turnover of charge is down which is in part economics and perhaps the economics are being constrained by less well performing packs that maybe got mistreated in pursuit of short term profit. Claiming a theoretical 7.5% round trip loss against the reality of 20-25% is of course exactly the kind of tactic that EMBER employ in constructing their fairy tales.
Battery economics depend on being able to stack revenues. The HPR has done at times extremely well out of a near monopoly position in the provision of FCAS services to add to its energy arbitrage earnings. You can see that here, where they earned A$13.4m in just one week of FCAS when the system was stressed:
http://nemlog.com.au//nlog/weekly-energy-and-fcas-revenues-for-participant//?D1=20220101&D2=20221231
However, in the UK we have seen grid stabilisation revenues collapse from a more or less guaranteed £17/MW/h of availability contracted to around 10% of that as the market has saturated and Dynamic Containment revenue has been cannibalised. The problem with longer duration storage is that you do not get to turn over your capacity as frequently, which means fewer revenue earning opportunities, which in turn means you need a higher margin to generate sufficient income from the available opportunities. I’ve done optimisation runs on different durations of battery covering the very volatile market of last year. 2 hours is about the longest duration that makes sense: at 4 hour duration the economics start to deteriorate – and that in ideal market conditions of extreme price volatility. In more normal markets a two hour battery will get a lower return than a one hour battery. The really big batteries are being built to service renewables generators – Cleve Hill solar, Blackhillock/Keith for Moray/Beatrice, etc. – but they are really only peak lopping volumes in the context of connected and to be connected generation.
The economics of genuinely longer term storage e.g. at the interseasonal level become completely untenable for batteries. You refer the the NREL projections made in early 2021 based on a literature survey. Back then lithium prices were around 6$/kg. Today they are over 40$/kg having spiked at over 80$/kg: something completely unforeseen by NREL. Their cost projections are meaningless. Tesla was reported to be charging over $500/kWh for megapacks recently – real world numbers, plus site and installation costs. Battery costs have gone up, not down. The same is true of wind turbines, as Kathryn’s recent article illustrates with great clarity.
Batteries will have some role in reducing grid congestion in the future as a largely incidental feature to other functions. The grid before renewables managed by having peaker plant located close to demand, thus eliminating the need for transmission to meet peak demands. The Triad system essentially encouraged further investment in private onsite generation to reduce the demand on the grid for transmission capacity. Peaker plant is cheap as a capital cost. Batteries are expensive, and much harder to justify.
I did not claim that Ben Pile had done anything more than expose EMBER’s links by way of origin and funding. Why pretend otherwise? Baroness Worthington is literally the Green aristocracy. But there is no conspiracy theory about those facts, unlike the lazy accusations of being funded by fossil fuel interests that have no foundation in fact that are so readily tossed out at Ben or say GWPF. The people that fund them want a sane world rather than one driven by net zero policy that will impoverish us if it continues to be attempted. Many of them support the development of sensible nuclear policy, which is a longer term essential.
If you would like an objective analysis of EMBER’s proposals I would recommend you listen to Prof Dieter Helm who explains that it is infeasible.
https://dieterhelm.co.uk/energy-climate/podcast-42-net-zero-crunch-time/
Incidentally I lost all respect for David Attenborough when I showed that his famous “walrus suicide” scenes filmed in the Russian Arctic were in fact the result of walruses being hunted by polar bears. It was an outright lie and deception. Yes, it was me personally who trawled through Siberian blogs in Russian to unearth the photographic and written evidence, and passed it on to polar bear expert Susan Crockford after she became suspicious about the claims.
@It doesn’t add up… 22 June 2023 at 9:30 PM
You say ” Tesla megapacks at the Hornsdale Power Reserve … running at about 80% round trip [efficiency]”.
And that provides some support for the Tesla Megapack V2 claimed 93.5% efficiency for 4 hour versions.
Battery cell power losses are I^2 x R to a reasonable first approximation, as long as you don’t charge close to 100% too often. Hornsdale has (and used to have) a maximum charge and discharge rate of 0.77C (= 150 MW/194 MWh = 100 MW/129 MWh), while 4 hour Megapacks are constrained to 0.25C – just under one third of the rate. You have to keep the current “I” going for longer if you discharge slower, so the efficiency losses are proportional to I (not I^2) and thus to C.
