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S Korea to convert half of existing coal fleet to gas

  • Market: Coal, Electricity
  • 11/05/20

The closure or conversion of ageing South Korean coal-fired power plants could cut power sector consumption by 19mn-28mn t/yr by 2034, although the decline may be slowed in the near term by the start-up of new plants in the next five years.

South Korea plans to shut a total of 15.3GW of coal-fired capacity by 2034, according to a draft of the country's ninth basic electricity plan released on 7 May, of which 12.7GW will be switched to run on LNG. South Korean state-owned Kepco utilities currently operate 33.7GW of coal capacity across 56 units.

Some 30 of those coal units that reach 30 years of service by 2034 will be retired, 24 of which will be converted to run on natural gas, according to the draft. The exact units to be converted were not specified, but are likely to comprise power plants earmarked for conversion by the five individual state-owned utilities.

The existing eighth electricity plan already includes the conversion of the 500MW Dangjin 1 and 2 units to run on gas in 2029, with the 560MW Samcheonpo 3 and 4 units to be retired in March 2023 and the 500MW Taean 1 and 2 units scheduled to close in 2025.

In addition, Korea East-West Power has proposed the conversion of its 500MW Dangjin 3 and 4 in 2030, according to board meeting notes published on its website.

Fellow state-owned utility Korea South East Power (Koen) has proposed converting its 500MW Samcheonpo units 5 and 6 in July 2027 and January 2028, respectively, and its 800MW Youngheung units 1 and 2 in June 2034 and December 2034. Koen's 560MW Samcheonpo units 1 and 2 are already scheduled to retire as part of the eighth plan.

Korea Southern Power (Kospo) plans to convert a total of 3GW of ageing coal capacity across six units in 2026-31. Kospo's meeting notes do not specify the exact units to be converted, but the 500MW Hadong units 1-6 are the oldest in its fleet. Kospo is already scheduled to retire its 250MW Honam units 1 and 2 in January 2021.

Korea Western Power's (Kowepo) 500MW Taean units 3 and 4 have been proposed for conversion to LNG in December 2032 and Korea Midland Power's (Komipo) 500MW Boryeong units 5 and 6 in December 2024 and December 2025, respectively. The 500MW Boryeong units 1 and 2 are scheduled to close in December this year as part of the eighth plan, but Komipo has decided to convert the units to run on LNG in December 2026, according to board meeting minutes.

But despite the swathe of plant retirements and fuel conversions, seven new coal units are currently under construction with a combined capacity of 7.26GW. This means that South Korea's installed coal capacity will likely peak around 2024-25, potentially slowing the decline in coal burn until later this decade.

State-owned utilities consumed 83.3mn t of coal (with an unspecified calorific value) to generate 226.8TWh in 2019, according to Kepco data. This represented a 71pc utilisation rate of the country's state-owned fleet, down from 75pc in 2018. Coal-fired load factors may remain under pressure in the coming years, as the government has pledged to restrict the use of coal plants to improve air quality during the peak winter heating season each year. Increasingly competitive gas prices and rising nuclear and renewable capacity may also stem the use of coal plants.

If the use of South Korea's installed state-owned coal capacity ranges between 60pc and 70pc, annual coal consumption for power could drop to as low as 53mn-62mn t/yr in 2034, according to Argus analysis. But annual power sector demand is set to average around 80mn t/yr in the next five years, assuming a 70pc average load each year, as new capacity additions will outpace retirements in the near term. But the record 89.3mn t of consumption recorded in 2018 may be unlikely to be repeated.

Ninth plan targets renewables growth

The government — recently strengthened by the success of President Moon Jae-in's party in last month's national assembly elections — is targeting a 62.3GW increase in renewable capacity by 2034, in line with a previous target set out in the third energy plan.

This would bring total renewable capacity to around 79GW, which the government expects to represent around 40pc of the country's installed capacity, compared with 15pc now. The ninth plan sees coal, nuclear and gas-fired capacity accounting for 14.9pc, 9.9pc and 31pc, respectively, by 2034.

