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.
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?
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.
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.
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:
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.
@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.
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.
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…
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.
Also Roger Andrews’ analysis of how much wind the Norwegian system can support.
PF Bach agrees that Norway’s balancing capacity is about exhausted.
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