Take 19% cumulative Hornsdale losses and multiply by 0.25/0.77 = 6.2%. 93.5% efficiency results in 6.5% losses, so this is a pretty close result. But it isn’t conclusive, as there are more components than just battery cells in the Hornsdale battery (and the Tesla V2 Megapack). Likely most of these have I^2 x R losses too, though that is not guaranteed.
The Hornsdale charge and discharge chart doesn’t give charge and discharge rates, but roughly equates to a full cycle per day (e.g 4000 MWh/month vs 129 MWh capacity ~= 30 days).
Once you apply I^ x R, Hornsdale certainly isn’t a counter example to disprove the Tesla 4 hour Megapack V2 spec.
“The really big batteries are being built to service renewables generators – Cleve Hill solar, Blackhillock/Keith for Moray/Beatrice, etc. – but they are really only peak lopping volumes in the context of connected and to be connected generation.”
For most of the world (which is sunnier than the UK on average) there is a sweet spot for solar + storage of 4 hours storage because that carries over enough energy from the daytime to handle the post-dusk evening peak too. 2 hours is not sufficient. So the justification depends on whether OGCT peaking plants are more or less expensive than 4 hour battery storage.
For the 2030 UK grid when you are starting to convert your OCGT (/CCGT) peaking plants to green hydrogen to get to net zero, you are balancing the cost of extra hours of storage vs the extra losses due to the round trip efficiency of power to gas to power of around 45%, plus the capital cost of the electrolysers needed to make the additional hydrogen. I doubt anyone is going to allow the capacity of these two grid components to be determined by price signals related to operational revenue – but we will see what the UK government REMA project comes up with eventually.
“The NREL projections made in early 2021 [relate to] lithium prices were around 6$/kg. Today they are over 40$/kg. … Battery costs have gone up, not down.”
CATL and Faradion will be in volume production of sodium ion cells this year, which use only cheap and commonly available materials, while being a little heavier than LFP in terms of specific energy. You can argue the toss as to how big their use in EVs will be, though some Chinese EV makers will be using them in EVs this year. But there is no doubt they are very suitable for stationary storage. CATL sodium ion cells are likely to reduce down to $40/kWh – half the current estimated CATL cost to Tesla of LFP cells, mostly due to the lower raw material costs.
Whatever battery cell prices are doing right now, there is only one direction in the medium term – straight down.
“The same is true of wind turbines, as Kathryn’s recent article illustrates with great clarity.”
You seem to be hung up on short-term prices, while the strategy for the UK grid should surely be depending on medium to long term prices. The world is at war right now, and pricing for a lot of things is likely to be lower a few years after that stops.
“Peaker plant is cheap as a capital cost. Batteries are expensive, and much harder to justify.”
Again, you should be looking medium term not short term.
https://www.lazard.com/media/sptlfats/lazards-levelized-cost-of-energy-version-150-vf.pdf gives peaker plant total capital costs as $700-925. If sodium ion grid battery storage has eventual cells costs of $40/kWh, then 4 hours is a total cell cost of $160/kW. It seems unlikely that the inverters, environment and ancillary equipment will push this figure3 above $700/kW.
In any case, EV V2G is likely to come in at a lower capital cost than a peaker plant.
Batteries don’t generate, of course, so you will still need some peaker/despatchable gas plants, converted to hydrogen. Roughly, with batteries, you need enough backup plants to provide the average supply needed in the peak 24 hours of demand (excluding losses). At the moment the requirement is to provide peak hour demand by means of despatchable plants, which is higher, of course.
“… accusations of being funded by fossil fuel interests that have no foundation in fact that are so readily tossed out at … GWPF.”
You can’t prove the GWPF is NOT funded by fossil fuel interests, as it hides behind charity rules to ensure the names of donors remain secret. And fossil fuel interests are the natural donors for an anti-renewables organisation such as this.
“The people that fund them want a sane world rather than one driven by net zero policy that will impoverish us if it continues to be attempted.”
Given the evidence of ocean heat content at https://www.ncei.noaa.gov/news/ocean-heat-content-rises, the only sane policy is one that gets to net zero as soon as possible. 90% of global warming net incoming heat ends up in the oceans, so there is much less noise associated with OHC measurements than with surface temperatures.
