Typhoon Higos disrupts south China coal consumption

: Coal
20/08/19

Typhoon Higos made landfall in south China's Guangdong province today, disrupting economic activity and bringing torrential rain that will likely lift hydropower output, potentially curbing coal consumption in the coming days.

Higos is the third typhoon in recent weeks to make landfall in China after Mekkhala and Hagupit. Higos has been moving in a northwest direction since landing in Guangdong and could reach neighbouring Guangxi province later today, according to the country's meteorological administration.

Guangdong is the largest Chinese province by GDP since 1989, achieving 10.5 trillion yuan ($1.52 trillion) in 2019. The province consumed 67.9TWh of power in June, up by 7.6pc from the same month last year, as rising summer temperatures boosted air-conditioning requirements and economic activity started recovering from the impact of Covid-19.

Torrential rain brought by Typhoon Higos will boost hydropower output, which could weigh on coal consumption in parts of south China, where high water levels from weeks of heavy rain during June-July have not completely receded. China's hydropower output reached 146.3TWh in July, 6.1pc higher from a year earlier and a 20.4pc increase from June, according to data from coal industry association the CCTD.

But the impact of rising hydropower output could be partially offset by a temporary reduction in available coal supplies to coastal utilities. A derailment on the Daqin railway on 17 August, which is critical in delivering supplies to the main coal transshipment port of Qinhuangdao in north China, has led to a sharp fall in coal inventories at the port. Qinhuangdao coal stocks were 5.35mn t yesterday, down from 5.91mn t a week earlier. It is unclear when Daqin operations will be restored.

China's domestic coal spot prices held relatively steady yesterday, with bids for NAR 5,500 kcal/kg coal in a range of Yn550-554/t fob north China ports against offers at around Yn556-560/t.

Argus

last assessed this market at Yn554.49/t fob Qinhuangdao on 14 August.

By Kelvin Leong

Related news posts

Argus illuminates the markets by putting a lens on the areas that matter most to you. The market news and commentary we publish reveals vital insights that enable you to make stronger, well-informed decisions. Explore a selection of news stories related to this one.

25/12/23

Viewpoint: Stable 2026 start for US steam coal

Cheyenne, 23 December (Argus) — US thermal coal markets are ending 2025 on a stronger footing than when they started the year, with producers expressing cautious optimism about 2026. Prices for most US thermal coal were at their highest levels since April-May 2023 in September and October. While steam coal prices have slipped in more recent weeks, they remain well-above year-earlier levels. US coal markets began to recover near the end of 2024, in response to a blast of colder-than-expected weather and higher natural gas prices. Coal-fired generation in at least some of the US continued to be above expectations through the third quarter of this year. This unanticipated boost offset lackluster seaborne coal pricing, leading US coal producers to focus their sales on US markets. Some producers expect to continue to favor domestic shipments over international markets in the coming year, given that US customers continue to be willing to pay more than international buyers. "We're still in negotiations for additional business next year," Core Natural Resources chief financial officer Mitesh Thakkar said on 6 November. "We certainly could increase some more volumes and get them exported. But I would say domestic is going to be year-on-year improved." The US Energy Information Administration (EIA) is expecting coal-fired generation to decrease next year largely because of continued power plant retirements. But generation may still be higher than in 2024. Some market fundamentals suggest generators could run remaining coal units at relatively elevated rates during peak demand seasons. Profit margins for running coal units in December, January and the first quarter of 2026 have been running higher than year earlier levels. In some cases, coal-fired generation also has been more profitable than power dispatch from some natural gas plants. For example, in the first 12 days of December, Argus assessed the peak day-ahead spark spread for 10,000 Btu/kWh coal units at the Indiana power hub — a reference point for central portions of the Midcontinent Independent System Operator — at an average of $27.44/MWh, while the margins for 8,000 Btu/kWh natural gas units were $26.14/MWh. Natural gas units also had less of a profit advantage over coal units in peak month-ahead and peak season Indiana power markets than they had in the first half of December 2024. Similar economic dynamics are present in the PJM Interconnection and Electric Reliability Council of Texas. President Donald Trump's full-throated endorsement of the coal sector, his moves to claw back environmental regulations and his administration's efforts to delay coal-plant retirements are boosting producers' confidence about US coal consumption in 2026. US energy secretary Chris Wright has invoked emergency powers to extend operations at Consumers Energy's JH Campbell plant until at least 17 February 2026. Consumers chief executive officer Garrick Rochow said on 30 October company officials expect the emergency orders for the Campbell plant to continue "for the long term". Independent of federal action, some utilities also have delayed a handful of power plant retirements and conversions previously scheduled for this year. All told, about 6,000-6,500MW of US coal capacity is being permanently taken off line or converted to another fuel this year, a sharp reduction from the 9,300MW projected at the very beginning of 2025, information collected by Argus and EIA show. The plant units that have delayed retirement dates consumed 6.7mn short tons (st) (6.1mn metric tonnes) of coal last year and 4.7mn st in the first eight months of 2025, EIA power plant operating data show. More retirements are scheduled for 2026, but some market participants have expressed uncertainty about their plans for next year, wondering if the Department of Energy (DOE) also will order their facilities to stay open. So far, DOE has directed Consumers' Energy's JH Campbell plant, which was scheduled to retire in May, three 90-day extension orders. And on 17 December, DOE also ordered Canadian utility TransAlta to delay retirement of its coal unit 2 in Centralia, Washington, for at least 90 days. Wright has indicated he could issue further orders. Some utilities — including CenterPoint, Dominion Energy, Southern Company subsidiary Georgia Power and Santee Cooper — have indicated they may delay coal plant retirements and conversions scheduled for 2026 and later. Most of the delays are short term and tied to revised timelines for bringing other facilities on line or incremental electricity growth, including potential data center additions. CenterPoint in October cited both economic reasons and greater load growth forecasts for reconsidering converting unit 3 of its FB Culley plant in Indiana to natural gas by the end of next year. The outlook for US exports is certain. Competition to place coal in European and Asia-Pacific markets remains steady. Those conditions could sustain downward pressure on some US thermal coal export prices and demand. But producers have expressed some optimism about 2026 US coal markets, with many having filled all of their projected sales book for next year and layered in contracts that have deliveries going out into 2027 and slightly later. And many market participants are thinking that stabilization might well continue into 2026. By Courtney Schlisserman Prompt season coal to gas differentials $/MWh Coal versus gas prompt month differentials $/MWh Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Viewpoint: CSAPR sentiment bearish despite coal use

