South Korea advances Uljin nuclear-hydrogen hub plans

Market: Electricity, Hydrogen
12/01/26

South Korea has moved closer to establishing a nuclear-powered hydrogen production base, with state-owned Korea Land and Housing Corp (LH) and Gyeongsangbuk-do Development Corp (GDC) submitting approval applications for the Uljin Nuclear Hydrogen National Industrial Complex.

The 1.45mn m² site in Hujeong, North Gyeongsang province, will produce nuclear-derived "pink" hydrogen. The electrolysers will use heat and surplus electricity from 10 nuclear reactors in the Uljin area. The developers did not reveal the project's production capacity.

LH and GDC will invest 410.7bn won ($312mn) in the project, with LH holding a 60pc stake and GDC 40pc. The national and provincial governments will spend W20bn each through 2028 to build hydrogen infrastructure, including refuelling stations.

The developers' submissions show construction starting in March 2028 and completion targeted for June 2033. About 73pc of the manufacturing area — 474,000m² — will be dedicated to electrolysis facilities.

Six major firms including GS E&C, GS Energy, Lotte Chemical, Samsung E&A, Hyosung Heavy Industries and BHI, have signed agreements to move into the complex.

This project is part of the government's wider vision for the region, with Uljin designated as a "hydrogen city".

The developers' plans suggest the use of industrial heat for electrolysis, indicating that solid oxide electrolysers (SOEC) may be used. SOECs offer higher efficiency than lower temperature electrolysers when coupled with industrial heat.

By Chingis Idrissov

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02/04/26

New furnaces to support Italian steel power demand

London, 2 April (Argus) — Rising steel demand and upcoming furnace expansions within Italy's highly electrified steel sector could increase the country's industrial power consumption. But high energy prices in the wake of the US-Iran conflict may limit sector growth. Italy is the second-largest steel producer in Europe, after Germany. It has the most electrified steel industry in the region, with 90pc of production coming from secondary steel made from scrap processed in electric arc furnaces in 2024, compared with an EU average of 45pc, according to steel association Federacciai. The country had 26 electric arc furnaces with a combined capacity of 23.9mn t/yr at the end of 2025, according to independent research body Global Iron and Steel Tracker ( see capacity graph ). Italy's wholesale power prices are consistently among the highest in Europe and prices have risen further since the onset of the US-Iran conflict, owing to Italy's strong gas marginality. Italy's second and third quarter power contracts were up by 39pc at the end of March compared with the end of February. Italian firms are constructing new electric furnaces that are expected to start operating in the next few years, which could increase steel sector electricity demand. Producer Acciaierie Venete announced a new 100t electric arc furnace in Padova, expected to be operational by this summer and projected to produce 750,000 t/yr of steel. This furnace alone would consume about 500 GWh/yr of power, assuming energy consumption of modern electric arc furnaces is around 670 kWh/t, based on steel output and power demand recorded in 2025. Fellow Italian steel producer Metinvest aims to break ground at a site in Piombino in central Italy by mid-2026. The new mill will have two electric arc furnaces and 2.7mn t/yr of hot-rolling capacity for low-emissions hot-rolled products, with production targeted for 2029. These furnaces would add a further 1.8 TWh/yr of power demand. And steelmaker Acciaierie d'Italia plans