In any case a net zero grid is unlikely to provide electricity anywhere near as expensive as the electricity we have had to buy over the past 18 months.
“I would recommend you listen to Prof Dieter Helm”
Dieter Helm lost my accolade for objectivity when he suggested that all generation sources should be priced for firm delivery of a constant output. If you want to go in that direction the most obvious way of expressing a requirement would be to quote for a proportion of the actual profile of demand – maybe adding in projections for new types of demand. Helm’s suggestion was intellectually lazy, which might have been due to a pro-nuclear bias. It is a mistake to take everything he says as gospel.
In your response in relation to Hornsdale you managed to ignore the evidence I provided, and to demonstrate that you have no knowledge of the battery operations. Reality trumps your models – and that is a refrain which I shall repeat. When the battery was initially installed the South Australian government contracted for the right to control 70MW of output for emergency situations. The result was that testing aside the battery operated at a maximum of +/-30MW of charging, making it in effect a 4 hour battery, save for a couple of occasions when the government exercised their option in very hot weather when demand was high. Much of the time (dis)charge rates were lower, but changing frequently to provide FCAS frequency stabilisation service. So your theory fails to account for the actual behaviour in the real world operation of the battery. I monitored its operations from the outset, often at 5 minute resolution as in this chart, which shows that HPR operation was not linked to its adjoining wind farm, debunking the idea that it was to be used to store wind energy for discharge during wind lulls.
https://uploads.disquscdn.com/images/d65ddaa1c30c0d75b3bd066d5c92e3ce51754b0739d21fa49e65d199ef241fc1.png
You will note that following the battery expansion in 2020 (which may have also entailed replacement of some packs that had deteriorated unacceptably, but that will never be public knowledge) HPR had a short period of rather better performance, peaking at around 88% efficiency, but that at the end of summer in 2021 it started to erode. The rapid erosion of performance should be a concern: the idea that these batteries are going to be good for even 10 years of service is looking dubious.
Sodium ion batteries in the real world:
Sodium-ion batteries have a lower voltage (2.5V) than lithium-ion batteries (3.7V), which means they may not be suitable for high-power applications that require a lot of energy to be delivered quickly.
They have a slower charge/discharge rate than lithium-ion batteries, which may not be suitable for applications that require a lot of power to be delivered quickly.
Sodium-ion batteries still have limited charge cycles before the battery begins to degrade
Doesn’t sound as though they are quite the panacea – I can find no hard data on round trip efficiency either. Still a lot of work to make them properly competitive, if that can be done. It’s unlikely that solving the problems will mean lower cost. Conclusion: NREL’s work remains hopelessly optimistic.
I see you seek to rely on Lazard’s discredited LCOE calculations. As King Charles said to Liz Truss “Oh dear, oh dear!” It is not appropriate to use LCOE when designing a grid system. It takes no account of the costs of intermittency of demand and generation and the way in which they rise if you increase reliance on particular sources. That’s before we look at the highly disputable assumptions for costs and lifetimes etc. that they make. Real world grid design entails coping with variations in demand and variations in supply (cost and availability in the case of fuels, weather and costs of maintenance/repair in the case of renewables), ensuring reliability (partly through flexibility) under the various operating scenarios while seeking to minimise expected costs in the long run.
I admire your optimism that EV owners are going to park up to keep the lights on instead of driving home in peak rush hour, and to tolerate degrading of their batteries in ways that will be far more costly than closely monitored grid batteries, while finding that their vehicle is unable to recharge to make that longer trip just when they need it. I have read the Cenex studies in detail and I doubt that the enthusiasm of early adopters paid handsome bribes to take part will be widely replicated in practice. YMMV will be a warning. We know that DFS needed to accept bids at £6,000/MWh to achieve a paltry maximum of 294MW of demand reduction on 23rd January, and that’s without degrading customer appliances. That’s the real world.
Can you prove the moon isn’t made of cheese? GWPF protects the identity of its donors in part because extreme greens have shown just how willing they are to attack those who oppose them – exemplified by JSO’s paint throwing escapades in Tufton St., and by repeated efforts to cancel their prominent supporters who are listed, and suffer the consequences. They do however state quite clearly
In order to make clear its complete independence, the GWPF does not accept donations either from energy companies or from anyone with a significant interest in an energy company.
