In October, the 1,400 MW interconnector between Britain and Norway, known as the North Sea Link, began commercial operations. The €1.6 billion project is a joint venture between National Grid and Norwegian system operator Statnett. Unlike the other markets with which Britain is linked, Norway and GB have low weather correlation, and Norway’s extensive hydro network is seen as contributing to Britain’s security of supply. Indeed, interconnector imports are now seen as a core component of British capacity margins, as outlined in NG ESO’s winter outlook. However, at the very end of December, the Norwegian government decided to cancel the proposed 1,400 MW North Connect interconnector between the UK and Norway. The project had become mired in controversy after suggestions that the additional interconnection could raise Norwegian power prices by NOK 0.01-0.03 /kWh.
There are growing concerns as to whether it is reasonable or sustainable for countries such as the UK to rely so heavily on imported electricity. With fuel poverty in Norway rising – the Norwegian Government has this week announced new measures to support consumers struggling with rising electricity prices – people are beginning to ask questions about the distribution of benefits associated with interconnectors. As one of my LinkedIn connections put it: “Why should Norwegian families and the Norwegian economy at large pay for the energy transition in the UK?” He is not the only one asking these questions as there are growing protests over high Norwegian power prices.
Norway’s extensive hydro system lacks the flexibility needed to balance European electricity markets
Norway’s electricity system is primarily driven by its extensive hydro-electric resources – over 93% of Norway’s electricity generation is from hydro. At the beginning of 2021, there were 1,681 hydropower plants in Norway, with a combined installed capacity of 33 GW. Norwegian hydropower reservoirs hold around half of the total energy storage capacity in hydropower reservoirs in Europe. Because these resources are not intermittent, unlike wind and solar which represent the bulk of renewable electricity generation in many European countries, a growing number of interconnectors has been built to the country.
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“Norway will basically act as Europe’s battery. When we’ve got high renewables, we’ll send it to Norway and they’ll use that power, or they’ll use it to pump water and store the energy in the hydro power stations. And then when we need power in the UK, the power will flow back from Norway to the UK,”
– Duncan Burt, Chief Sustainability Officer, National Grid
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Unfortunately, this is to fundamentally mis-understand Norway’s generation resources – although the system is dominated by hydropower, there is very little pumped storage, and what there is was generally not designed for daily peaking-style use. In fact, only 1,400 MW of the 33 GW of Norwegian hydro is pumped storage, across 10 power plants.
The development of Norway hydropower was closely related with its industrial development. All ten of the pumped storage plants are located in the Central (Trøndelag or Midt-Norge/Midt-Noreg) and Western (Vestlandet) regions, the first of which – the 11 MW plant at Brattingfoss was opened in 1955. Most Norwegian pumped hydro schemes were designed for seasonal storage…water is pumped up to reservoirs in the upper part of the catchment areas during the snow-melting season. This takes advantage of the country’s topography, with steep slopes and high plateaus, and existing natural lakes are typically used, with dams constructed to contain the water. Tunnel systems connect the reservoirs to an underground generating station. It is common practice to have several brook intakes along the headrace and tailrace tunnels to collect water from smaller secondary water streams.
The round-trip efficiency for the 10 pumped hydro plants varies between 65% and 80%. Since they were designed primarily for seasonal storage and pumping of water during the spring and autumn high flow seasons, the pumps tend to have time-consuming and cumbersome start-up processes, ranging from 6.5 minutes to several hours, although recently upgraded plants can achieve pump start up times of under 3 minutes. Only half of the plants can start up in under 10 minutes. The Herva hydro plant has such a time-consuming procedure for the coupling of the pump runner, that the pump is only operated once a year for a few weeks during flood season. By comparison, the pumps and turbines at the UK’s largest pumped hydro power station, Dinowig can reach full operation in 16 seconds.
All of this means that Norway’s hydro system, while extensive, lacks the flexibility needed to balance Europe’s electricity markets once the limit of its hydro reserves have been reached. These limits might be tested this winter, as reservoir levels are far below the 20-year median, and at times have been close to 20-year lows.