to phase out Italy's only coal-fired blast furnaces at its Taranto plant and replace them with electric furnaces. The firm's Taranto facility has operated below full capacity for more than 10 years and was placed under extraordinary administration in February 2024. The Italian government has put the Taranto assets up for tender, requiring any buyer to commit to replacing the furnaces with electric ones, with authorisation for 6mn t/yr. Private equity firm Flacks Group has been selected as the preferred bidder, proposing a plan for 4mn t/yr. The switch to electric furnaces was scheduled for 2027, but doubt has been case over the future of the Taranto site owing to production issues and a court order mandating a shutdown because of health concerns. State of play Italy's steel sector accounted for 42.4pc of total power demand from energy-intensive sectors in 2025, at 13.8TWh. This marks a 3.7pc increase from the previous year, according to transmission system operator Terna ( see sectoral graph ). Italy's crude steel output rose by 3.6pc to 20.7mn t in 2025, Federacciai data show. Steel power demand fell by 10pc on the year in 2022 and was stagnant over 2023-24 but turned to growth in 2025 ( see long-term demand graph ). Monthly power demand has consistently increased year on year since July 2025, driven by increased production in anticipation of higher steel demand in 2026 ( see monthly graph ). Steel sector power demand reached 1.3TWh in February, up by 3.7pc on the year, mirroring a 2.6pc increase in crude steel output to 1.9mn t. EU steel demand is forecast to rise by 1.3pc to around 134mn t in 2026, according to European sector association Eurofer. And the EU plans to cut import quotas for flat steel from 1 July. Italy is a major importer of flat steel so the lower quota could boost domestic production. Energy efficiency in the sector increased over 2015-21, with consumption falling from roughly 800 kWh/t to below 700 kWh/t, data from Federacciai show. But power demand per ton of output has been slowly edging up since 2021. Geopolitical worries The Italian government has taken steps to insulate industry from power price increases, but geopolitical risks continue to influence prices. Italy launched its Energy Release Scheme late last year, offering electricity to energy-intensive users at a fixed price of €65/MWh in exchange for commitments to develop renewable capacity and return equivalent power over 20 years. But high energy costs will continue to weigh on steelmakers this year, Eurofer director-general Axel Eggert said, pointing to the impact of the Middle East war on gas markets after the Dutch TTF benchmark moved above €50/MWh in early March. Italian steel and scrap association Assofermet flagged the conflict as a source of potential additional cost pressures in an already volatile market. "Operating complexity and growing concerns related to the Carbon Border Adjustment Mechanism (CBAM) and the upcoming entry into force of the new safeguard measure are significantly weighing on the market," it said. The rollout of the CBAM — which raises import costs — will be accompanied by a gradual reduction of free allowances under the Emissions Trading System, from which energy intensive industries have long benefited. As free allocations decline, steelmakers will need to buy more allowances, adding further cost burdens. By Ilenia Reale Electric arc furnace capacity by country mn t/yr Sectoral breakdown of industry power demand % Steel power demand, 12-month trailing average TWh/m Power demand vs steel output, monthly Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . 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Carbon - In focus: UK ETS widens discount to EU in Q1