The increase in renewable generation would offset declines in coal, gas and nuclear generation and cater for growth in overall power demand. The eighth plan targeted a 24 percentage point increase in renewables' share of power generation to 33.7pc by 2030, with coal, gas and nuclear shares falling by around nine, five and seven percentage points. The targets in the ninth plan — to be confirmed in the second half of the year — may now be even tougher on coal.

Change in Korean generation mix 2019-34 GW

South Korean coal burn vs installed capacity mn t, GW

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19/02/25

EU draft plan seeks to cut energy costs

EU draft plan seeks to cut energy costs

Brussels, 19 February (Argus) — The European Commission has set out plans to tackle the cost of energy in the EU, warning in a draft document that Europe risks de-industrialisation because of a growing energy price gap compared to global competitors. High energy prices are undermining "the EU's global standing and international competitiveness", the commission said, in a draft action plan for affordable energy, seen by Argus . The plan is expected to be released next week, alongside a clean industrial deal and other strategy documents. Much of the strategy relies on non-binding recommendations rather than legislation, particularly in energy taxation. Officials cite EU reliance on imported fossil fuels as a main driver of price volatility. And they also highlight network costs and taxation as key factors. For taxation, the commission pledges — non-binding — recommendations that will advise EU states on how to "effectively" lower electricity taxation levels all the way down to "zero" for energy-intensive industries and households. Electricity should be "less taxed" than other energy sources on the bloc's road to decarbonisation, the commission said. It wants to strip non-energy cost components from energy bills. Officials also eye revival of the long-stalled effort to revise the EU's 2003 energy taxation directive. That requires unanimous approval from member states. The commission pledges, for this year, an energy union task force that pushes for a "genuine" energy union with a fully integrated EU energy market. Additional initiatives include an electrification action plan, a roadmap for digitalisation, and a heating and cooling strategy. A white paper will look at deeper electricity market integration in early next year. EU officials promise "guidance" to national governments on removing barriers to consumers switching suppliers and changing contracts, on energy efficiency, and on consumers and communities producing and selling renewable energy. More legislative action will come to decouple retail electricity bills from gas prices and ease restrictions on long-term energy contracts for heavy industries. By 2026, the commission promises guidance on combining power purchase agreements (PPAs) with contracts for difference (CfDs). And officials will push for new rules on forward markets and hedging. There are also plans for a tariff methodology for network charges that could become legally binding. Familiar proposals include fast-tracking energy infrastructure permits, boosting system flexibility via storage and demand response. Legislative overhaul of the EU's energy security framework in 2026 aims to better prepare Europe for supply disruptions, cutting price volatility and levels. Specific figures on expected savings from cutting fossil fuel imports are not given in the draft seen by Argus . But the strategy outlines the expected savings from replacing fossil fuel demand in electricity generation with "clean energy" at 50pc. Improving electrification and energy efficiency will save 30pc and enhancing energy system flexibility will save 20pc, according to the draft. The commission is also exploring long-term supply deals and investments in LNG export terminals to curb prices. 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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Singapore adds $3.7bn clean energy funds, mulls nuclear


19/02/25
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19/02/25

Singapore adds $3.7bn clean energy funds, mulls nuclear

Singapore, 19 February (Argus) — 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. By Prethika Nair Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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Japan approves new energy mix target, climate plans