At the same time that water levels began to fall, Norwegian electricity prices began to rise significantly. Norway has historically had very low power prices, but suddenly prices rose to multiples of previous levels, creating affordability problems both for households and industry. In early January, the Norwegian government said it would reimburse households for 80% of all electricity costs above NOK 700 /MWh (€70 /MWh) for the rest of winter in response to rapidly rising prices. This is an increase from a previous support scheme which provided a 55% rebate, which had cut bills by a quarter in the worst affected areas. Under the scheme, households receive support for up to 5,000 kWh of monthly consumption. However, critics have claimed that the NOK 8.9 billion scheme is insufficient given the scale of price increases.
In addition, Norwegian electricity demand is expected to rise in coming years, with Statnett predicting an increase from 133 TWh per year now to 220 TWh by 2050. Demand is expected to grow by over 14% to 2026, driven by datacentres and offshore oil and gas platforms. The largest increase is expected in the south where the most heavy industries are located, and which will see the impact of the electrification of the Johan Sverdrup oil field and its neighbouring fields.
Additional generation capacity will be needed to meet this increased demand. The potential for more hydropower is limited since most viable locations have already been developed or are subject to environmental conservation protections. Development of onshore wind has stalled due to strong public opposition, leaving offshore wind as the likely source of growth.
More internal transmission capacity is also needed to reduce regional price differences. Last year prices in the north averaged €30.95 /MWh, while those in the south averaged slightly above €63 /MWh.
Renewables will revolutionise the geopolitics of power generation
Germany has the largest national power consumption of any European country, with much of its domestic electricity coming from coal plants (particularly given the nuclear closure programme). The country is also trying to transition away from fossil fuels, and has installed a significant amount of wind generation, but not only does this introduce issues of intermittency, a lack of internal transmission infrastructure connecting renewable generation in the north of the country with industrial demand in the south has created problems with its neighbours. In fact, Germany and Austria were forced to separate their single bidding zone in 2017 after complaints from transmission operators in Poland and the Czech Republic whose grids were being overwhelmed by German power flows.
On windy days, Germany is a major power exporter, but on still days, the country relies on imports: in 2020 Germany was the largest exporter in Europe, but the largest net exporter was Norway. The previous year it was France, whose generation mix is overwhelmingly non-intermittent nuclear and hydro. In 2020, Norway had above average rainfall, with reservoirs reaching their highest levels in 5 years. As a result, Norwegian power prices fell significantly, making it cheap for connected markets to import.
Norway now has direct electricity interconnections with Finland (100 MW), Sweden (3,695 MW), Denmark (1,700 MW), Germany (1,400 MW), the Netherlands (700 MW), the UK (1,400 MW) and Russia (50 MW). When the NordLink cable to Germany was opened in March 2021, Norwegian system operator Statnett said it would enable Norway to absorb excess wind power from Germany, saving its hydro reserves for periods of lower supply.
“It is unlikely that Norway will absorb excess renewable generation from other countries. This would require Norway to import power. The majority of hydropower in Norway is not pumped storage, which means that the flexibility to consume power is very limited. It would not be economical to import power from the continent to run the limited amount of pumped storage [in Norway].”
– Jean-Paul Harreman, BV director, EnAppSys
Norway’s interconnectors are all owned and operated as joint ventures between Statnett and the TSOs of the connected markets, with profits shared on a 50/50 basis. The question is whether this is actually a good deal for Norway, since it tends to export when power prices are high in Norway and imports when power prices are low. Because Norway typically needs to use the power it imports immediately since there is limited storage capacity, these cheap imports are of little value since they tend to occur when the market is already well supplied.
“It will be interesting to see what happens with Belgium’s nuclear fleet and Germany’s coal closures. These events will eliminate 6 GW of nuclear in Belgium and 15 GW of generation capacity in Germany, both neighbours of France, over the next 5-10 years. Depending on what replaces this capacity and what happens in neighbouring countries, this may increase French exports considerably,”
– Jean-Paul Harreman, BV director, EnAppSys
The new interconnectors between Norway and Germany and the UK have been causing problems in Sweden, which led Swedish system operator, Svenska Kraftnat, to reduce its cross-border capacity to Norway in early December, with Norway retaliating by reducing exports to the country. The reason for Svenska Kraftnat’s action was that during periods of exports from Norway to the UK and Germany, Norway increased its imports from Sweden leading the Swedish TSO to reduce export capacity by as much as half this year to keep its operations secure.