02/04/26

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02/04/26

Carbon - In focus: UK ETS widens discount to EU in Q1

London, 2 April (Argus) — The benchmark front-year contract under the UK emissions trading scheme (ETS) significantly widened its discount to the EU throughout the first quarter of this year, as scant signs of progress on efforts to link the two systems reduced previous optimism of an impending price convergence, and the UK supply-demand balance remained more relaxed than the EU's. The UK ETS front-year contract closed on average around £14.75/t of CO2 equivalent (CO2e) below its EU counterpart in Argus assessments over January-March, having widened from a low of £6.85/t CO2e in mid-January to a high of £25/t CO2e this week. This compares with an average discount of £13.50/t CO2e in the fourth quarter of last year, within a narrower range of £8.80-17.70/t CO2e, and is the widest average discount for any quarter since the first quarter of last year's £21.80/t CO2e. Linkage plans squeeze spread The UK's discount to the EU began to narrow significantly after the UK government said in a statement in March 2025 that it was "actively considering" linking its ETS back to the EU's, a position confirmed by both sides as part of their common understanding agreement concluded between the UK and EU at a summit in May last year. The markets separated in 2021 as part of Brexit, and while the EU-UK trade and co-operation agreement signed as part of that process committed the two sides to giving "serious consideration" to linking the schemes, no meaningful steps towards a link had previously been taken. The news dramatically narrowed the spread between the two markets, with the UK front year's discount to the EU squeezed to an average of £9.90/t CO2e in the second quarter of 2025. A linkage would logically lead to a convergence of UK and EU ETS prices, as the allowances issued under the two schemes would be fungible. Momentum on the issue continued over the remainder of the year and early 2026, as the European Commission set out in July its recommendation for the legal basis for linkage negotiations, approved by member states in November , and the first round of negotiations kicked off in January . But while the EU and UK said that they aimed to complete talks on the linkage before the next UK-EU summit in 2026, no date for the meeting has been set, and updates on negotiations have in recent months been notable by their absence. Recent events have likely pushed ETS linkage down the political agenda, whether on the domestic front — Keir Starmer's position as UK prime minister came under pressure in February — or internationally, most notably as the US-Iran war sparked a renewed energy crisis. EU supply-demand balance tightens Changes to key fundamentals have also tightened the EU ETS supply-demand balance this year in a way that hasn't been seen in the UK ETS, further widening the spread between the markets. Both the maritime and aviation sectors will have to pay for 100pc of their 2026 emissions covered by the EU ETS, after shipping was phased gradually into the system over the previous two years and free allocations for airlines were phased out. Free allocations for industrial sectors covered by the EU's carbon border adjustment mechanism (CBAM) are also scheduled to start decreasing from this year alongside the measure's introduction, and some CBAM-exposed firms have begun purchasing EU ETS allowances to hedge their expected costs. The UK also ended free allocations for aviation under its ETS this year. But the maritime sector will not be included at all until July this year, and then will only apply to domestic voyages until at least 2028. And the UK CBAM does not launch until 2027. The UK ETS authority also opted late last year not to introduce a supply adjustment mechanism to the scheme, which could otherwise have reduced allowance auction volumes if the total number of allowances in circulation surpassed a certain level. Short-term fundamentals diverge The US-Iran war has prompted further divergence between the markets. EU ETS prices rallied in tandem with natural gas prices on the expectation that more coal plants would come on line, increasing the carbon intensity of the bloc's generation mix and therefore compliance demand for allowances. The UK, by contrast, has no operational coal-fired units. This has seen carbon costs even for power generators become consistently cheaper in the UK than the EU for the first time since February last year, despite the UK's additional £18/t CO2e carbon price support (CPS) charge on the sector. The discount of the UK ETS to the EU including the CPS stood at an average of around £3.25/t CO2e in March. UK ETS prices could find some support over the coming weeks from last-minute buying in the run-up to the scheme's annual compliance deadline on 30 April, upward pressure that will not be seen in the EU ETS with its 30 September deadline, which could narrow the spread between the markets in the short term. But participants will otherwise be awaiting more clarity on linkage. And with the Middle East conflict dragging on, the approach of local elections in the UK and the planned EU ETS review in July, plenty of factors could slow completion of the talks. By Victoria Hatherick EU, UK ETS front-year contract £/t CO2e Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.

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Regulators press data centers to cut load, or wait

