S Korea to convert half of existing coal fleet to gas
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.
Related news posts
Indonesia's coal exports edge higher in April
Indonesia's coal exports edge higher in April
Singapore, 1 July (Argus) — Indonesia's coal exports in April edged higher from a year earlier, led by a growth in shipments to India and southeast Asia. The country exported 44.54mn t of coal in April, up by 2.2pc from a year earlier, customs data show. But the exports fell from 46.1mn t in March . The data includes all types of coal such as thermal as well as coking coal. Indonesia exported about 175.58mn t of coal in January-April, up from 168.5mn t during the same period a year earlier. The country could export a total of 526.68mn t this year at the current pace of 43.89mn t/month, up from 521.1mn t a year earlier, according to Argus calculations based on the customs data. The year-on-year increase in April exports was mainly supported by a rise in demand from India, the world's second-largest coal importer, as utilities there looked to bulk up purchases to replenish stocks for the summer season. Shipments to India in April rose by 8.5pc on the year and by 4.8pc on the month to 11.03mn t, according to the data. The exports were supported by strong demand from utilities with an increase in coal-fired generation. India's overall coal-fired generation — which meets most of the country's power requirements — rose to 116.5TWh in April, up from 106TWh a year earlier, according to data from the country's Central Electricity Authority. April's coal-fired generation was also higher than March's 112.5TWh because heatwaves led to increased air-conditioning use. Indonesian exports also rose to cater for increased demand from southeast Asia. Exports to the region in April rose by 36pc on the year and by 21pc from March to 11.03mn t. This was led by a steady rise in exports to Vietnam, where shipments more than doubled to 2.86mn t from 1.35mn t a year earlier and 2.03mn t in March. The demand was led by utilities as coal-fired generation rose to around 16.5TWh in April, up from an estimated 11.89TWh a year earlier, to cater for an increase in power demand during the dry season. Vietnamese coal imports reached 6.5mn t in May , up from 4.97mn t a year earlier, and from 5.9mn t in April, provisional customs data show. Shipments to China — the world's largest coal importer — accounted for nearly 35pc of Indonesian exports at 15.57mn t, down from 18.5mn t a year earlier and 19.26mn t in March. The drop came as Chinese utilities slowed down purchases of seaborne cargoes in line with the softness in thermal power generation. China's thermal power generation, which mainly uses coal, fell to 454TWh in May from 471TWh a year earlier and 459TWh in April, according to the latest data from the National Bureau of Statistics. China's imports of thermal coal — including non-coking bituminous coal, sub-bituminous coal, and lignite — totalled 32.7mn t, down from 31.4mn t a year earlier and from 32.9mn t in May, Chinese customs data show. Output rises A rise in Indonesian coal production supported higher exports in January-April. Output during the period rose to 266.1mn t, up by 9.2pc from a year earlier, according to data from the country's energy ministry (ESDM). But the output in May and June is estimated to have slipped, taking the year-to-date tally to about 371mn t, down by 2.5pc from a year earlier. The data will likely be revised, as output is frequently reviewed in Indonesia because of a lag in some producers' reporting. Indonesian output could face pressure from heavy rains in parts of key coal-producing Kalimantan region, while production cutbacks could also affect overall production. Some coal producers could trim output in response to ongoing prices in the international market. Argus assessed Indonesian GAR 4,200 kcal/kg coal at $52.86/t fob Kalimantan on 28 June, down by 6.4pc from $57.50/t on 8 March, the highest level for 2024. It is also sharply down from a 2023 peak of $90.41/t in January last year. Weaker output could dent the export trajectory, but coal exports in May are estimated at 44.12mn t, according to data from trade analytics firm Kpler, up from 41.47mn t a year earlier. By Saurabh Chaturvedi Indonesian coal exports (mn t) Indonesia Jan-Apr coal exports by destination (mn t) Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
Fire shuts Anglo American’s Australian coking coal mine
Fire shuts Anglo American’s Australian coking coal mine
