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S Korea to convert half of existing coal fleet to gas

  • Spanish 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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10/07/25

Workers strike at Australian coal mine: Correction

Workers strike at Australian coal mine: Correction

Corrects mine lock-out start date in paragraph 3 Sydney, 10 July (Argus) — Mining and Energy Union (MEU) workers at US producer Peabody Energy's Metropolitan mine in New South Wales are striking over an ongoing pay dispute, halting production until 5pm AEST (7am GMT) on 10 July. MEU launched a five-hour stoppage at 5pm on 9 July, before extending it to 12 hours. The unionised workers launched another 12-hour strike early on 10 July, the union told Argus on the same day. Peabody locked miners out of the mixed thermal, hard coking, and pulverised coal injection (PCI) mine from 18 June until 5:30pm on 9 July, without pay, over an increasingly acrimonious employment negotiation. MEU and Peabody negotiators are at odds over the use of contractors at Metropolitan, among other issues. They met for Fair Work Commission-led mediation during the lock-out on 8 July. Metropolitan Coal remains fully committed to ongoing good faith negotiations with the union, a Peabody spokesperson told Argus on 10 July. The MEU's latest strike comes a day after unionised workers at global producer Glencore's 20mn t/yr Ulan thermal coal mine launched a day-long strike, targeting some underground operations at the complex. The Ulan strike is set to end on 10 July. By Avinash Govind Send comments and request more information at [email protected] Copyright © 2025. Argus Media group . All rights reserved.

US' Peabody extends coal mine lock-out: Correction


10/07/25
10/07/25

US' Peabody extends coal mine lock-out: Correction

Corrects mine lock-out start date in paragraph 3 Sydney, 10 July (Argus) — US coal producer Peabody Energy has extended a lock-out of workers at its Australian Metropolitan mine until late on 9 July, because of a continuing dispute with the Mining and Energy Union (MEU). MEU workers will remain barred from entering the mixed thermal, pulverised coal injection (PCI), and hard coking coal mine — which produced 1.8mn t of coal in 2024 — without pay until 9 July, the union and company confirmed on 7 July. Peabody's lock-out began on 18 June and was scheduled to end on 6 July . The company ended the action early on 3 July, but then reintroduced and extended it late on 4 July because of partial work bans. The MEU can launch an unlimited number of work stoppages and limited work bans at Metropolitan, based on a 7 June strike authorisation. The MEU and Peabody remain at odds over the use of contractors at the mine, among other issues. The two groups are scheduled to engage in a Fair Work Commission (FWC) mediation on 8 July. They have already had two FWC mediations over the dispute, said Peabody's vice-president of underground operations Mike Carter on 7 July. Peabody has also met with employees more than 10 times, he added. Metropolitan Coal remains fully committed to ongoing good faith negotiations with its workers, a Peabody spokesperson said on 7 July. MEU workers will rally outside the site early on 8 July, joined by other labour unions. The labour dispute at Metropolitan follows a series of strikes at Peabody Energy's 12mn t/yr Wilpinjong thermal coal mine in February, over a different contract negotiation. By Avinash Govind Send comments and request more information at [email protected] Copyright © 2025. Argus Media group . All rights reserved.

Japan’s Sumitomo to invest $10bn in UK clean energy


10/07/25
10/07/25

Japan’s Sumitomo to invest $10bn in UK clean energy

Tokyo, 10 July (Argus) — Japanese trading firm Sumitomo has agreed to invest a total of £7.5bn ($10.2bn) by 2035 in key clean energy projects in the UK. The agreement was made with the UK's Department for Business and Trade's Office for Investment on 9 July. The £7.5bn total includes investments Sumitomo made before this deal. The investments will be focused on key offshore wind and hydrogen projects. Sumitomo is also actively exploring the commercialisation of next-generation technologies such as fusion energy and energy management with storage solutions, the firm said. Sumitomo did not disclose more details on what projects it will invest in, when requested for comment. Sumitomo is currently involved in a low-carbon hydrogen production project at the Bacton gas terminal in north Norfolk, CO2 storage in the North Sea and the Peak Cluster CO2 shipping project. The trading house has also invested in offshore wind power businesses. Sumitomo chose to partner with the UK because of the government's support for clean energy businesses, said the firm, and it intends to enhance its collaboration with the UK to develop its clean energy portfolio. By Nanami Oki Send comments and request more information at [email protected] Copyright © 2025. Argus Media group . All rights reserved.