Why do you think they are lying? Is it because that is standard practice among your friends?
I do not claim to be an expert on oceanography in relation to climate change (I know much more to degree level and beyond about the role of LWIR in heating and cooling the atmosphere which is probably my specialist topic on climate, along with the limitations of mathematical modelling of climate), but I am reading Alan Longhurst’s book Doubt and Certainty in Climate Science – he was an oceanographer at Scripps and played a key role in understanding the role of plankton in the oceanic CO2 balance, and certainly is well qualified to evaluate those aspects of science. Recommended. The page you link is out of date, but its use of zillions of Zeta Joules as a scare tactic is renowned among anyone who knows how to calculate the heat capacity of the oceans. Please note I do not make a habit of debating climate science in public fora as it is usually unenlightening, although I do try to improve my education on it periodically by reading mostly original papers. Extreme climate scenarios are no justification for the immediate impoverishment and enslavement of the people of selected Western countries in pursuit of net zero via a programme dominated by wind and solar. I have no truck with genocidal Malthusians like Roger Hallam.
Unfortunately as we are only just embarking on a more earnest attempt to pursue a net zero grid I cannot agree with your claim that it will provide cheaper energy than we have paid for in recent times. I have spent a lot of time researching the plans and issues following a career in the energy industry that started at AERE Harwell which was run by Sir Walter Marshall who also ran the CEGB. I had an education in what it takes to run a successful grid from the outset. I have had many discussions with a wide range of experts in different aspects of energy provision: much of my expertise is really theirs. It is quite clear that the costs of pursuing the present plans will be eyewatering and unpleasant in their consequences for our standard of living and ultimately health and longevity, and make last year seem like a pleasant dream. We will be poor, hungry and cold.
You evidently failed to understand the key point that Helm was making in his review. The basic idea is that the present policies take no account of the costs of intermittency, which is simply paid for wherever it occurs and added to bills. An optimal grid design takes account of all costs, and aims to ensure that the tradeoffs balance to produce a low cost outcome. You can do that quite effectively by requiring parties to negotiate among themselves to come up with a joint effort that lowers costs, and allowing competition to drive towards the desired outcome. Perhaps you should give him your time and listen to what he has to say. He evidently has more expertise.
@Mark – 24/06/23 comment 1
Thank you for the more detailed information on actual power for charge and discharge, which I was aware of.
You say that, at least in one set of circumstances, the HPR battery storage efficiency was as high as 88%. That is more than half way between your claim of 80% and the Tesla Megapack 2 specification of 93.5%.
There may well have been some teething problems with HPR, but clearly not sufficiently important to stop HPR being upgraded significantly at significant cost.
Your claims that performance “eroded” at the end of summer 2021 is unlikely to be true. To be credible, you would have to show that the operational regime of the battery did not change, including the distribution of charging and discharging C values. Also that the battery was operated at similar maximum charge levels. If you want to go ahead with such an analysis feel free.
But before you waste your time …
The Tesla Megapack 2 likely uses LFP battery cells, and not NCA or NMC cells, as were probably used in the HPR and Megapack 1. We surmise this because the Megapack 2 is heavier and longer than Megapack 1 for a given spec. But LFP is more suited to stationary storage, as length and weight are not key considerations.
LFP cells have a higher round trip efficiency than NCA or NCM, and can routinely be charged to 100% without suffering unwanted degradation. The advice is to charge NCM only to 80% routinely, unless the full capacity is required.
So if the HPR with NCA or NMC cells can achieve 88% round trip efficiency in certain situations, it is highly plausible that Megapack 2 can beat that by a significant margin. Your analysis of HPR does not thus disprove the Megapack 2 spec.
Yes it is better to have measured figures for battery packs, but most manufacturers are responsible and don’t make stupid claims that will be refuted the first times someone does some measurements.
There are other sources of LFP cells efficiency and likely cycle life, such as the Powin stationary storage specs at https://powin.com/wp-content/uploads/2022/02/Powin_Stacks_Product_Line_2021.pdf. The 360E spec gives a lifetime of 20 years, 7,300 cycles (down to 66% of original capacity for the CATL CB310 LFP cell model) and the DC round trip efficiency is 93% for 1.5+ hours and 95% for 3+ hours. These are DC devices, of course, so you would expect a slightly lower overall AC efficiency once charger, discharger and HVAC losses are included. Note that the Megapack 2 is a 4 hour device, so you might expect a small improvement in the DC efficiency compared to the Powin device.
