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Singapore adds $3.7bn clean energy funds, mulls nuclear

  • Market: Electricity, Hydrogen
  • 19/02/25

Singapore will add a further S$5bn ($3.7bn) to its clean energy fund, and is also studying the potential for nuclear deployment, said the country's prime minister Lawrence Wong on 18 February.

Singapore's Future Energy Fund was set up in 2024 with an initial injection of S$5bn to develop clean energy options.

Expanding access to clean energy is a major national imperative as "the industries of the future," such as artificial intelligence and semiconductors, are highly energy intensive, said Wong at the unveiling of the country's budget for 2025. "Be it electricity imports, hydrogen or nuclear, we need to make major investments in new infrastructure," said Wong.

A short-term solution is to import low-carbon electricity from the region. Singapore expects about a third of its projected electricity demand in 2035 to be met through electricity imports, according to Wong. The country aims to import 6GW of low-carbon electricity by 2035, and has signed supply agreements with Malaysia, as well as granted conditional approvals to projects in Indonesia.

But Singapore needs to have its own domestic sources of clean power, said Wong.

Singapore has been evaluating the use of low-carbon hydrogen for power, "but there are inherent challenges in the production, storage and transportation of hydrogen, which make it hard to scale up in a commercially viable manner," Wong added.

Nuclear power could be another option. Singapore had considered the possibility of developing nuclear power in 2010, but assessed that conventional nuclear technologies were not suitable. Since then, there have been significant advancements in nuclear technologies such as small modular reactors (SMRs), which have better safety features than conventional reactors, said Wong.

Interest in nuclear energy is also rising in the region, with several countries planning to include it in their energy mixes, such as Indonesia and the Philippines. Singapore has signed agreements with the US on civil nuclear co-operation, and is working on similar collaborations with other countries that have capabilities and experience, especially with SMRs, said Wong.

Singapore submitted its new emissions reduction target on 10 February, aiming to reduce emissions to 45mn-50mn of CO2 equivalent (CO2e) in 2035 as part of its nationally determined contribution.

Singapore aims to decarbonise its transport sector, which currently accounts for about 15pc of total emissions, in line with its emissions reduction goals. Singapore will introduce a new heavy vehicle zero emission scheme and a heavy electric vehicle (EV) charger grant to accelerate the adoption of cleaner heavy vehicles. The grant will provide incentives for the purchase of heavy EVs and co-funding of charging infrastructure, said Wong.


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13/03/25

Lower Rio Tinto Al output cuts New Zealand power demand

Lower Rio Tinto Al output cuts New Zealand power demand

Sydney, 13 March (Argus) — New Zealand's industrial electricity demand fell on the year in October-December 2024, after Rio Tinto cut production at its Tiwai Point aluminium smelter in the previous quarter. The country's industrial electricity demand was down by 9pc compared with a year earlier, data from the Ministry of Business, Innovation, and Employment show ( see table ). Rio Tinto cut production at Tiwai Point in late-July 2024, after New Zealand utility Meridian Energy requested that it reduce its energy use by 205 MW. Many of the plant's potlines remained off line until late-September 2024, when Rio Tinto began restarting production at a reduced level. The Tiwai Point Aluminium Smelter is New Zealand's largest industrial energy user, consuming 572MW of power, often accounting for 12-13pc of national electricity demand, according to New Zealand's Electricity Authority. But it only accounted for about 10pc of total demand in October-December because of its lower production level. Rio Tinto's decreased power use and the country's rising geothermal generation in October-December pushed New Zealand's coal- and gas-fired generation to their lowest levels since late-2022. Utilities produced 2.1PJ from coal- and gas-fired generation, down by 73pc on the quarter and by 42pc on the year ( see table ). Coal- and gas-fired plants accounted for just 6pc of total generation in the fourth quarter of 2024, down from 19pc in July-September and 10pc a year earlier. Meanwhile, New Zealand's renewable power generation grew in importance over October-December, even as the government continued taking steps to promote coal- and gas-fired generation. The share of renewable electricity rose to 94.3pc, the highest level since December 2022 and the fourth highest on record. The New Zealand government is eager to promote oil, gas and petroleum generation, resources minister Shane Jones told Argus in December 2024. New Zealand's government has rolled back a ban on offshore gas exploration and has been fast-tracking coal developments since taking office in 2023. The country's largest utility, Meridian Energy, also warned of a structural gas shortage in late February, calling for new gas exploration. By Avinash Govind New Zealand Energy Quarterly Oct-Dec '24 Jul-Sep '24 Oct-Dec '23 q-o-q ± % y-o-y ± % Electricity Consumption (PJ) Industrial 11.0 10.1 12.1 8.7 -9.0 Total 33.7 38.1 35.2 -11.4 -4.3 Electricity Production (PJ) Coal 0.5 3.2 1.3 -84.9 -64.2 Gas 1.7 4.6 2.4 -63.8 -29.8 Geothermal 7.6 8.5 7.1 -10.9 6.6 Total 37.7 41.5 38.2 -9.3 -1.4 Source: Ministry of Business, Innovation, and Employment (MBIE) Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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H2 sector wary as EU nears low-carbon rules: Correction