LNG imports feasible, New Zealand utilities say


10/07/25
10/07/25

LNG imports feasible, New Zealand utilities say

Sydney, 10 July (Argus) — Importing LNG to cover New Zealand's shortfall of gas is technically feasible but more challenging than expected, according to two new reports commissioned by five energy companies. Conventional-scale LNG imports would help meet power demand in years when hydroelectric inflows are low, but the total cost to end users is estimated at NZ$170-210mn/yr ($102-126mn/yr) including costs of $10.12-10.37/MMBtu on a landed basis — or approximately NZ$17.83-18.27/GJ, based on a forward exchange rate of NZ$1.67:$1 — according to reports sponsored by New Zealand utilities Clarus, Contact Energy, Genesis Energy, Meridian Energy, and Mercury. Major works to establish infrastructure such as port or pipeline upgrades have been estimated at NZ$190mn-1bn, a level of investment that holds risks given uncertainty about the country's future energy mix and need for imports. Smaller-scale options using existing ports and involving imports from Australia via 15,000m³ vessels could provide an additional 7-10 PJ/yr (187mn-267mn m³/yr) or about one month's supply, but this could cost 25pc more than the large-scale option at about $11.41-11.92/MMBtu, or NZ$20.10-21/GJ . Smaller-scale LNG infrastructure capital costs could be NZ$140mn-295mn, but securing offtake and a solution for storing imported LNG would need to be finalised first, the study said. New Zealand's gas supply has plummeted after years of underinvestment in the Taranaki basin, the country's main source. Just 25.93PJ was produced in January-March, down by 19pc on the year, according to government data. High prices are impacting the production of fertilizers and other industries . Wellington is looking to lure upstream producers via a NZ$200mn co-investment to buy stakes in new gas fields, while also working towards potential LNG import plans . By Tom Major Send comments and request more information at [email protected] Copyright © 2025. Argus Media group . All rights reserved.

Market eyes grid balance as Europe tests granular GOOs


09/07/25
09/07/25

Market eyes grid balance as Europe tests granular GOOs

London, 9 July (Argus) — Irish and Danish electricity suppliers have recently tested the use of granular guarantees of origin (GOOs), matching production and consumption on an hourly basis. But as concerns about grid balance remain among participants in the wider European GOO market, a gradual approach might be key. Software provider Granular Energy this week announced the results of a pilot with Irish suppliers Electric Ireland, Flogas and SSE Airtricity and GOO registry provider Grexel — part of EEX group. This aimed to test a "hybrid system", in which hourly matched GOOs are used alongside less granular certificates. Participating suppliers received hourly GOOs for output from selected renewables assets, and cancelled them on behalf of users for their April 2025 consumption. Granular Energy acted as the issuing body, while Grexel provided a "sandbox version" of the national GOO registry, enabling the coexistence of certificates at different levels of granularity. One of the key findings of the study was that "allowing a phased, opt-in rollout" can help reduce overall data volumes and preserve compatibility with the rest of the Association of Issuing Bodies (AIB) hub, according to Granular Energy. "This kind of optionality creates a clear path for Ireland and EU member states to gradually transition to hourly systems independent of an EU-wide overhaul," Granular Energy co-founder and chief operating officer Bruno Menu said. The pilot follows a late-2024 report by the Sustainable Energy Authority of Ireland that recommended an upgrade of the national GOO system to enhance emissions reporting for "large energy users", such as data centres. Grexel has recently been awarded funds to help interested GOO issuing bodies develop hourly tracking infrastructure. Meanwhile, Danish electricity supplier Reel also recently completed a pilot with Granular Energy and national transmission system operator Energinet, with the results announced at the end of June. As part of this, five Danish companies matched their electricity consumption to GOOs on an hourly, weekly and monthly basis. Wider push The 24/7 Carbon-Free Coalition — part of international non-profit Climate Group — in June released its first technical criteria for companies claiming to use carbon-free electricity (CFE) globally, recommending the use of hourly matching for all claims based on certificates. In addition to that, standard-setting group Greenhouse Gas Protocol has been conducting a review of its reporting standards. Based on initial feedback , the technical group working on scope 2 emissions — covering indirect emissions from purchased energy — is updating inventory rules with greater granularity, with a public consultation to be launched later this year. A fine balance Some GOO market participants are concerned about 24/7 CFE matching creating a new system of incentives that could ignore the needs of the wider electricity network, where consumption and production must be balanced at all times. In a 24/7 CFE system, players could make decisions based on their contracted renewable assets, rather than respond to real-time signals from the grid, independent originator Axel Baudson told Argus . For example, power oversupply "on a beautiful sunny afternoon" — when renewables production is high — could increase if renewables generators are contractually obliged to deliver hourly matched certificates, he explained. For this reason, granular matching should be expanded "with a perspective of dynamic grid balancing", Baudson said. These "suboptimal" scenarios are minimised "once a larger pool of consumers and producers is involved", Granular Energy's Menu told Argus in response, explaining that the ultimate aim is to move from individual corporate strategies for procuring granular GOOs to "a broader optimisation at the country level". This creates price signals and drives better alignment with the needs of the grid, he added. Under the annual disclosure regime — the most common across European countries — consumption can be matched to output at any point during the disclosure year to reach zero emissions. This is often not possible when first moving to hourly disclosure, Menu explained, because of the reality of physical power flows during the day. This, in turn, creates more incentives to decarbonise the wider grid and invest in storage capacity. Annually (mis)matched Even within the current annual system, disclosure rules and certificates' expiry periods differ across European countries . Some national registries allow GOO cancellations for 12 months from the energy production, while others extend this to 18 months. A harmonised framework for annual disclosure should be the priority, several GOO traders told Argus , before gradually adopting more specific timeframes, such as quarterly and monthly. France has the most granular disclosure system in the AIB hub, requiring monthly matching, with certificates typically commanding a premium to Europe-wide contracts. Current-year French GOOs from solar, wind and hydropower traded at an average of €0.93/MWh at the end of June, above average Argus assessments of €0.74/MWh for 2025 European wind and solar and Nordic hydro GOOs. By Giulio Bajona Send comments and request more information at [email protected] Copyright © 2025. Argus Media group . All rights reserved.

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