31/03/26

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31/03/26

Regulators press data centers to cut load, or wait

Houston, 31 March (Argus) — US regulators and grid operators are calling on data centers to cut their power use when the grid is overloaded, saying it is the only way to connect large-load customers as quickly as they are requesting. Officials and industry executives in Houston for an energy conference last week agreed the grid can not be expanded fast enough to meet unprecedented load-growth forecasts if each data center must be served its full allocation of power every hour of the year. But panel discussions and interviews showed a gap between the flexibility regulators say is possible and what data-center operators say they can deliver right now. "Finding a way to manage this demand in a flexible way is how we are going to get through this transition," PJM chief operating officer Stu Bresler said at CERAWeek by S&P Global in Houston, Texas. Without a way to curtail load during tight conditions, large new customers could face wait times stretching over a decade to connect on to the grid, he said. Although data centers request power connections sized for their maximum load, they do not necessarily operate at that level around-the-clock. Meanwhile, the grid only faces severe strain for a few dozen hours a year, usually during extreme weather events, a window that the Electric Power Research Institute (EPRI) says amounts to less than 1pc of the time. Regulators argue that if data centers agreed to reduce their draw during those peak hours for the grid, the system could absorb far more demand without immediate infrastructure expansion. Officials pointed to a study by Duke University showing that if customers in PJM, the nation's largest grid operator, cut load by half a percentage point for roughly two days, 18GW of new load could be absorbed without adding physical infrastructure to the system. Those cuts will not materialize without clear financial incentives, said the conference attendees. One way to incentivize such behavior is to pay large load customers who agree to use less power at the grid's request, the same way generators are compensated for supply, said Federal Energy Regulatory Commission (FERC) commissioner Judy Chang. "We really should focus on the demand side and include large data centers' ability to curtail," said Chang. "We're not quite getting the incentives yet right." Switching off Some artificial intelligence (AI)-training workloads can be paused or rescheduled but that flexibility varies by site and depends on permits, on-site equipment and the type of computing being performed, said Google's global head of data center energy, Amanda Peterson Corio. "There are many flexibility options, but not every data center can respond the same way," she said. AI-focused "compute factories" tend to be more adaptable because training jobs can be paused, while enterprise data-center workloads are far less flexible, said EPRI vice president of strategy David Porter. The group's work includes launching Flex Mosaic, a classification system meant to help utilities and data-center operators define what each site can realistically offer. Large customers who can will respond if markets put a value on reducing load, but the industry still needs clear rules for how much load can be cut and under what price signals, said Peterson Corio. Some data-center operators pushed back against the idea that most facilities can deliver the type of reductions regulators are envisioning. The vast majority of Amazon Work Spaces' (AWS) sites cannot lower their load on demand because the cloud and enterprise workloads they host cannot be interrupted without affecting customers, said AWS vice president Kerry Person. The only practical way AWS and others like it can reduce their draw on the grid is by switching to on-site backup generators, the majority of which burn fossil fuels because battery storage technology has not yet reached the scale of demand. US rules prohibit that approach, however, because environmental permits limit backup generators to emergency use only. "That's a regulatory issue," Person said. For now, most large-scale examples of this behavior remain confined to pilot programs. EPRI's DC Flex initiative is running field demonstrations at operating data centers to test how much load can be reduced without harming performance and whether facilities can provide services such as frequency support. If the industry cannot agree on workable rules for cutting load during peak hours, large users will continue to pursue their own behind-the-meter generation rather than wait years for a grid connection — a shift executives warned would raise costs, lock in more fossil-fuel use and leave the shared power system worse off . By Jasmina Kelemen Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.

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Bulk terminals firm HES prepares for energy transition

