Netherlands 'taking steps' towards new nuclear plants

Spanish Market: Electricity, Hydrogen
13/06/22

The Dutch government is "taking steps" towards the construction of two new nuclear power plants, according to a national energy system plan outlined last week.

According to the outline published on Friday, a scenario study is being conducted into the relationship between various types of CO2-free capacity and how nuclear energy can be integrated into the Dutch power mix. The study is also looking at the cost efficiency of nuclear energy at the system level and the potential benefits in terms of use of space and infrastructure investments. The outline also says the role that nuclear energy can play in the production of hydrogen will be explored.

The outline states that future domestic capacity will cover "approximately" the Netherlands' direct annual power demand and that given the variable nature of renewable generation, flexibility must increase. The required adjustable generation — which nuclear generation offers, the outline says — would also have to be CO2-free.

The government's coalition agreement at the end of 2021 stated that the country would aim to build two nuclear reactors after 2030 and extend the lifespan of the only active reactor, the 485MW Borssele plant. Nuclear output from Borssele has averaged just over 414MW in 2022, around the same as in 2021,when it averaged 412MW.

Onshore and offshore wind output has risen by an average of 177.29MW and 282.72MW, respectively, on the year in 2022. The government last week announced tenders for six new offshore wind farms totalling 10.7GW to be held in 2025-27, with the view to launching them in 2029-31.

By Helen Senior

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02/04/25

UK to sign remaining CfDs for first H2 round in May

Birmingham, 2 April (Argus) — The UK hopes to sign long-awaited subsidy contracts with the remaining projects from its first hydrogen allocation round (HAR1) in May, minister of state for the department of energy security and net zero, Sarah Jones, said. The UK will also "very shortly" unveil a shortlist of projects selected for subsidies of a larger second round (HAR2), Jones said at the Hydrogen UK conference in Birmingham today. But the announcement will hardly satisfy UK developers who have been expecting the shortlist any day since late 2024 . The missing list was the top talking point among delegates at the event. The UK has signed 15-year contracts-for-difference (CfDs) with four of the 11 renewable hydrogen projects selected in HAR1 , according to the latest information from the Low Carbon Contracts Company (LCCC), the government-backed counterparty. Finalising the rest of the CfDs is long-overdue in the eyes of many developers because the UK first announced its winners in December 2023. The process was delayed by the general election last summer and concerns around the Climate Change Levy (CCL) charged on electricity supply, among other issues. The new government took a step towards assuaging concerns about the CCL last week which might allow more projects to sign contracts. But HAR1 developers have warned that signing a CfD does not guarantee they will build projects straight away, since there is hardly any penalty for signing the subsidy deal. Some still need to finalise deals for power supply, construction contracts and financing, meaning it could still take time for signatories to take their final investment decisions. The UK will also update its hydrogen strategy later this year, Jones said. "New evidence has emerged on cost, demand and expected operating patterns, and our understanding has evolved with time," including on "how we can expect the hydrogen economy to develop over time," Jones said. The statements could indicate that the Labour government might amend the 10GW clean hydrogen production target set by the previous administration for 2030, according to one industry participant. The Conservative government's 10GW goal from 2022 had included a sub-target for 6GW electrolytic production capacity. The government will also reconsider the role of hydrogen in making steel in the UK, Jones said. The idea of using hydrogen for steel appeared to have little future in the UK under the previous government as concepts from the UK's steel plants had made no tangible progress . By Aidan Lea Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Australia’s gas leaders hit out at market intervention