CATL sodium ion battery cells to be in volume production this year are expected to have a cycle life in the 3,000 to 6,000 range, and a 3.2C charge rate to 80% charge. These specs are pretty good as far as grid battery storage is concerned, and also suitable for at least low end EVs.
However, it is early days yet, and we will doubtless know more after teardowns when these cells appear in some Chinese made EVs later t6his year.
Lazard’s LCOE calculations clearly are subject to the way plant is used. However the capital costs, which is what I quoted, are not.
Why do I think GWPF is lying?
One reason is because its leader at the time, Nigel Lawson, appeared on a BBC discussion alongside a scientist and proceeded to tell a string of untruths.
Also, every document I have read from the GWPF contains significant misinformation, such as that the public accounts showed that SSE was making a huge loss on one of its offshore wind farms, whereas when I examined them, the public accounts showed no such thing.
Another reason is a GWPF publication purporting to show that offshore wind farms (and others) in UK and Denmark showed rapid degradation in capacity factor such that they were virtually worthless in energy production by the end of their 25 year lifetimes. Yet one look at the mini CF charts by offshore wind farm by year at https://energynumbers.info/uk-offshore-wind-capacity-factors tells you this is not true. There’s a link to the Danish farms too, and decommissioned Vindeby showed no significant CF degradation until they started removing the turbines.
The GWPF works to the type of misinformation model adopted by most of the oil lobby funded, climate denier think tanks in the US funded by hundreds of millions of Koch brothers style money.
Enough said. The debate on climate science is over, and it is time for action.
I don’t subscribe to the view that those who worked for years on old fossil fuel grids inevitably have a good appreciation of the design and operational issues of a renewable grid based on variable wind and solar.
Here are my articles on an all wind and solar Texas grid based on simulations using actuals:-
– https://judithcurry.com/2017/05/14/electricity-in-texas-is-100-renewables-feasible-part-i/
– https://judithcurry.com/2017/08/06/electricity-in-texas-part-ii-the-cost-of-a-100-renewable-grid/
These articles are more intended as educational than comprehensive – to help people understand the issues and solutions rather than provide a definitive solution.
And here is a white paper on a 2050 net zero UK grid
– https://spiral.imperial.ac.uk/bitstream/10044/1/88966/7/EFL_Net%20Zero%20GB%20Electricity_White%20Paper.pdf
One issue for net zero grids is what the market arrangements should be. I don’t have the answer, though the current UK arrangements are certainly not going to work for very long. The UK government REMA process is likely to lead to a well thought out set of changes which will be a decent first stab at solving the problem. If you are concerned about this then plug yourself into the process – I submitted responses, but really only had two things to say I considered others might not have thought of.
EV owners won’t be asked to stay at work to support the grid. They will use the EV as per normal, and likely allow it to cycle batteries between 50% and 100% when plugged in (I favour wireless inductive charging for this as it is far more convenient). The mobile app will have an immediate charging override available, and the ability to specify out of the ordinary travel plans, such as access to the electronic calendar of the driver. The quid pro quo, according to Nissan, is probably free electricity for EV travel when charging at home.
7,300 cycle LFP EV batteries won’t be significantly degraded by V2G. For a 300 mile range EV this is 2 million miles down to 66%, which doubtless equates to at least 1 million miles to keep above 80% of original battery capacity. The average UK car lasts around 16 years and is driven 7,500 miles per year, which is a total lifetime distance of 120,000 miles – far short of what the battery can deliver. The battery will either be handed down to the next generation, or extracted on scrapping the EV and used for another 10-20 year as grid storage.
Here is a link to an up to date OHC chart – https://www.climate.gov/news-features/understanding-climate/climate-change-ocean-heat-content
I have been using the previous one to respond to climate deniers for the last 3 years in an open tab. But the most recent years do not show any different pattern to that in the previous chart.
Norwegian supply overall is constrained by water. The hydro generators have more than sufficient peak generation to cover the Norwegian peaks, and the Norwegian network doesn’t have peak hour issue. Normally, Norway has spare hydro water available during the annual cycle.
