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.
“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
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.