31/03/26

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31/03/26

Bulk terminals firm HES prepares for energy transition

Paris, 31 March (Argus) — Bulk terminal company HES International operates 14 facilities in four European countries and anticipates important changes to its operations as the energy transition and hydrogen market evolve. Argus spoke with new energies business development director Otto Waterlander and chief commercial officer for HES Med Terminal Firas Ezzeddine about how an infrastructure player must adapt to serve customers. Edited highlights follow: What does HES do and what is its role in decarbonisation? Ezzeddine: We are an essential and critical part of the logistics value chain for the industrial heart of Europe. Our value proposition is that we are located in deep sea ports in close proximity to industrial zones, meaning that we are well positioned to serve strategic European industries and their logistical needs. Waterlander: We are purely an infrastructure player; we do not normally have a stake or exposure to the commodities that we manage through our terminals. Our customers tend to be carbon-intensive and they all are struggling with the question of decarbonisation. For HES, it is both a necessity and an opportunity. It is a necessity because classic flows of commodities will phase out over time. And an opportunity because of the energy transition... new things are happening, for example, [development of a] CO2 [market]. Today, we are not involved in handling CO2, but it is going to become a commodity in the future. What are the main challenges related to energy transition activities? Ezzeddine: I see challenges in three buckets. The first is timing: there is a bit of a lag between project deployment and when the infrastructure should be ready to facilitate flows. These are generally not well aligned. The second challenge is around financing. We see from both private and public sector a bit of a risk averseness in terms of investing in the infrastructure for the future. The final challenge is regulation regarding both the new flows of commodities and the actual development of infrastructure. Waterlander: There is also a question about what the utilisation of new infrastructure will be like, particularly in the early years. What you see in the industry is that often projects get delayed, either because they are not economic or because their utilisation challenges create an [unfavourable] economic situation. A recent example is the CO2 transport pipelines. They require large volumes to make it economic and those volumes are not there yet. You need to factor in some long periods of underutilisation of the infrastructure. H ow are you addressing this last challenge, for example for CO 2 infrastructure? Waterlander: We believe that the key to unlocking the market is to go smaller and create optionality. For example, with regard to CO2 terminal activities, we are advancing in Wilhelmshaven and Rotterdam. We already have infrastructure there to receive tankers and we have dedicated jetties to handle the unloading or loading of vessels. We just need to adjust them so that we can also move CO2. We believe that we can actually get our terminals economically viable at about 1.5mn or maybe 2mn t/yr of CO2 handling, when most of the projects will look at 10mn t/yr plus. If we could develop a smaller size terminal to begin with and then grow to larger sizes, we can help the market to come to grips with those volumes. And then gradually over time, volumes will move into pipelines as well. Will the CO 2 be liquefied at the HES terminals? Waterlander: There are two models. In one we have pipeline transport of gaseous CO2, then HES will liquefy the CO2 at its site before it goes onto the ships. That is the most efficient way because otherwise each player would have to have their own liquefaction. But before we have the gaseous pipelines, we will see customers installing their CO2 capture facilities, liquefy it on site, load it into rail tankcars or into barges on the Rhine, for example, to Rotterdam. In this case we receive it in liquid form already. We are planning to have CO2 infrastructure in place by 2029. In the first year, that is only for a small volume, but by 2030 it starts to become significant. We will launch an open season for our first two CO2 terminals in the coming weeks and we are aiming to analyse more specific capacity bookings through these. In France's Fos-sur-Mer, you are working with the Gravithy green iron initiative . What additional infrastructure is needed for that? Ezzeddine: We will be managing the inflow of material for them, which is the iron ore, and the export of their hot briquetted iron [HBI] production. What that entails, in essence, is having some cranes and conveyor belt infrastructure from and to their facility. For the iron ore side, it is not different from the infrastructure that we have for other sites. But the HBI requires dedicated infrastructure because of the nature of the product. What we are doing now is designing a conveyor belt network going from our terminal to theirs, which is around 2km away, where we send iron ore and we receive HBI, and we dedicate a specific slot on our terminal land where we have specific storage for them. Does GravitHy need to book capacity in advance to enable the expansions? Ezzeddine: We have a specific planning and demand forecasting system where we input the potential volumes going in and out. When a new client comes in, they add their inflow and outflow requirements to the model. Then we see whether that is feasible or not given the current infrastructure and the land capacity that we have. The client, in this case GravitHy, tells us they have a need for ‘X' million tonnes of throughput in our terminal, and it is up to us to design the optimal inflow and outflow process. We update the model quite frequently so that we have visibility on what is needed by when, especially because some projects require infrastructure that takes years to build. What are HES' plans for e-methanol? Waterlander: We're working on an e-methanol import project where it will be brought from across the Atlantic into Germany. We have a storage site in Germany that is a former refinery and has liquid storage facilities. We still have an element of the refinery operational that provides security of supply today. We're discussing with a partner the construction of a synthetic aviation fuel (e-SAF) facility as well, which they would locate on our premises. What about other hydrogen carriers or hydrogen-based fuels? Waterlander: We're very proactive on following everything in the hydrogen space. We had discussions about liquid hydrogen imports. We are also into advanced project steps on imports of ammonia into Germany and are in project definition for imports of liquid organic hydrogen carriers. For our Wilhelmshaven site, we already have signed a letter of intent with grid infrastructure company OGE to be connected to the hydrogen network. Ammonia in particular is rather expensive because you need crackers. Is HES planning to develop ammonia crackers? Waterlander: It depends, it is still such early days. If we do it, it would not be at our sole risk, that is clear. Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.