Norway without interconnector traffic would be 96% hydro generation. Thus imports of power from the UK at night save precisely the same quantity of hydro water (strictly water x height above lower reservoir) as imports from UK in peak hours. The quantity of water saved does not depend on the other load on the system in any way, though the price of the power does.
Because Norway participates in northern European electricity trading markets, its market price for electricity (or at least for exported power – I don’t know about internal pricing) does match the European market prices – after all, Norway is entitled to maximise its revenue from power trading. So power exported during European peak hours is always going to be more expensive. But that also doesn’t change the physics that Norwegian exports and imports have the same effect (saving or using) on hydro storage levels whenever they happen.
According to https://www.researchgate.net/figure/European-nodes-and-international-interconnectors-considered-for-the-European-power_fig1_356890911, France does not have a direct interconnector to Norway, so can only exchange power with Norway via the UK link or via 3 links involving two intermediate countries (e.g Germany and Belgium). Norway only needs to keep its new regulations simple, and monitor and regulate yearly physical interconnector net flows, leaving the complexities of the traded source or destination of power to someone else to manage.
Norway is correct in any case to protect its resources. In the big picture northern European power scheme, Norwegian hydro capacity is too valuable to use mainly as baseload for Norway itself. Norway should put in place export rules which say it must always be able to satisfy internal Norwegian demand for the rest of the season, but also develop interconnectors (and maybe additional generators to increase peak generation capacity) to play the biggest (and most profitable) role it can in backing up variable wind and solar power in northern Europe.
If someone else pays, Norway could also pair up lakes at high and low levels and upgrade some parts of the system to pumped hydro storage. This would not involve any more (usually highly contentious) dams or reservoirs, but requires tunnels, transmission lines and generator upgrades to pump/generators. A few years ago my money was on Germany ending up biting the bullet and footing the bill for this, but from where things stand today, it might even be the UK which has the need for such a solution first. Norway keeps trying to sell this development.
It is worth taking a look at PF Bach’s analysis of 2022 international power flows in Europe.
http://pfbach.dk/firma_pfb/references/pfb_france_rushed_down_from_net_export_to_net_import2023_01_28.pdf
Also Roger Andrews’ analysis of how much wind the Norwegian system can support.
http://web.archive.org/web/20160801042131/http://euanmearns.com/how-much-wind-and-solar-can-norways-reservoirs-balance/
PF Bach agrees that Norway’s balancing capacity is about exhausted.
http://pfbach.dk/firma_pfb/references/pfb_norway_at_the_limit_of_its_transmission_capacity_2022_06_19.pdf
It is easy to forget that inter annual variations means Norwegian hydro generation can be a bit over 140TWh or as little as 100TWh depending on precipitation. As the interconnection hub, the NO2 ELSPOT area has borne the brunt of the increased interconnection on its market prices. The effects on Norway were dramatic and immediate when the German interconnector opened. This chart shows what happened
https://datawrapper.dwcdn.net/fLVEo/1/
Just thought this thread should have an update on the performance of the HPR battery, which seems to be in trouble again. Pace Peter Davies, but I don’t think AEMO data lie.
https://i0.wp.com/wattsupwiththat.com/wp-content/uploads/2024/02/Hornsdale-Performance-1707958165.7449.png
Two months in succession at below 75% round trip efficiency, and reduced throughput.
Perhaps when Davies has some spare time he might read the Royal Society report on storage, and run his calculations for how Texas would have survived the Feb21 freeze on renewables alone, including no use of gas for heating.
IDAU said “how Texas would have survived the Feb21 freeze on renewables alone”
As it turns out, the February 2021 (Day After) Valentines Day Texas (C̵h̵a̵i̵n̵ ̵S̵a̵w̵) Grid Massacre was a pretty similar repeat precisely a decade after a very similar set of Texas blackouts in February 2011, caused by a very similar winter storm. The gas supply infrastructure, lots of CCGT plants, many wind turbines and other forms of generation froze and there had to be blackouts to stop the grid from collapsing under record winter loads, despite nominally adequate reserve generation.
The 1-5 February 2011 period was included in my modelling of the ERCOT Texas grid with links above. But…
At the time (2016), I wasn’t aware of the Feb 2011 storm, so made no allowance for it. So my modelling was based on the ERCOT supplied demand figures. On page 76 of the FERC report at https://www.ferc.gov/sites/default/files/2020-05/ReportontheSouthwestColdWeatherEventfromFebruary2011Report.pdf, it says the maximum load would have been 59 GW without any load shedding.