18/02/25
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18/02/25

Japan approves new energy mix target, climate plans

Tokyo, 18 February (Argus) — Japan has approved its targeted power mix portfolio for the April 2040-March 2041 fiscal year, as well as its new greenhouse gas (GHG) emissions reduction goal, it announced today. The new power mix goal, the centrepiece of the country's Strategic Energy Plan (SEP), is in line with Japan's aim to reduce GHG emissions by 73pc by 2040-41 compared to 2013-14 levels. Tokyo plans to submit the 2040-41 emission target, as well as a 60pc emissions reduction goal for 2035-36, to the UN climate body the UNFCCC on 18 February as the country's nationally determined contribution (NDC). The country has not made major changes to its draft proposal that it unveiled in December. The new SEP sees renewable energy making up 40-50pc of the country's power generation in 2040-41, up from 22.9pc in 2023-24. The share of thermal power will fall to around 30-40pc from 68.6pc, while that of nuclear will increase to around 20pc from 8.5pc during the same period. The 2040-41 target is based on Japanese power demand of 1,100-1,200 TWh, which is higher by 12-22pc from 2023-24. The government has planned the power portfolio so that it is not heavily dependent on one specific power source or fuel type, the country's minister for trade and industry (Meti) Yoji Muto said on 18 February, although the new plan suggests making maximum use of low-carbon power supply sources. Public consultation over 27 December-26 January revealed that some think Japan should slow or even stop the decarbonisation process, given the US government's reversal of its climate policies, including its withdrawal from the Paris climate agreement, said Meti. But global commitment to decarbonisation will remain unchanged, said Muto, adding that Japan will lose its industrial competitiveness if the country delays green transformation efforts. But US president Donald Trump's "drill, baby, drill" policy has prompted the Japanese government to delete a segment from the draft SEP that had initially proposed bilateral co-operation through Tokyo's green transformation strategy and the US' Inflation Reduction Act. Despite Tokyo's decarbonisation goals, the new SEP assumes that fossil fuels, including natural gas, oil and coal, will still account for over 50pc of primary energy demand in 2040-41 in all of its scenarios — although this is down from 93pc in 2013-14 and 83pc in 2022-23. The scenarios vary based on the degree of uptake of renewables, hydrogen and its derivatives, and carbon capture and storage (CCS) technologies, to fulfil the 73pc emission reduction goal by 2040-41. Worst-case scenario Tokyo also has also set out a potential worst-case scenario, assuming slower development of clean technologies, in which fossil fuels would still account for 67pc of primary energy supply in 2040-41. Under this scenario, which assumes Japan will only reduce its GHG emissions by around 61pc by 2040-41, natural gas is estimated to account for about 26pc, or 74mn t, of Japan's primary energy supply, which is higher than the 53mn-61mn t in the base scenarios that are formulated in accordance to the 73pc emissions reduction target. Japan would need to address the potential 21mn t gap in gas demand, which will mostly be met by LNG imports, in 2040-41, depending on the development of clean technologies. The gap is equivalent to 32pc of the country's LNG imports of 65.9mn t in 2024. When asked by Argus whether the government will continue to try securing LNG to ensure energy supply security when considering the worst-case scenario, a Meti official said Tokyo should continue pursuing its 73pc GHG reduction target, but it is necessary to consider the potential risks for each individual policy and the measures that need to be taken, instead of making decisions based on the worst-case scenario. The new SEP has highlighted the role of LNG in the country's energy transition and the necessity to secure long-term supplies of the fuel. It is unclear what ratio gas-fired capacity will account for in Japan's 2040-41 power mix, as the SEP does not include a breakdown of thermal generation. But gas-fed output is expected to take up the majority share, given that gas has already outpaced coal in power generation and Tokyo has pledged to phase out inefficient coal-fired plants by 2030. By Motoko Hasegawa and Yusuke Maekawa Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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India's domestic coal supply to utilities rises in Jan