Sydney, 1 July (Argus) — UK-South African mining firm Anglo American has closed its 5mn t/yr Grosvenor coking coal mine in the Bowen basin region of Australia's Queensland, after a fire broke out underground. The methane gas ignition occurred on 29 June and it is likely to take several months before the mine can restart given the damage underground, according to Anglo American. Independent regulator Resources, Safety and Health Queensland said it was assisting the firm to safely seal the mine on 1 July. Grosvenor was expected to deliver 1.2mn t of coal in July-December, down from 2.3mn t in January-June, because of a planned longwall move in the second half of 2024. Anglo American's steelmaking coal business was budgeted to produce 15mn-17mn t of coking coal in 2024 and the firm will update this guidance as more information becomes available. Anglo American is looking to exit its coal mining operations in Australia , after rejecting a takeover offer from Australian mining firm BHP. It has struggled to manage the build-up of methane from its Queensland mines over the past few years. Operations at Australia's Moranbah North mine was closed from March-May 2022, after a fatal accident raised safety concerns. The producer also stalled operations at the Grosvenor mine in May 2020 because of gas ignition issues. Argus assessed the premium hard low-volatile coking coal price at $234/t fob Australia on 28 June, down from a year-to-date high of $336.25/t on 12 January. By Jo Clarke Australian metallurgical coal prices ($/t) Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
US Supreme Court ends 'deference' to regulators
US Supreme Court ends 'deference' to regulators
Washington, 28 June (Argus) — The US Supreme Court's conservative majority, in one of its most significant rulings in years, has thrown out a landmark, 40-year-old precedent under which courts have offered federal agencies significant leeway in deciding how to regulate the energy sector and other industries. In a 6-3 ruling that marks a major blow to President Joe Biden's administration, the court's conservatives overturned its 1984 ruling Chevron v. NRDC that for decades has served as a cornerstone for how judges should review the legality of federal regulations when a statute is not clear. But chief justice John Roberts, writing for the majority, said experience has shown the precedent is "unworkable" and became an "impediment, rather than an aid" for courts to analyze what a specific law requires. "All that remains of Chevron is a decaying husk with bold pretensions," the opinion said. For decades, under what is now known as Chevron deference, courts were first required to review if a law was clear and if not, to defer to an agency's interpretation so long as the government's reading was reasonable. But the court's majority said the landmark precedent has become a source of unpredictability, allowing any ambiguity in a law to be a "license authorizing an agency to change positions as much as it likes." Roberts wrote that the federal courts can no longer defer to an agency's interpretation "simply because" a law is ambiguous. "Chevron is overruled," Roberts writes. "Courts must exercise their independent judgment in deciding whether an agency has acted within its statutory authority." The court's ruling, named Loper Bright Enterprises v. Gina Raimando, focuses on lawsuits from herring fishers who opposed a rule that could require them to pay about $710 per day for an at-sea observer to verify compliance with regional catch limits. The US Commerce Department said it believes it interpreted the law correctly, but the fishers said the "best interpretation" of the statute was that it did not apply to herring fishers. The court's three liberal justices dissented from the ruling, which they said will likely result in "large-scale disruptions" by putting federal judges in the position of having to rule on the merits of a variety of scientific and technical judgments, without the benefit of expertise that regulators have developed over the course of decades. Overturning Chevron will put courts "at the apex" of policy decisions on every conceivable topic, including climate change, health care, finance, transportation, artificial intelligence and other issues where courts lack specific expertise, judge Elena Kagan wrote. "In every sphere of current or future federal regulations, expect courts from now on to play a commanding role," Kagan wrote. The Supreme Court for years has been chipping away at the importance of Chevron deference, such as a 2022 ruling where it created the "major questions doctrine" to invalidate a greenhouse gas emission rule limits for power plants. That doctrine attempts to prohibit agencies from resolving issues that have "vast economic and political significance" without clear direction from the US Congress. That has led regulators to be hesitant in relying on Chevron to defend their regulations in court. The Supreme Court last cited the precedent in 2016. The ruling comes a day after the Supreme Court's conservatives, in another 6-3 ruling , dramatically curtailed the ability of the US Securities and Exchange Commission — and likely many other federal agencies — to use in-house tribunals to impose civil penalties. The court ruled those enforcement cases instead need to be filed as jury trials. That change is expected to curtail enforcement of securities fraud, since court cases are more resource-intensive. By Chris Knight Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
Q&A: Corporate reporting and certification schemes
Q&A: Corporate reporting and certification schemes