02/04/25

Australia’s gas leaders hit out at market intervention

Sydney, 2 April (Argus) — Senior figures in Australia's upstream gas sector have hit out at plans for intervention in the heavily regulated industry, as debate continues on how to best address domestic supply shortfalls later this decade. The federal Coalition in March announced National Gas Plan including a 50-100 PJ/yr (1.34bn-2.68bn m³/yr) domestic reservation system aimed at forcing the three LNG exporters based in Queensland's Gladstone to direct more supply to the eastern states' market. But oversupplying the market to drive down prices would destroy the viability of smaller gas projects, Australian independent Beach Energy's chief executive Brett Woods said at a conference in Sydney on 1 April. The domestic-focused firm, which will export some LNG volumes via its Waitsia project in 2025, warns that such a move by the Peter Dutton-led opposition would reduce export incomes while harming Australia's international reputation. The volumes impacted by the policy could reach around 900,000-1.8mn t/yr. Expropriation of developed reserves is equivalent to breaking contracts with LNG buyers and with the foreign and local investors that the country needs for ongoing economic security, Woods said on 1 April. Domestic gas reservation systems put in place by the state governments of Western Australia (WA) and Queensland, designed to keep local markets well supplied, were "clearly supportable", Woods said, but only future supply should be subject to the regulations. LNG terminals, which represent about 70pc of eastern Australia's total gas consumption and shipped 24mn t in 2024 , should not be blamed for the failure of governments to expedite new supply and plan for Australia's gas future, head of Shell Australia Cecile Wake said in response to the Coalition's proposal. Shell's QGC business supplied 15pc of its volumes to the local grid, with the remainder shipped from its 8.5mn t/yr Queensland Curtis LNG project, Wake added. Canberra has moved to promote gas use as a transition fuel to firm renewable energy in line with its 2030 emissions reduction targets, but progress has been slow as reforming laws appear to be hampering development . The state governments, particularly in gas-poor Victoria and New South Wales (NSW), must recognise the need for locally-produced supply and streamline the approvals processes, especially environmental permits, executives said. But despite pleas for an end to years of interventionist policy — including the governing Labor party's measures to cap the price of domestic gas at A$12/GJ , Australia's fractured political environment and rising cost of living has sparked largely populist responses from its leaders. A so-called "hung" parliament is likely to result from the 3 May poll , with a variety of mainly left-leaning independents representing an anti-fossil fuel agenda expected to control the balance of power in Australia's parliament. LNG debate sharpens Debate on the causes of southern Australia's gas deficit has persisted, and the ironic outcome of underinvestment in gas supply could be LNG re-imports from Gladstone to NSW, Victoria and South Australia, making fracked coal-bed methane — liquefied in Queensland and regasified — a likely higher-emissions alternative to pipeline supply. Several developers are readying for this possibility , which is considered inevitable without action to increase supply in Victoria or NSW, increase winter storages or raise north-south pipeline capacity. Australian pipeline operator APA appears to have the most to lose out of the active firms in the gas sector. APA chief executive Adam Watson this week criticised plans for imports, because relying on LNG will set the price of domestic gas at a detrimental level, raise emissions and decrease reliability of supply, Watson said. The firm is planning to increase its eastern pipeline capacity by 25pc to bring new supplies from the Bass, Surat and Beetaloo basins to market. But investment certainty is needed or Australia will risk needing to subsidise coal-fired power for longer if sufficient gas is unavailable to back up wind and solar generators with peaking power, Watson said. By Tom Major Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

LNG stocks at Japan’s power utilities rise

02/04/25

LNG stocks at Japan’s power utilities rise

Osaka, 2 April (Argus) — LNG inventories at Japan's main power utilities increased during the week to 30 March, as warmer weather reduced electricity demand for heating purposes and limited gas-fired generation. The utilities held 2.24mn t of LNG on 30 March, up by 22pc from a week earlier, according to a weekly survey by the trade and industry ministry Meti. This was higher by 51pc compared with 1.48mn t at the end of March 2024 and up by 10pc against 2.03mn t — the average end-March stocks over 2020-24. A seasonal rise in temperatures weighed on power demand, which fell by 12pc on the week to 87GW across 24-30 March, according to the Organisation for Cross-regional Co-ordination of Transmission Operators (Occto). This resulted in a 24pc fall in gas-fired output to an average of 24GW during the period, the Occto data showed. Coal- and oil-fed generation also fell by 14pc to 23GW and by 21pc to 409MW respectively in the same period. The lower demand has created extra supplies to be sold on the wholesale market. This has weighed on day-ahead prices on the Japan Electric Power Exchange (Jepx) and worsened generation economics for the country's thermal power plants. Margins at a 58pc-efficient gas-fired unit running on oil-priced LNG supplies fell into negative territory, with the spark spread averaging at a loss of -¥2.28/kWh ($15.22/MWh) across 24-30 March, compared with the previous week's profit of ¥0.84/kWh. The 58pc spark spread using spot LNG widened the deficit, with the margin averaging at a loss of -¥3.79/kWh against the previous week's -¥0.80/kWh, based on the ANEA — the Argus assessment for spot LNG deliveries to northeast Asia. Coal remained competitive in Japan's merit order. But the dark spread of a 40pc-efficient coal-fired unit also fell by 64pc on the week to an average of ¥1.63/kWh over 24-30 March, based on Argus' spot coal and freight assessments. By Motoko Hasegawa Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