Finland and Denmark both also rely on imports, with these capacity reductions also affecting their markets, raising electricity prices significantly. Both countries want the European Union to end the exemption to regulations that allow TSOs to make such import/export capacity reductions. The rules on this were tightened in 2020 to require TSOs to make at least 70% of their cross-border capacity available for trading within the day-ahead market coupling regime of which Norway is also a part, although since Brexit, the UK is not. (Interestingly, Nordic TSOs do not appear to be making the necessary data available to Acer for it to monitor compliance with this rule, and while most dc interconnectors that are required to comply with the rule do so – not all are – very few of the ac interconnectors see the 70% rule being met.)
“Imports from our neighbouring countries ensure adequacy at times of peak consumption. The recent increase in the electricity price throughout Europe does not directly affect the adequacy of electricity, but prices may rise dramatically for short periods,”
– Reima Paivinen, head of operations at Fingrid
This was the third consecutive year in which Sweden had applied for a derogation from the 70% rule, so the issue is not solely related to Norway’s new export capacity.
Time to re-think energy policy across Europe
Several of Europe’s electricity markets are at critical points in their history. France’s nuclear fleet is beginning to age, with hopes being pinned on the troubled Flamanville 3 project for the next generation of nuclear power. Britain is in a similar but more serious situation with its nuclear fleet, and together with the coal exit, winter capacity margins are looking uncomfortably tight as this decade progresses. Meanwhile Germany and Belgium are closing perfectly functional nuclear plant leaving Germany in particular reliant on coal. Prices are rising across the continent, as increasing levels of interconnection pull electricity towards the markets with the least excess domestic capacity.
And this is where the problems are starting to emerge – power market trading under market coupling is intended to flow seamlessly from markets with higher capacity margins (and lower prices) to those with lower capacity margins and higher prices. As more and more markets rely on wind, this creates increasing tensions when it isn’t windy, particularly when those weather systems sit across the Continent, depressing wind output in all of the connected markets.
But on the other hand, energy policy is not harmonised – each country makes its own decisions about how much and which type of generation and transmission capacity it should build. Because it is relatively easy to subsidise renewable generation into existence, that has been prioritised, but the investments in transmission, storage and low carbon baseload generation (nuclear) which are needed to efficiently manage this new renewable generation capacity has been lacking. To make matters worse, the economics of gas generation are declining, as utilisation levels drop, pushing efficient gas plant out of the market altogether in some cases (for example the Calon CCGTs in the UK).
It is difficult to see how this situation can continue much further without significant change. In particular, it is hard to see why Norwegian consumers should be exposed to the high electricity prices that are the result of lack of investment by other European countries. So to answer the question posed at the start of this blog…can Norway be the battery of Europe…perhaps, but should it? Probably not.
You pulled together a lot of interesting detail. The late Roger Andrews tackled this question back in 2013, and his underlying analysis is still entirely relevant and accurate, because not much has changed in the hydro system. As he explains, exports are limited to total generation less local demand, while imports can never be more than demand, replacing local generation. It makes no sense to convert generation to pumped storage capability because of the export limitation, aside from the fact that not running hydro when using imports is almost 100% efficient storage.
http://web.archive.org/web/20160801042131/http://euanmearns.com/how-much-wind-and-solar-can-norways-reservoirs-balance/
He concludes
Over the next few decades forests of offshore wind turbines are scheduled to be planted in the North Sea and linked to mainland centers of consumption through the proposed North Sea supergrid. When the wind blows these forests of turbines will deliver far larger amounts of power than the centers of consumption can possibly use, and the bulk of it will have to be wasted if nowhere can be found to store it. But where will this immense amount of storage be found? One thing is for sure; it won’t be Norway.