London, 28 June (Argus) — Corporate reporting standards and obligations are becoming more granular and falling under greater scrutiny across the EU, after new rules came into force at the start of 2024. Argus spoke to net zero adviser Nils Holta at environmental solutions provider Ecohz to review changes to EU legislation and consider their impact on wholesale energy attribute certificates markets. Edited highlights follow: Let's start by decoding the acronyms and taking stock of changes to reporting standards this year. What do the principles of the CSRD and ESRS look like? How do these align with the EU Taxonomy? These are all thematically related pieces of legislation, that are not formally linked to each other. The Corporate Sustainability Reporting Directive (CSRD) and the EU Sustainable Investment Taxonomy are two of the angles of a sustainability transparency triangle completed by the Green Claims Directive (GCD). Through these policy mechanisms, the EU seeks to cover sustainability reporting, sustainability criteria for investments, and marketing information to consumers. Essentially, the EU is trying to add sustainability as a new dimension of the single market, alongside standardised comparisons on quality and price. The CSRD relates more to the finance side. Through the annex with the European Sustainability Reporting Standards (ESRS), it details how companies should report on their sustainability impact, their sustainability-related risks, and any financial opportunities that arrive as a result of sustainability matters. It has been developed as an addition to European financial disclosure requirements, and in Norway, for instance, it has been transposed through amendments to the "accounting law" (Regnskapsloven). For financial undertakings, the Sustainable Finance Disclosure Regulation (SFDR) plays much the same role, albeit at a higher level of granularity. On the consumer-facing side, companies will soon be required to adhere to the GCD when promoting their products' environmental profiles to final consumers in what the EU calls "explicit environmental claims". While not quite the same as sustainability reporting, it fits in a market dynamic where the EU expects economic actors to be more transparent about the environmental qualities of their products — like we are used to for price and quality. Finally, we have the EU Taxonomy for sustainable activities, or just the Taxonomy. The Taxonomy is a list of economic activities with clear criteria on how they can be performed sustainably, and, in some cases, how they can be considered a transitional activity to more sustainable options. The Taxonomy also mandates that large undertakings and financial actors disclose the percentage of their Capex [capital expenditure], Opex [operating expenditure], and turnover that is invested in, finances, or derives from activities that are considered sustainable under the Taxonomy. Here is the link to the CSRD (ESRS), GCD and SFDR. If you are required to report on the percentage of your investments or turnover that is associated with sustainable activities, you need to know how all the companies you invest in are performing. And through the CSRD they are required to share this information in a transparent and streamlined manner. If, as a company, you want to make a claim about a product's environmental profile, you are now also required to possess and sort the information necessary to found that claim through the same directive. So here we have the triangle — the Taxonomy and SFDR push investors towards sustainable investments. The GCD provides consumers with a choice to consume sustainably, and the CSRD and ESRS ensure that companies have the information necessary for the other two to work. So the EU wants you to base Taxonomy reporting or environmental claims on the information published in your CSRD reporting? Not quite. I should stress at this point that EU law does not require companies to use the same methodologies for their CSRD reporting as for explicit environmental claims under the GCD or for showing criteria alignment with the Taxonomy. The simple reason is that communication to different audiences — shareholders, financial sector institutions, consumers — might require different approaches. It is, however, very simple to base claims under the Taxonomy or GCD on information gathered for CSRD reporting, and I have seen companies rely on CSRD reporting for claims of Taxonomy-alignment in their annual reports. How are things changing within the CSRD in terms of how industrial and corporate (I&C) companies will need to document energy — power and gas — consumption throughout their supply chains? What does it mean in terms of scope 2 and 3 emissions? This is a good place to clarify terminology. The CSRD is an EU directive that mandates sustainability reporting, sets out how member states are responsible for making sure companies report, and details which categories of companies need to report. All in all, we are taking about at least 50,000 EU-based companies and maybe another 10,000 non-EU companies with operations in the EU, as a rough assessment. The ESRS are the technical standards, outlining — over some 300 pages — how companies can assess what information they need to report and how