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DOE coal-plant orders yield mixed results

30/03/26

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30/03/26

DOE coal-plant orders yield mixed results

Cheyenne, 30 March (Argus) — Only half of the eight US coal-fired power plant units that energy secretary Chris Wright ordered to continue operating this winter actually dispatched appreciable amounts of electricity to the grid. In January, four of the eight coal units the Department of Energy (DOE) ordered to stay open under section 202 (c) of the Federal Power Act had net positive generation, according to power plant operating data recently released by the US Energy Information Administration (EIA). Two other units consumed more power than they dispatched, while another two did not dispatch any generation during the month. Citing an energy emergency, Wright pointed to concerns about grid reliability in ordering the eight coal units and another two units that run on natural gas and oil to stay open instead of retiring as planned in 2025. Wright then extended the emergency orders for these units when the directives expired, pointing to the same concerns. But some politicians and environmental and consumer groups have disputed Wright's claims grid operators faced potential emergencies. Data from the EIA show that two units at the first coal plant DOE ordered to stay open last year — Consumers Energy's JH Campbell plant in Michigan — dispatched power every month following the department's initial order on 23 May 2025. Another unit at the plant had net generation in June-October as well as December but consumed more energy than it dispatched in November 2025 and in January 2026. Unit 17 of NiSource's RM Schahfer plant and unit 2 of Centerpoint Energy's FB Culley plant, both of which were initially issued emergency orders in December and had them extended on 23 March, also generated power in January. But Schahfer unit 18, which also is subject to the order, had net -3,705MWh on generation in January. DOE's recent orders keeping retiring plant units open have required the plant units be available for dispatch when needed. But that did not mean that they had to generate power at other times. With the exceptions of storms in late-January and early February, the weather in the US most of this past winter was relatively mild. Constellation Power said it operated Eddystone units 3 and 4, which run on natural gas and oil and have been subject to DOE orders since 30 May 2025, during hot weather at the end of June and end of July and during winter storm conditions and colder than normal weather 26-29 January. Extending operations at the last minute can be complicated by fuel availability and other factors. Of the two coal units under emergency orders that did not dispatch any power in January according to EIA, Tri-State Generation & Transmission's Craig unit 1 ,was taken out of service in mid-December because of a mechanical failure, while TransAlta's Centralia plant was put in "cold-shutdown" in early December. DOE issued emergency orders to both units at the end of December, shortly before they were scheduled to retire. The agency extended the order for the Craig unit on 30 March and the order for Centralia on 16 March. DOE last year also issued an order allowing Talen Energy to run unit 4 of the HA Wagner oil-fired plant in excess of emissions limits if needed for reliability, but that order expired at the end of 2025. Talen expects to operate Wagner units 3 and 4 until 31 May 2029. By Courtney Schlisserman US coal plants with active emergency orders Plant name Jan 26 net generation ( MWh ) Jan 26 consumption ( st ) Jan 25 net generation ( MWh ) Jan 25 consumption ( st ) JH Campbell unit 1 155,951 89,633 187,955 107,469 JH Campbell unit 2 -612 0 193,811 108,375 JH Campbell unit 3 431,520 245,342 578,398 320,758 Centralia 0 0 430,197 302,227 Craig unit 1 0 0 174,089 100,975 RM Schahfer unit 17 172,064 90,574 98,307 54,965 RM Schahfer unit 18 -3,705 0 136,987 70,368 FB Culley unit 2 9,338 6,092 17,922 10,884 — EIA Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.

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South Korea advances Uljin nuclear-hydrogen hub plans

Related news posts

New furnaces to support Italian steel power demand

New furnaces to support Italian steel power demand

Carbon - In focus: UK ETS widens discount to EU in Q1

Carbon - In focus: UK ETS widens discount to EU in Q1

Regulators press data centers to cut load, or wait

Regulators press data centers to cut load, or wait

Bulk terminals firm HES prepares for energy transition

Bulk terminals firm HES prepares for energy transition

DOE coal-plant orders yield mixed results

DOE coal-plant orders yield mixed results

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