12/03/25
News
12/03/25

H2 sector wary as EU nears low-carbon rules: Correction

Corrects paragraph 7 to clarify that Hydrogen Europe's requests refer to CO2 intensity of upstream natural gas supply rather than fugitive methane emissions London, 12 March (Argus) — As the European Commission edges closer to publishing its long-awaited low-carbon hydrogen regulation expected this month, there is much at stake for prospective producers within the bloc but also potential overseas suppliers, according to industry association Hydrogen Europe. The European Commission said in its Clean Industrial Deal from late February that it intends to adopt a delegated act defining low-carbon hydrogen this quarter , following publication of a draft last summer and subsequent consultation with stakeholders. The EU has already set a CO2 emissions threshold of 3.38kg of CO2 equivalent for low-carbon hydrogen, but the delegated act will settle the details for a range of production pathways that do not fall under the EU's already-adopted definition of renewable fuels of non-biological origin (RFNBOs). These include electrolysis from non-renewable power such as nuclear or waste incineration, gas reforming with carbon capture, and methane pyrolysis. Hydrogen Europe is hoping that the adopted text — which would then require approval from the European Parliament and member states — will entail some changes it says are key to unlocking nuclear-powered hydrogen and to ensure a fair reflection of emissions from gas-based production. The association has urged the commission to allow companies buying nuclear power via power purchase agreements to factor this into their emissions calculations rather than having to use a default number that stems from the CO2 intensity of the respective country's grid. This is the only way that grid-connected projects could move ahead in countries with low renewables penetration and otherwise large swathes of production could potentially be ruled out, industry participants have said. The industry body has also stressed that the EU should let gas-based hydrogen producers use project-specific figures for the CO2 intensity of their upstream natural gas supply rather than a blanket number irrespective of the location. Project-specific figures will be used for upstream methane emissions from 2028 under a separate methane regulation, which could potentially advantage Norwegian producers with typically lower upstream emissions over producers in the Middle East and parts of the US. Hydrogen Europe's chief executive Jorgo Chatzimarkakis said the sector "desperately needs legal certainty" and complained that missing deadlines has "become standard rather than an exception" for the commission. Other industry participants have previously made similar arguments around emissions calculations for nuclear power and for upstream methane emissions and many have stressed the need for certainty around the definition. The rules are crucial because low-carbon hydrogen will be needed "in the market ramp-up phase" as "renewable hydrogen is not yet available in sufficient quantities or at sufficiently affordable prices," Chatzimarkakis said. Moreover, many renewable hydrogen projects will probably have to pivot their electrolysers to make low-carbon hydrogen in spare hours to shore up their business case. Curbing low-carbon hydrogen volumes with tight rules inadvertently weakens the case for investment in midstream infrastructure that is essential in the long term, Chatzimarkakis said. This debate on measuring the emissions of hydrogen production is the latest in a slew of painstaking procedures globally, as rule makers have tried to enshrine best practices without overly regulating the nascent industry. The EU took around two years to define renewable hydrogen and the process was hardly quicker in the US. The previous US administration of president Joe Biden clarified rules for its 45V hydrogen production tax credits in early January. It listened to pleas from producers and will allow them to use project-specific emissions calculations that might give the EU food for thought — although the future of the clean energy incentives including 45V is unclear following the return of Donald Trump to the White House in January . By Aidan Lea Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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EU consults on decarbonisation, clean tech aid


