Singapore, Vietnam eye greater low-carbon power trade

Spanish Market: Electricity
28/03/25

Singapore and Vietnam have signed a letter of intent (LOI) to enhance collaboration on cross-border electricity trade for the Asean power grid.

Under the LOI, the countries will explore raising the targeted capacity of low-carbon electricity imports from Vietnam to Singapore to around 2GW by 2035, announced Singapore's Ministry of Trade and Industry on 26 March.

This builds on the previous conditional approval that was granted by Singapore's Energy Market Authority to Sembcorp Utilities in October 2023 to import 1.2GW of low-carbon electricity from Vietnam. The electricity will be transmitted from Vietnam to Singapore via new sub-sea cables of around 1,000km.

The Vietnam and Singapore governments will continue to engage interested companies that have credible and commercially viable proposals, said MTI.

"This LOI reflects our enhanced level of ambition to support not just cross-border electricity trading between our two countries, but the broader development of a sustainable, inclusive and resilient Asean power grid," said Singapore's second minister for trade and industry Tan See Leng.

Singapore aims to import up to 6GW of low-carbon electricity by 2035, and has signed supply agreements with Malaysia, as well as granted conditional approvals to projects in Indonesia.

There have been steps toward the development of the long-awaited Asean power grid, which once established, could help the region source and share electricity regionally. The Lao PDR-Thailand-Malaysia-Singapore power integration project (LTMS-PIP) will be enhanced under its second phase to double the capacity of electricity traded from 100MW to a maximum of 200MW, the EMA announced in September last year.

By Prethika Nair

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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.

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.

US mulls cutting funds to H2 hubs outside of GOP states

27/03/25

US mulls cutting funds to H2 hubs outside of GOP states

Houston, 27 March (Argus) — The US Department of Energy (DOE) is considering cutting funding to hydrogen hubs that are located in primarily Democratic states, while sparing those mostly spread across Republican states, according to a list shared with Argus . A table circulating among officials shows hubs that are to receive federal funding labeled as either "cut" or "keep." Out of the seven hubs, only three are set to "keep": HyVelocity, in Texas and Louisiana, the Appalachian hub spanning Ohio, Kentucky and West Virginia and the Heartland hub spread across Minnesota, South Dakota and North Dakota. The hubs that may lose federal support include California's ARCHES; the Pacific Northwest Hydrogen Association (PNWH2) spanning Oregon, Washington and Montana; the Midwest hub encompassing Illinois, Indiana and Michigan, and the Mid-Atlantic hub in Pennsylvania, Delaware, and New Jersey. With the exception of the Midwest hub, most of the hubs facing potential cuts would use renewable and nuclear power to produce hydrogen. Most of the projects in the hubs on the "keep" list would be powered by natural gas and use carbon capture and storage (CCS) facilities to reduce emissions. The DOE did not immediately respond to requests for comment. Fuel Cell and Hydrogen Energy Association (FCHEA) chief executive Frank Wolak said the list came from DOE but cautioned the department's plans are still unclear."We're aware a list has been created that shows four of seven hubs being cut," said Wolak. "We haven't seen anything formal and don't understand exactly what is the DOE intention." Hydrogen hub funding advanced by the administration of former president Joe Biden was expected to come under scrutiny after President Donald Trump paused disbursements and ordered a review of clean-energy initiatives. Federal funding for the hubs grew out of the bipartisan Inflation Reduction Act and the Infrastructure and Investment Jobs Act, which together dedicated $8bn to jump start domestic hydrogen production in industrial clusters from the east to west coasts. The funding was structured to pay out to the hubs over four phases spanning a decade, with disbursements dependent upon projects meeting defined objectives related to operational progress and private-investment commitments. The first tranches to the seven hubs, totaling over $20mn, have been delivered but the list of potential cuts puts the fate of the second phase into doubt. "So far the Trump administration hasn't attempted to claw back that phase-one funding," said Sara Gersen, senior attorney for Earthjustice. "The question is, what happens in 2026 when they try to renew contracts for phase 2?" ARCHES chief executive Angelina Galiteva said the California hub "remains committed to working with our partners to establish a secure, reliable and competitive hydrogen ecosystem". Spokespeople for the others hubs vulnerable to losing federal funds did not immediately respond to requests for comment. However, at least one of the hubs put out a public statement highlighting how its goals align with the administration's objectives. "Many of these opportunities will support rural communities" and "advance American energy independence", the Pacific Northwest hub said in a social media post. Environmental advocates argue that the climate benefits from hydrogen originating from natural gas with CCS, the technology proposed for projects on the "keep" list, evaporate when net emissions are taken into account and do not justify the potentially billions of dollars in federal support they may receive when compared to other decarbonization techniques. "Spending billions of dollars on untested carbon capture technology in applications with no net-climate benefit is a waste of taxpayer money," said Anika Juhn, IEEFA energy data analyst and co-author of the report Blue Hydrogen's Carbon Capture Boondogle . "Building out renewable power infrastructure, improving energy efficiency, and reducing methane leakage from the natural gas system are more cost-effective and proven approaches to a clean energy transition." For now, both fossil-fuel based and renewable energy companies have been lobbying the Trump administration to keep clean energy incentives enacted by the IRA without differentiating how the hydrogen is produced. The potential cut to federal funding is not expected to affect industry support for the most lucrative incentives that come in the form of tax cuts, such as the support that has coalesced around protecting the 45V hydrogen production credit, said Wolak. "I don't see any change to the agenda of 45V, that effort is primary," said Wolak. "I see an effort perhaps arising to define the hubs and the merit of the hubs rising parallel to the 45V effort." FCHEA is advising its members that may be affected by hub funding cuts to contact their congressional representatives, Wolak said. By Jasmina Kelemen Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

France delays solar subsidy reductions

27/03/25

France delays solar subsidy reductions

London, 27 March (Argus) — Planned cuts in subsidies to building-mounted solar installations will not be made retroactive after the solar sector successfully lobbied the French government, but other changes will still go ahead. The government today published final legislation on changes to feed-in tariffs for new solar sites under 500kW capacity mounted on buildings or above fields or car parks. The legislation is intended to reduce the amount of capacity being built in this sector, as it is less cost-effective than larger sites, the government said. For the 100-500kW segment, for which the government proposed to reduce the tariff retroactively from 1 February, the drop to €95/MWh from €105/MWh will take place for all projects registered from now, rather than since the beginning of February. And a planned monthly reassessment of the tariff — to allow it be to be reduced if too many projects applied — will only kick in from 1 July. But sharp cuts remain on tariffs for smaller installations, and for self-consumption, although they too are no longer retroactive. Project developers on large installations will now also need to provide a €10,000 deposit, intended to reduce the drop-out rate from projects which do not advance to construction. The government intends to put in place a tender mechanism for the 100-500kW sector, replacing the current open window system. It hopes to set this up by September to take over when the cut in tariffs for this sector begin to kick in. Solar actors' reaction to the news was mixed. Renewables association SER welcomed the delay to cuts for the 100-500kW segment. But much uncertainty remains over the volume to be offered and the frequency with which the tenders to replace this sector will take place. There is a risk that the "cliff edge" the association had warned about has just been pushed back to 1 July from 1 February, SER president Jules Nyssen said, if the tenders are not ready to go in time. By Rhys Talbot Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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