French nuclear modulation to step up this summer

01/04/25

French nuclear modulation to step up this summer

London, 1 April (Argus) — Modulation in the French nuclear fleet, and the consequent gap between nuclear availability and output, is set to grow in the coming weeks as consumption falls in summer and solar output picks up. But the fleet's ability to modulate, touted as one of its great strengths, could be put to the test by growing amounts of intermittent renewable capacity, without any accompanying rise in consumption or in flexible storage capacity. France's flexible nuclear plants are unusual in being able to modulate their output downwards, with each reactor capable of dropping twice a day to 20pc of rated output. Nuclear reactors by their nature have high fixed costs and low variable costs. But operator EdF still reduces production in hours in which prices fall below these low variable costs, widening the gap between the theoretical available capacity and actual production. And low-priced hours became more common last year, particularly in the summer, in the middle of the day and on weekends, as low demand coincided with high nuclear and renewable production. The gap between availability and output across the fleet typically has held at 1-2GW on a monthly basis in recent years. But last summer, it jumped to 4GW on average in each month from April-August ( see availability-output gap graph ). And so far this year it has averaged 2GW, compared with 1.8GW in the same period last year. Modulation has held higher too, with the difference between maximum and minimum daily nuclear output averaging 4.6GW, up from 3.2GW last year ( see modulation graph ). Solar output so far this year has averaged 2.4GW, up by 35pc on 1.8GW in the same period in 2024, after France's solar fleet grew by 5GW, or roughly a quarter, over 2024. As output increases with longer days, this will begin translating into increasingly more output centred around midday, driving stronger modulation. Modulation becomes political Modulation has this year become a political football, with the government promoting the parallel growth of nuclear and intermittent renewables, while an insurgent faction, typically on the political right, claims that more renewables are at best wasteful and at worst actively damage the nuclear fleet. France's nuclear fleet has always modulated, as its large size means residual demand is lower than capacity in low consumption periods. But the extent of this modulation grew sharply last year. Lower consumption contributed to this, as did the growth of renewables. Much of France's renewable capacity is not exposed to market prices, as it is remunerated by feed-in tariffs, and has no incentive to shut down when prices fall below zero. Even the minority of capacity that is required to halt production when prices fall below zero in order to retain subsidy still can produce at prices only slightly above zero, or below the marginal cost that drives EdF to modulate down nuclear output. Operator EdF defends its ability to modulate. The firm's nuclear chief, Etienne Dutheil, last year told a senate commission that the fleet's ability to modulate was the "envy" of other operators. And modulation has "very few effects" as long as it is partial and does not require a total shutdown that makes the plant cool down, he said. The firm told the senate enquiry that thus far, there is "no proven statistical link between modulation and a possible loss of production or increased failures of plants". But modulation could increase wear on reactors' secondary circuits and consequently increase maintenance needs, it said. Proponents of a combined nuclear and renewables approach say that meeting France's goals for electrifying end-uses will require a large volume of extra electricity in the coming years, which potential new nuclear plants — planned for the second half of the next decade at the earliest — will not be able to deliver in time. But opponents decry the combination of nuclear and renewables as wasteful, given that EdF does not save on any of its hefty fixed costs when modulating down nuclear plants to make way for zero-marginal cost renewable output, essentially putting a double burden on consumers that have to pay twice for two separate generating fleets. And others put forward the damage that they say modulation does to the nuclear fleet. Rassemblement National (RN) leader Marine Le Pen raised the topic in a written question to the government last month, asserting that modulation "prematurely ages pipes and welds of reactors". And even some internal EdF documents present modulation in a less benign light than the firm's chiefs. The combination of renewables and nuclear leads to power output fluctuations that are "never insignificant in terms of safety, especially of the control of the reactor core, and the maintainability, longevity and operating costs of our facilities", according to a 2024 report by the company's chief nuclear safety inspector. The PPE3 energy plan, which the government hopes to finalise in law imminently, commits France to rapid increases in renewables deployment. If the plan's objectives are followed, intermittent output will grow in the coming years. The plan also aims for a rapid increase in consumption to soak up the extra power produced. But potential drivers of electrification such as heat pumps and electric vehicles had their subsidies slashed in the 2025 budget. Increased storage capacity could be a way to integrate more intermittent renewables. France already has pumped-storage sites that can add up to 3.8GW of flexible demand during peak output periods. But battery storage is little developed in France, thanks partly to these pumped-storage sites and to nuclear modulation, both of which limit intra-day spreads. As battery capacity grows, it typically quickly saturates the ancillary services market and these wholesale spreads will become increasingly important for making battery projects profitable. By Rhys Talbot Nuclear availability-output gap GW Daily nuclear modulation (max-min output) Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Global energy mix evolves as electricity demand surges