11/03/25
News
11/03/25

EU consults on decarbonisation, clean tech aid

Brussels, 11 March (Argus) — The European Commission has opened a consultation on updates to its state aid rules, which aim to take into account the bloc's proposed clean industrial deal — designed to simplify and speed decarbonisation. The commission is aiming to publish the rules in June, following input from EU states. The updated state aid rules would then apply to how the commission decides on EU states' financing of projects up until the end of 2030. The draft provides for member states' simplified tender procedures for renewables and energy storage. The commission specifically notes the possibility of granting aid without tender for less mature technologies, such as renewable hydrogen. There would also be more flexibility for EU states aiding industrial decarbonisation, with a choice of tender-based schemes, direct support and new limits for very large projects. The commission lists batteries, solar panels, wind turbines, heat-pumps, electrolysers and carbon capture usage and storage among clean technologies that can be supported, as well as their key components and critical raw materials. Officials note the possibility of EU countries de-risking private investment. The rules, when adopted, would also allow for investment in storage for renewable fuels of non-biological origin (RFNBOs), biofuels, bioliquids, biogas, biomethane, and biomass fuels as long as they obtain at least 75pc of their content from a directly connected and related production facility. Aid can only be granted for biofuels, biogas, and biomass fuel production if compliant with the bloc's renewables directive. While the rules for biofuels are not new, they do reflect the wider scope of aid now foreseen by the commission. And officials say the rules allow for projects in the EU to receive aid from a member state if a comparably project would receive aid in a third country. The commission released its proposed clean industrial deal in late February . The deal targets a simplification of rules, to allow EU member states to aid industrial decarbonisation, renewables rollout, clean tech manufacturing and de-risking private investments. Today's consultation runs until 25 April. By Dafydd ab Iago Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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Italian Bess necessary to reduce gas burn: Industry