25/12/22

Viewpoint: CSAPR sentiment bearish despite coal use

Houston, 22 December (Argus) — Expectations for lower prices is likely to persist in the federal Cross-State Air Pollution Rule (CSAPR) allowance markets next year as they remain oversupplied, even with higher levels of coal-fired generation. The seasonal NOx markets have been more active this year compared to 2024, when prices essentially flatlined due to regulatory and legal uncertainty brought about by a barrage of lawsuits filed against the US Environmental Protection Agency (EPA) for its "good neighbor" plan. That plan, which the agency finalized in 2023 under former president Joe Biden, sought to help downwind states meet the 2015 national air quality standards for ozone. The plan imposes more stringent ozone season NOx caps for power plants in more than 20 upwind states, as well as setting new limits on some industrial facilities. But the plan is now essentially defunct after the US Supreme Court halted its implementation in June 2024. This led the EPA to return to less-rigorous NOx emissions limits tied to older ozone standards and reshuffle the participating states into the Group 2 and "expanded" Group 2 markets. Argus launched its assessment of the latter in February 2025. EPA said in March it intends to reconsider the good neighbor plan in order to give states more freedom in developing their own ozone reduction plans. The announcement led to the US District of Columbia Circuit Court of Appeals pausing a lawsuit challenging the legality of the good neighbor plan until the agency completes its reconsideration, and which could culminate in new regulations by fall 2026. But those developments did little to move the seasonal NOx markets, which have already been sluggish due to oversupply and weak compliance demand, leading to more dramatic price fluctuations when trades do occur. Argus has assessed Group 2 allowances at $875/short ton (st) since 1 December and expanded Group 2 allowances at $850/st since 24 October. It is unclear how US president Donald Trump's current hostility towards environmental regulations will affect the administration's attitude towards the existing CSAPR allowance trading markets, but it seems likely that they are here to stay. The EPA likely is "digging into the air transport modeling that they have to understand what their options are," and which could potentially echo its determination during Trump's first term that states had adequately addressed downwind pollution, said Carrie Jenks, executive director of Harvard Law School's Environmental and Energy Law Program. "The EPA is committed to advancing cooperative federalism and working with states on state implementation plans (SIPs) to provide clean air for all Americans," the agency said in December. But extensive case law suggests that the EPA has little room to give states more power to manage emissions as they see fit. Both the DC Circuit Court and the US Supreme Court have made it clear that the EPA must intervene if a state does not sufficiently lower its emissions, Jenks said. "So the EPA's hands, regardless of who's in the White House, are really tied," she said. As a result, the EPA will likely try to prolong the issue by giving states more time to draw up their own ozone-reduction plans. The debates over those plans could revolve around how the modeling of emissions is conducted and interpreted. Even if that modeling is challenged in the courts, it can take years for litigation to get resolved. More coal, more emissions Despite the continued dearth of activity in the seasonal NOx markets, increases in coal-fired generation, a significant source of NOx and SO2 emissions, have buoyed the outlook in those markets, heightening expectations for higher emissions. During the past year, stronger power demand and higher natural gas prices have allowed coal to take a larger market share, which has resulted in increased coal-fired power in grids that serve states covered by CSAPR. But NOx emissions during this year's ozone season, which ran from May through September, were lower than expected, according to market participants. Cumulative emissions in the Group 2 and expanded Group 2 markets rose by just 1pc and 4.2pc, respectively, and remained well below their overall limits. It was likely more cost-effective for power plants to run their NOx controls than to purchase or surrender additional allowances for compliance. Still, given the Trump administration's pro-coal agenda, it remains to be seen for how long increases in coal generation will continue and to what extent that will affect the CSAPR markets. Conversations over ballooning data center demand have also bled into the seasonal NOx markets as the Trump administration seeks to leverage coal to power that boom. There are currently a lot of moving parts that make it difficult to make predictions, including how competitive coal is compared to other energy sources such as renewables, where data centers get built, their demand flexibility, and the federal and state regulatory landscapes in the coming years, Jenks said. By Ida Balakrishna Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Japan's Niigata assembly backs Tepco's nuclear return