The NSL interconnector has been limited to a maximum of 700MW under a succession of Norwegian excuses, some physical like the problems at the Blyth converter station, and the low reservoir levels, but also the effects of the huge difference in prices that often exists. Opening up the direct link to Germany had dramatic effects on prices in Oslo.
https://datawrapper.dwcdn.net/fLVEo/1/
lf the links are larger than the slack in the system then they define the local market price, threatening to bid away supply from the local market. Perhaps the Norwegians might be happier if we get around to massive wind surpluses at negative prices on a regular basis. Subsidising Norwegian consumers may sit less well with other Europeans who will still be paying for PtG and massive overinvestment in renewables to be able to feed it..
Interesting article and a perspective on Norway I hadn’t seen before. Could you please explain the statement “[Norway] tends to export when power prices are high in Norway and imports when power prices are low”? It contradicts basis supply/demand economics.
Hi Kathryn…..thanks for a most interesting posting, prompting this speedy response.
Teasing out accurate detail is so refreshing in the glib world of mis-information.
Not the first time I have learned of Norwegian hydro storage acting like a huge battery.
Just 1400MW across a mix of 10 plants offering slow response pumped storage is small beer IMO.
So pleased your posting mentioned that amazing feat of British engineering; Dinorwig.
Built by the nationalised CEGB to offer off peak storage to Wylfa & Heysham nuclear plants.
Six 300MW reversible turbines can deliver 1.7GW in 17 secs. NGESO love them.
Designed to self start from cold & re-boot a blacked out supergrid network, an added bonus.
That to me is a proper integrated pumped storage scheme (battery) with added value.
Barry Wright, Lancashire.
Dinorwig also has an excellent visitor centre!
The Norwegian pumped storage does what it was designed to do…we can’t really compare it with Dinorwig because the problem it was aimed to solve was different. It’s only now that other countries have decided to backstop their own electricity systems with Norway’s hydro capacity that they might be needed in a different way, but it would be a bit harsh to judge the Norwegians for not anticipating this decades ago when they built their systems!
As usual a very informative article that really gets below the surface of how involved running the electricity system is nowadays. When i read Electrical Engineering the module on the CEGB management of cost was the rather simple merit order and a nice banker question for the exam too many variables now!!
I was surprised to see price rises in Norway as surely they are hardly exposed to the price of fossil fuels like many European countries are. Also given how dependant they are on Hydro generation I would have thought on a security of supply level govt would tell Statnett to stop exporting if reservoir levels fall below a certain threshold. Its not as if Norway need the money as its nicely leveraged to gas and oil price.
Whilst i get the rationale over pump storage there is still the benefit to substitute import electricity over draw down of reservoir reserves but guess the price has to be right. Given UK metered wind today is running at 14GW as i write this and our national demand is down as its warmed up a bit the Norwegians are still in export mode to us. Mind you even over the weekend our 25GW of metered wind still only got to just shy of 15GW as to whether it was constrained we will have to see what NG report.
Norway is outside the EU but inside the market coupling regime, however, in its shoes I absolutely would be curtailing cross-border capacity, and we may yet see that happen.
I think the problem with imports displacing reservoir discharge is that if the imports happen when Norway doesn’t particularly need the power than the replacement value is low. If this was really working properly, the Norwegian hydro levels wouldn’t be so low…perhaps a dry year has happened to coincide with 2.8 GW of new cross-border capacity, but perhaps not. The sharp rise in Norwgian prices suggests this isn’t working how they hoped…
but it would be a bit harsh to judge the Norwegians for not anticipating this decades ago when they built their systems!
Hi again….I admire Norway on many fronts, not least their management of indigenous resources & the sovereign wealth fund etc. leading to them being one of the richest nations in the world, they obviously got something right, sure we could learn much from their model.
However Dinorwig came on stream 1984.
I just couldn’t resist an opportunity to fly the flag.
Courage, initiative, & forward thinking some 40 years ago in my view deserves a place in any debate.
Barry Wright, Lancashire.
Barry quite right to fly the flag a brilliant bit of foresight by the CEGB that still delivering stellar service after 38 years despite being hammered far harder almost day in day out than it was ever expected to do. Built by the great GEC as well and without going completely off the topic not sure we even make anything for the NG today.