11/03/25
News
11/03/25

Italian Bess necessary to reduce gas burn: Industry

London, 11 March (Argus) — As renewables become more prevalent in the Italian power mix, market participants support the buildout of battery energy storage systems (Bess) to replace gas-fired generation as a source of flexibility, Argus heard on the sidelines of the KEY25 Energy Transition Expo in Rimini last week. Italy has some of the highest electricity prices in Europe owing to the country's heavy reliance on gas-fired generation, with the single national price (Pun) averaging €107.75/MWh over 2024. While there has been a decrease in gas burn and an increase in renewables output since 2022, gas-fired generation still accounted for slightly over 40pc of the power mix on average last year, compared with combined solar and wind generation at 21pc. The Italian government has set ambitious renewable targets under the country's national energy and climate plan, aiming to reach 131.3GW — including solar, wind and hydro capacity — by 2030 from 77GW in January under Italy's climate and energy plan. There is general agreement among market participants that reducing gas burn in favour of renewable energy sources will lower electricity prices, but some gas-fired capacity may never be removed from the Italian power mix without having another technology that can provide the same flexibility at scale. Residual demand in Italy is falling, but thermal output remains essential to cover demand peaks during critical summer and winter periods, according to Italian transmission system operator (TSO) Terna's latest system adequacy report . But as renewables cover an increasing share of electricity demand — estimated to reach 335TWh in 2028 — thermal plants will become less economically viable and are likely to be decommissioned unless they are kept operating through ancillary services. "The more renewable generation we have, the less gas-fired plants will have to cover residual electricity demand. Only the most efficient — hence the cheapest — gas-fired plants will be accepted, and the others will be decommissioned," a power trader told Argus . But turning on a gas-fired plant from cold and with a stop-start operation would lead to exaggerated costs and higher maintenance prices. "Morning and evening prices could be used to cover the maintenance of the plant, and the average price would risk being the same but with very marked price differences," the head of power origination of an Italian utility told Argus . "This would lead to investing a lot in batteries that could exploit the spreads and lower them a bit," he added. Market participants attending the conference widely agreed that growing renewable capacity means there is a need to focus on the development of Bess, especially those with 6-8 hours duration to enable time shifting. Solar photovoltaic capacity is expected to grow by 6-8 GW/yr to 2030, according to industry body Italia Solare president Paolo Viscontini. The Italian energy ministry has recently accepted Terna's view that the country will need an additional 10GWh of Bess capacity by 2028 to avoid the risk of the grid becoming congested in periods of overgeneration. As of January 2025, Italy had 13.3GWh of Bess capacity — mainly in the south of the country and on the islands — and is expected to reach 50GWh by 2030. And Terna last week said it will hold its first auction for large-scale Bess with 2028 delivery on 30 September, for which it has already approved 9GWh, as reported by the operator's grid development manager Francesco Del Pizzo. Connection requests for Bess projects more than tripled in 2024 to 253GW worth of capacity, mainly because of a significant reduction in capital expenditure for the assets, which has dropped by around 40pc since 2022 and is expected to stabilise at a competitive price in the next few years. By Ilenia Reale Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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Ontario adds fee for electricity exports to US: Update


10/03/25
News
10/03/25

Ontario adds fee for electricity exports to US: Update

Updates with comments from US utilities Calgary, 10 March (Argus) — Ontario is imposing a 25pc tariff on electricity exports to the US starting today, carrying through on its threatened retaliation for a trade war started by US president Donald Trump. "We will apply maximum pressure to maximize our leverage, that's why today we're moving forward with a 25pc surcharge on electricity exports for the 1.5mn American homes and business that Ontario powers," Ontario premier Doug Ford said today in Toronto. Ontario was the largest exporter of electricity to the US in 2023, sending 15.2 TWh to New York, Michigan and Minnesota. The neighbouring province of Quebec, which exported 13.4 TWh the same year to New York and New England, has said it is also considering its options amid the trade war. Ford said he feels "terrible" because average consumers will pay when it is really Trump who is responsible. The surcharge will cost the US up to $400,000/d, amounting to an increase of $100 for consumers each month, according to Ford. "I will not hesitate to increase this charge," said Ford. "If necessary, if the United States escalates, I will not hesitate to shut the electricity off completely." Trump on 4 March imposed a 10pc tax on Canadian energy imports, a 25pc tariff on non-energy imports from Canada and a 25pc tariff on all imports from Mexico. But executive orders that he signed on 6 March exempted North American trade covered by the US-Mexico-Canada (USMCA) free trade agreement from new tariffs after 12:01am eastern time on 7 March. Trump has said he is delaying the tariffs on Canada and Mexico until 2 April, but his executive orders make no mention of that restart date. Minnesota Power, a subsidiary of Allete, imports "a small portion" of its electricity from Ontario but expects the impact to be "negligible", the utility said. Minnesota Power receives 11pc of its of its energy supply from Manitoba Hydro, but Manitoba has not followed Ontario's lead and imposed a surcharge. Michigan's largest utility, Consumers Energy — which serves 6.8mn of the state's 10mn residents — does not purchase power from Ontario. Xcel Energy, which serves customers in Minnesota and Michigan, also said it did not buy power from Ontario. By Brett Holmes and Anna Harmon Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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