28/03/25

Global energy mix evolves as electricity demand surges

Climate change is becoming a bigger factor behind electrification, but cleaner energy use is slowing the growth in global emissions, writes Georgia Gratton London, 28 March (Argus) — A substantial increase in electricity demand — boosted by extreme weather — drove an overall rise in global energy demand in 2024, lifting it well above the average pace of increase in recent years, OECD energy watchdog the IEA announced this week. This led to a rise in natural gas consumption, although renewables and nuclear shouldered the majority of the increase in demand, leaving oil's share of total energy demand below 30pc for the first time. Global energy demand rose by 2.2pc in 2024 compared with 2023 — higher than the average demand increase of 1.3pc/yr between 2013 and 2023 — according to the Paris-based agency's Global Energy Review . Global electricity consumption increased faster, by 4.3pc, driven by record-high temperatures — that led to increased cooling needs — as well as growing industrial consumption, the electrification of transport and the rapid growth of power-hungry data centres needed to support the boom in artificial intelligence, the IEA says. Renewables and nuclear covered the majority of growth in electricity demand, at 80pc, while supply of gas-fired power generation "also increased steadily", the IEA says. New renewable power installations reached about 700GW in 2024 — a new high. Solar power led the pack, rising by about 550GW last year. The power generation and overall energy mix is changing, as economies shift towards electrification. The rate of increase in coal demand slowed to 1.1pc in 2024, around half the pace seen in 2023. Coal remained the single biggest source of power generation in 2024, at 35pc, but renewable power sources and nuclear together made up 41pc of total generation last year, IEA data show. Nuclear power use is expected to hit its highest ever this year, the agency says. And "growth in global oil demand slowed markedly in 2024", the IEA says, rising by 0.8pc compared with 1.9pc in 2023. A rise in electric vehicle (EV) purchases was a key contributor to the drop in oil demand for road transport, and this offset "a significant proportion" of the rise in oil consumption for aviation and petrochemicals, the IEA says. Blowing hot and coal Much of the growth in coal consumption last year was down to "intense heatwaves" — particularly in China and India, the IEA found. These "contributed more than 90pc of the total annual increase in coal consumption globally", for cooling needs. The IEA repeatedly noted the significant effect that extreme weather in 2024 had on energy systems and demand patterns. Last year was the hottest ever recorded, beating the previous record set in 2023, and for CO2 emissions, "weather effects" made up about half of the 2024 increase, the watchdog found. "Weather effects contributed about 15pc of the overall increase in global energy demand," according to the IEA. Global cooling degree days were 6pc higher on the year in 2024, and 20pc higher than the 2000-20 average. But the "continued rapid adoption of clean energy technologies" restricted the rise in energy-related CO2 emissions, which fell to 0.8pc in 2024 from 1.2pc in 2023, the IEA says. Energy-related CO2 emissions — including flaring — still hit a record high of 37.8bn t in 2024, but the rise in emissions was lower than global GDP growth. Key "clean energy technologies" — solar, wind and nuclear power, EVs and heat pumps — collectively now prevent about 2.6bn t/yr CO2 of emissions, the IEA says. But there remains an emissions divide between advanced and developing economies. "The majority of emissions growth in 2024 came from emerging and developing economies other than China," the agency says, while advanced economies such as the UK and EU cut emissions last year and continue to push ahead with decarbonisation. Global energy suppy by fuel EJ Growth ±% 2024 2023 2022 24/23 23/22 Total 648 634 622 2.2 1.8 Renewables 97 92 89 5.8 3.1 Nuclear 31 30 29 3.7 2.2 Natural gas 149 145 144 2.7 0.7 Oil 193 192 188 0.8 1.9 Coal 177 175 172 1.2 2.0 Global power generation by fuel TWh Growth ±% 2024 2023 2022 24/23 23/22 Total 31,153 29,897 29,153 4.2 2.6 Renewables 9,992 9,074 8,643 10.0 5.0 Nuclear 2,844 2,743 2,684 3.7 2.2 Natural gas 6,793 6,622 6,526 2.6 1.5 Oil 738 762 801 -3.2 -4.8 Coal 10,736 10,645 10,452 0.9 1.8 Global power generation by country TWh Growth ±% 2024 2023 2022 24/23 23/22 World 31,153 29,897 29,153 4.2 2.6 US 4,556 4,419 4,473 3.1 -1.2 EU 2,769 2,718 2,792 1.9 -2.6 China 10,205 9,564 8,947 6.7 6.9 India 2,059 1,958 1,814 5.2 7.9 Global CO2 emissions by country mn t Growth ±% 2024 2023 2022 24/23 23/22 World 37,566 37,270 36,819 0.8 1.2 US 4,546 4,567 4,717 -0.5 -3.2 EU 2,401 2,455 2,683 -2.2 -8.5 China 12,603 12,552 12,013 0.4 4.5 India 2,987 2,836 2,691 5.3 5.4 *includes industrial process emissions — IEA Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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