Another excellent and thought provoking post. Why are these issues not debated more widely. Even the technical press is superficial and follows group think faith. National Grid could instigate these debates but has changed from a well respected independent and neutral expert to a political and commercial peddler of simplistic myths. Politicians who repeat these myths have at last moved on from saying it is always windy somewhere in the UK to saying it is always windy somewhere in Europe which interconnectors can share around. However Interconnectors can only ever be the icing on the cake and serve a marginal mutual benefit. In the NG Winter Outlook both wind and interconnector flows are treated very optimistically when in reality wind can be near zero and interconnector flows can go both ways. DC interconnector flows can even go round in circles – this is obviously to someones benefit but not the consumers. Is it in the consumers interest to have interconnectors importing and exporting at the same time or pumped storage stations pumping and generating at the same time?
Dinorwig is a fantastic piece of kit whose technical flexibility is now unfortunately limited by commercial considerations. Here in Wales there are huge opportunities for development of small scale hydro and pumped storage schemes but the focus is entirely on wind and solar.
Did I put in too many links? Sometimes that pushes comments to the spam/trash bin.
It by-passed the moderation queue and went straight into the bin – I’ve approved it now. I’m guessing you use a VPN since the software recognises regular comments from the same IP address and automatically approves them, but I always have to do yours manually (hence there can sometimes be a delay)…I have no issues with that, but you might need to give me a nudge if something doesn’t appear…
Interesting & well-written as always Kathryn, thanks.
At the risk of over simplifying (my points won’t address all the issues you allude to), but to play devil’s advocate a little wrt the Norwegian aspects:
1. wouldn’t an increase in more faster-ramping pumped hydro in NO be possible / who has studied this / how much would it cost? I’m not suggesting this is trivial, but surely something must be possible, thereby making the NO energy system more flexible & alleviating some of the problems?
2. ditto with NO’s power mix, which relying heavily on just one source (hydro) is always going to be vulnerable (to any unexpected factors eg bellic or climate/weather related, however unlikely that may seem at present). Increased offshore wind (for example) would increase brute generation capacity & hence alleviate at least some of the fuel poverty issues you mentioned. Adding green hydrogen into the mix would help too, perhaps significantly (soaking up the surplus wind as & when most appropriate).
3. W/o knowing much about NO’s industry make-up, the country’s O&G expertise should presumably be able to build blue & grey hydrogen capacity in the south to decarbonise industry, amongst other things.
You are raising legitimate questions on a grander (& very relevant) European & intra-state scale, which I’m not claiming the above will satisfactorily address, at least within the time & costs constraints we may all be facing. But the advent of (many colours of) hydrogen across many nations over the next 10Y (or less according to BNEF & other more bullish observers) I think should help make national markets more flexible, & hence more able to adjust for imbalances elsewhere when they occur.
Have not studied this properly, just some random thoughts I’d welcome your views on. Thanks again for your excellent posts!
I can really recommend the Roger Andrews article I linked to in my reply above. There is an excellent debate in the comments from knowledgeable people with experience of Norway and of hydro systems engineering and economics which addresses most of your questions.
The fuel poverty issue arises simply because Norwegians must pay if they want to keep electricity for themselves when there is a high priced bidder on the other end of an interconnector. The only way to stop that is to limit interconnector exports. Hydro is extremely low cost, and in fact you will see in the chart I posted the per MWh price was close to zero during the low demand lockdowns in 2020, and it used to be the case that the majority of a Norwegian electricity bill was to pay for the poles and wires that deliver it.
Norwegian industry is already heavily decarbonised. Norsk Hydro uses cheap power to smelt aluminium for instance, though the consumption of carbon anodes does produce CO2. They are even running cables from onshore out to oil and gas platforms to provide their power needs instead of using the readily available gas to power turbines at the platforms: this is expensive vanity green spending, justified by a high carbon tax.
There would be very little sense in building green hydrogen in Norway, as you have to add interconnectors to supply it, hugely adding to costs, and it destroys energy prodigiously. Importing in place of generating is almost 100% efficient. Using pumped hydro drops that to about 70-75%, allowing for interconnector losses as well as pumping loss. Using hydrogen drops it to 60% to make the hydrogen, and then 50-60% (depending on whether it is peak lopping or baseload) of that to recover electricity from it.