A quick play with my simulation model shows 13 GW was the limit of additional demand for those 5 days with no requirement for more resources – 14 GW requires more CCGT plant capacity. 20 GW suppressed demand would require an extra 6 GW of gas generation fueled by green methane or green hydrogen.
A quick tweak to the simulation to add 13 GW extra to all demand for those 5 days would increase the peak for those days to 71.5 GW at 19:00-20:00 on 2nd Feb, vs an assumed summer peak of 71 GW.
61.5% of Texas heating already uses electricity – presumably resistance heating or heat pumps normally used for air conditioning operated in reverse. See https://www.eia.gov/state/print.php?sid=TX. So operation of the 61.5% of heating ought to be included in the 59 GW estimate from page 76 of the FERC report.
Thus adding the extra 38.5% for the non-electrical heating would be a significant but not huge increase to the expected grid load during the Feb 2021 storm. A slightly larger system configuration would cope with it.
The simulation is intended only to be indicative. The assumption of the 100% wind and solar simulations is that everything is working. Provision of sufficient redundancy is a responsibility of the grid operators.
Even after adding redundancy, to ensure no blackouts in the seemingly decadal winter storms means winterising everything, including the backup green hydrogen (or methane) storage facilities, CCGT generation and wind turbines. The solar panels were assumed to be 2 axis tracking which could probably just be tilted to shed snow, provided the motor mechanisms were winterised, or strong enough to overcome any icing.
However, this wind and solar solution is exactly as exposed to the Texas regulations as the Texas grid was in both the Feb 2011 and 2021 storms. The PUC (public utilities commission) regulating the grid isn’t inclined to mandate full winterisation of either gas plants or wind turbines. Nor of wind turbines, which, in much colder climates, routinely have heaters installed, and then reliably provide their normal wind-dependent power.
The TRC (Texas Railroad Commission) regulates both natural gas and hydrogen infrastructure, and is inevitably persuaded by political donations not to mandate infrastructure winterisation, as the gas supply companies make a fortune in these winter storms. So I expect there to be another 200 odd lives lost if a third, similar storm happens in February 2033. And there isn’t any likelihood of a TRC mandate to ensure a wind and solar grid backup hydrogen fuel infrastructure will be suitably weatherised to stop it from freezing solid. Some things never change and migrating the grid to wind and solar can’t solve what is essentially a political problem with winter storms.
Was anything actually implemented or legislated for by Norway on this. The latest news I can find on this is a proposal amend legislation and a consultation https://www.regjeringen.no/en/aktuelt/proposal-for-amendments-for-better-control-with-security-of-electricity-supply/id2986884/
can anyone point me to the change of legislation. Thank you!
I think the new amendment has not passed yet but the old amendment I think is contained in the emergency provisions (Section 9), but it’s not entirely clear:
https://lovdata-no.translate.goog/dokument/NL/lov/1990-06-29-50/KAPITTEL_7?_x_tr_sl=auto&_x_tr_tl=en&_x_tr_hl=en-GB#KAPITTEL_7
The comment had me coming back to the thread to see that Mr Davies had not answered the question I posed. I downloaded the hourly data on generation and demand for ERCOT from the EIA for February 2021. Adding wind and solar output together, the minimum contribution to supply was just 649MW at 8 p.m. CST on the 15th, when forecast demand was over 73GW (actual supply was well below that due to power cuts). So to supply the demand it would have taken more than 100 times as much capacity (~3TW of wind!) without storage or other backup.
A more relevant way of putting it is that backup dispatchable capacity required would be essentially 100% of peak demand, plus a reserve. The storage required to cover the Dunkelflaute period in the middle of the month is about 8TWh, or $4 trillion in batteries – and it would have to be full when that started, assuming sufficient capacity to supply the overall energy demand over the month including storage round trip losses (about 5.05 times what was installed). The storage requirement could be lessened by investing in extra generation and curtailing unstorable surpluses, but it doesn’t diminish all that rapidly. However, proper evaluation of storage requirement can only be done over a multi decade weather and demand history, as the Royal Society finally managed to do last year for the UK.