18/02/25
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18/02/25

India's domestic coal supply to utilities rises in Jan

Singapore, 18 February (Argus) — Domestic thermal coal supplies to Indian utilities rose in January as power plants continued to boost inventories. Combined coal supplies to utilities from domestic sources such as state-controlled Coal India (CIL), Singareni Collieries (SCCL) and captive blocks stood at 76.41mn t, up by 5.8pc from a year earlier, provisional data from India's coal ministry show. Supply was also up from 76.04mn t in December. Indian utilities continued to restock, although coal consumption at utilities was weaker than initially anticipated, as temperatures in most parts of the country were higher last month compared to historical averages, curbing power demand. India's coal-fired generation — which meets most of its power requirements — stood at 109.68TWh during January, down from 111.72TWh a year earlier, but up from 104.30TWh in December, Central Electricity Authority (CEA) data show. Higher domestic coal supplies and weaker coal burn supported stock positions at utilities. Combined coal inventories at Indian power plants stood at around 50.5mn t on 31 January, up from 45.2mn t on 31 December and higher from 38.59mn t as of 31 January 2024, according to CEA data. The inventory as of the end of January would last for over 17 days at the current daily coal consumption rate at utilities. Higher stocks and a steady uptick in domestic supplies might have pressured utility demand for imported coal and India's overall seaborne receipts last month. India imported 11.63mn t of thermal coal last month, down from 13.34mn t a year earlier, according to data from analytics firm Kpler. Imports reached 163mn t in 2024, down from 168.2mn t in 2023, Kpler data show. Indian power sector imports, which account for more than 40pc of the country's overall imports, dropped on the year for the fourth straight month in December , and might have eased in January. Combined thermal coal imports by Indian utilities, excluding captive power plants, stood at 3.25mn t in December, down by 2.17mn t or 49pc from a year earlier, CEA data show. Imports could come under pressure if the government does not extend its directive to imported coal-fired plants, which have a combined capacity of 17.7GW, to boost generation under Section 11 of the Indian electricity law, which also gives some flexibility to such generators to sell excess production in the power market. The directive is due to expire on 28 February. Production, supply mix The increased supplies to utilities were supported by higher overall thermal production. India's coal output rose by 4.4pc in January from a year earlier to 104.49mn t. The country's supplies to all sectors stood at 93.21mn t last month, up by 6.7pc on the year. CIL produced 77.79mn t in January, down from around 78.41mn t a year earlier, while it supplied 69.26mn t, rising from 67.52mn t last year, ministry data show. Of this, 55.01mn t of coal was supplied to the power sector in January, easing from 55.15mn t a year earlier. Meanwhile, output at coal producer SCCL rose by 5pc from a year earlier to 6.97mn t in January. But its overall supplies in January fell by about 1.5pc on the year to 6.12mn t, while dispatches to the power sector rose by 2.2pc on the year to 5.6mn t. Captive coal block producers and other small government mining entities comprised the remainder of the supplies to utilities in January. Output from captive coal blocks and other mining companies rose by over 31pc on the year to 19.72mn t in January, while supplies rose by nearly 30.7pc to 17.83mn t. Data on domestic coal supplies to Indian utilities do not include dispatches to captive power plants set up by industries. Supplies to such captive utilities — from sources such as CIL, SCCL and captive coal blocks — reached 6.29mn t in January, up by almost 9pc from a year earlier. Domestic supplies to steel and cement sector in January rose by 4.5pc and 31pc from a year earlier to 860,000t and 900,000t respectively, the ministry data show. By Saurabh Chaturvedi Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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Philippines to review shutdown of 232MW coal plant


17/02/25
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17/02/25

Philippines to review shutdown of 232MW coal plant

Manila, 17 February (Argus) — The Philippines will review plans to retire the 232MW Mindanao coal-fired power plant in Misamis Oriental province because the rehabilitation of a major regional power complex could cause an electricity supply shortage. The country could put on hold plans to accelerate the retirement of the Mindanao coal plant to 2026 from 2031, the Department of Energy (DoE) said. The plant, majority owned by private-sector Aboitiz Power, started operations in 2006 under a build-operate-transfer (BOT) agreement with the National Power and Power Sector Assets and Liabilities Management. The plant was originally scheduled to be retired in 2031 once the BOT agreement had run its course and plant ownership transferred to the national government, but authorities later decided to shut it down by 2026. The plant consumes over 1mn t/yr of coal. Authorities might review the retirement plans to offset the loss of power supply from the 1,000MW Agus-Pulangi hydropower complex, which will be rehabilitated next year. The complex comprises seven hydropower plants and serves as a key source of baseload power in the Mindanao grid. It is currently capable of producing only 600-700MW of power because of siltation and ageing infrastructure. Parts of the power complex are over 50 years old and its oldest dam, Agus 6, started commercial operations in April 1971. The rehabilitation involves repairing, replacing and upgrading the components of an existing hydroelectric power plant to restore its functionality, improve efficiency and extend its lifespan. The complex will run at a derated capacity during rehabilitation works, which could take several years. This comes as power demand in the Mindanao grid continued to increase last year. Demand averaged 2.248GW in 2024, a 10.2pc increase from 2.040GW a year earlier. The Mindanao plant could supply enough power to keep the grid stable at its full capacity, by covering for the loss in generating capacity and meeting the increase in power demand, DoE added. By Antonio Delos Reyes Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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