The reality is that hydrogen is a very high cost route however you do it. It is only being considered because a) batteries are even more ridiculous for serious volumes of storage, and b) there isn’t anywhere enough potential hydro capacity to provide what would be needed for a wind and solar grid. Frankly the storage volumes required for hydrogen would be challenging to put it politely, and the economics look frightening.
Really interesting read, thanks Kathryn! One point doesn”t make sense to me though, you don’t pumped storage in the Norwegian hydro system to soak up the wind resource when it is abundant, you just need flexible generation. Ie if the hydroelectric stops producing power this water is saved in the dam for later use, meaning there is in fact 33GW of storage in the system.
It seems an incredible waste to not tap into this flexibility. Surely there is a mechanism to ensure Norwegian consumers can benefit in the windfall too (which the hydro plants will undoubtedly experience).
Paul-Frederik Bach has a fascinating map of the net electricity flows across borders in Europe in 2021
http://pfbach.dk/
Also a map showing the more detailed flows within the Nordic region linked immediately below..
Surely the UK links will help when we have more wind power planted. In the next 3 years we could see the UK with an additional 6-7 GW of wind power. When it is most windy, Autumn to April we will be able to support the Norwegian power requirements over most nights and some of the daytime too. That leaves them with lakes not being so quickly depleted as the snow falls. Low lake levels in Autumn should prove to be less of an issue to them in the knowledge that they will get substantial support over winter.
Does their system require a minimum level of generation to maintain the ecology of rivers below the hydro dams? This is an interesting feature of hydro power in New Zealand where they measure spilled water, that is water let through dams without generating power.
And the Scottish oil and gas industry is preparing to be supported by offshore turbines in order to remove the need to burn fossil fuels to run the platforms. Won’t Norway follow suit?
Great article by Kathryn Porter who obviously knows what she is talking about. Although I would like to add one detail that is missed here, or at least can be misunderstood. Norway indeed has only a few hydro power plants equipped with pumps, but Norway nonetheless has large amounts of controllable hydro power – much more than described in the article. The most common way to control output of a hydro power plant in Norway is using the gates, not the pumps. Many Norwegian hydro power plants are located at vast reservoirs, where output is controlled by lifting or closing the gates. This should be reflected in the text, otherwise the conclusions might be misleading.
A very interesting article for a water resources engineer who did feasibility studies on hydropower for a Consultant who designed part of Dinorwig before I joined. I have also carried out a review of England and Wales looking for pumped storage hydro sites and found about 115. The most attractive are the use of old quarries and open-cast coal pits. Scotland already has 8 schemes with planning permission. One of these Glenmuchlock is an old open cast pit. Out of interest, I looked at Norway when I heard about the interconnector on the BBC and had the impression that the Norwegians were going to develop a new pumped storage project at the same time. Norway looks like a PSH engineer’s dream with deep fjords and high plateaus, many having existing lakes or flat wet areas.
I see the paper was published in early February before the Russian Invasion of Ukraine and wonder if a new security unity within Western Europe through NATO might have changed national outlooks to be independent of Russian gas. Clearly most of the Norwegian hydro is not pumped storage and susceptible to long dry periods when run-of-river schemes run approach environmental limits and reservoirs become depleted. This is likely to occur more frequently as climate change impacts occur. Pumped storage in closed systems will not have this problem especially if operating with saline fjord water.
Just a note about the UK. Dinorwig was built specifically to partly match an 8 GW (it may have been less then) 5-hour peak in the UK’s daily winter demand along with the other 4 PSH stations. Today the need is for long-duration storage which means they can be designed for longer duration. If designed for 15 hours, the power capacity and flows are 1/3 so, for the same energy output turbines can be much smaller, and pipes or tunnels have much smaller diameters. In fact that makes smaller schemes with say 150m head difference and buried pipe transmissions that can be built in a far shorter time very economically viable especially using quarries already full of water and high-level bunded reservoirs. Somewhere such as the South Wales coalfield has some 6 of these pits as well as some 400 deep mines full of water above 25deg,C and high flat topped hills.