this can be reported. The ESRS go into detail regarding how questions about energy consumption and climate transition plans or supply chains are asked and framed. Thank you for the clarification, and now back to the market-based vs location-based reporting? In general, the ESRS move towards market-based reporting. Emissions are to be reported by scope — 1, 2 and 3 — separately and using both market-based and location-based methodologies for Scope 2. They are also to be reported against total turnover, so investors can see the greenhouse gas intensity of their investments' turnover. At the same time, the ESRS clearly state that energy consumption must be reported using the market-based methodology in the case of Scope 2, and that it "can" be market-based in Scope 1, which for most companies would primarily relate to gas. The latter is highly technical and is tied to the EU emissions trading system monitoring and reporting requirements. Disclosing companies must report Scope 3 as it was reported to them. There is no option to not report on Scope 3 emissions outside of Europe, which means that these 60,000 or so companies will push their own reporting requirements through their entire value chain. It also means that oil and gas companies will finally need to include emissions from combustion of their own products in their sustainability reporting. Considering that changes to the CSRD will lead to greater focus on Scope 3 emissions, how is this likely to impact the energy attribute certificates (EAC) markets? Are you already seeing changing approaches to EAC procurement? How do biomethane and hydrogen fit into the picture, and is there a role for carbon offsets? What we are seeing is a greater corporate interest in understanding their own value chain and getting their suppliers to cover Scope 2 consumption with EACs. They can even use the divergence between location and market-based reporting to stress how much they actually achieve by sourcing renewable energy. The result is quite literally the difference between the two numbers. The ESRS do not open for carbon offsets as a way of reducing total emissions. Any offsets must be reported separately. Biomethane and hydrogen would both serve to decarbonise your gas combustion, so mainly Scope 1. However, the requirements for credible claims to consumption are tied to a bundled model, so we expect less focus on certificate trade and more focus on efficient value chains to deliver the product as a whole. There are a lot of open questions here tied to member state transposition of the Renewable Energy Directive (RED) III — and in some cases RED II — and to the coming Union Database for renewable fuels. How will the GCD impact consumer disclosure requirements and how does it tangentially relate to the Taxonomy? Do you expect this to also drive more granular purchases in EAC markets? When procuring EACs, will additional specifications such as eco labels become more prominent in the market? There is no specific link between the GCD and the Taxonomy, but Taxonomy-alignment would definitely be one of the things that can be communicated and substantiated in a way that is aligned with the GCD. Using an eco-label is a way to distinguish your product among several who all use renewable electricity. However, it is difficult to assess exactly how companies and consumers will react to this information in the long term. In the near future, we expect the GCD to lead to a reduction in environmental performance claims overall, at least until companies have a decent understanding of what and how they should communicate. The fine is up to 10pc of total turnover. There are often questions around how nuclear power is viewed in the EU Taxonomy — can you clarify that? And how do you see nuclear power — through scope 2/3 — playing a role in I&C companies documenting carbon neutrality through disclosure mechanisms? There has been a growing trend of energy suppliers offering carbon-neutral tariffs as opposed to renewable owing to the greater cost of documenting renewables through EACs, on top of already higher outright power and gas prices. Do you see I&C customers taking a similar route? Under the Taxonomy, nuclear is not considered renewable. It is, however, acknowledged as carbon-neutral, and we see several EU initiatives targeted at promoting "low-carbon" rather than renewable solutions. There is also an addendum to the Taxonomy, where nuclear and gas-fired power plants can be considered Taxonomy-aligned under certain circumstances. For gas, this relates to replacing coal and being time-limited in nature; while for nuclear, it is tied to a series of environmental and waste-treatment requirements. As long as the market recognises a qualitative difference between renewable and nuclear, EACs for each will be priced differently. Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
Business intelligence reports
Get concise, trustworthy and unbiased analysis of the latest trends and developments in oil and energy markets. These reports are specially created for decision makers who don’t have time to track markets day-by-day, minute-by-minute.
Learn more