25/12/22

Japan's Niigata assembly backs Tepco's nuclear return

Osaka, 22 December (Argus) — Japan's Niigata prefectural assembly has supported its prefectural governor's decision to approve the restart of the Kashiwazaki-Kariwa nuclear reactors operated by utility Tokyo Electric Power (Tepco). The assembly passed a vote of confidence on Niigata governor Hideyo Hanazumi on 22 December. He had sought the assembly's judgement on his plan to authorise the restart of the No.6 and No.7 reactors at the Kashiwazaki-Kariwa, each with a capacity of 1,356MW. Hanazumi had previously indicated that he would step down if the motion was rejected. The motion was attached to a supplementary budget request of ¥31mn ($197,048) for the April 2025-March 2026 fiscal year, intended to support activities related to the restart of the Kashiwazaki-Kariwa nuclear plant. Hanazumi plans to meet Japan's trade and industry minister Ryosei Akazawa on 23 December to discuss the restart of the nuclear plant. The endorsement will allow Tepco to move towards restarting its reactors for the first time since they triggered the Fukushima-Daiichi nuclear disaster, after a powerful earthquake and tsunami in March 2011. The plant, which has remained off line since March 2012, is Tepco's sole nuclear station, after it scrapped the damaged Fukushima Daiichi and nearby Fukushima Daini plants. The Kashiwazaki-Kariwa plant comprises of seven reactors with a combined capacity of 8,212MW, of which the No.6 and No.7 units have cleared the stricter post-Fukushima safety inspections. Tepco has yet to file an application with the country's nuclear regulation authority (NRA) for screening of the five other reactors. The utility is also mulling scrapping the No.1 and No.2 reactors. Tepco is expected to prepare for the restart of the No.6 reactor first, given that the No.7 unit will be required to remain shut until August 2029 for the installation of anti-terrorism facilities. The No.6 reactor is expected to resume operations after clearing pre-use inspections, which typically last for three weeks to one month. This means that Tepco will be able to restart the No.6 reactor in January at the earliest. The return of the Kashiwazaki-Kariwa plant could be a milestone in Tepco's progress in nuclear power generation after the Fukushima disaster, with the No.6 unit marking Tepco's first reactor to be restarted after the disaster. Electricity from the nuclear plant will be sent to the Tokyo metropolitan area, with the nuclear plant — located in the Tohoku region — mitigating the risk of a power shortage in Japan's capital. A single nuclear reactor can produce 10 TWh/yr of electricity, and can save the company an estimated ¥100bn/yr, Tepco previously said. The return of the No.6 reactor is also expected to reduce CO2 emissions by around 3.3mn t/yr, it added. By Motoko Hasegawa Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Pakistan's 660MW coal plant shows overcapacity: IEEFA

25/12/22

Pakistan's 660MW coal plant shows overcapacity: IEEFA

Singapore, 22 December (Argus) — Pakistan's 660MW Jamshoro coal-fired power plant has been operating at 6pc capacity since its commissioning in May, underscoring weak electricity demand and broader structural challenges in the country's power sector, according to think tank the Institute for Energy Economics and Financial Analysis (IEEFA). The imported coal-fired plant, part of a state-owned generation facility in Sindh province of Pakistan, was built with international financing led by the Asian Development Bank. It has been operating at low capacity at a time when the national grid currently has a surplus of 10–12GW, IEEFA said in its report released last week. The plant's weak operational metrics has capped growth potential of Pakistan's overall coal imports. The country's thermal imports are estimated at 752,000t in December, up from 503,000t a year earlier, according to data analytics firm Kpler. Low utilisation rates also exacerbate financial stress in the sector, as power tariffs must rise to cover capacity charges to operate the plant, IEEFA said in its report. Capacity payments are fixed charges owed to generators regardless of output. Expansion scrapped Jamshoro Power has dropped plans to add another 660MW coal-fired unit at the facility, which also includes 880MW of gas- and oil-fired power plants. The company has moved to exclude the generating license for the second 660MW coal unit from the project, citing lack of funds for construction, power regulator Nepra said in a notice to stakeholders . Jamshoro Power company was originally licensed to operate two 660MW units, but only one was built and entered commercial operation in May. The company has also proposed de-licensing its four oil-fired generation units, which have a combined capacity of 880MW. By Saurabh Chaturvedi Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Viewpoint: Dry weather to ease Australia's coal queues

25/12/17

Viewpoint: Dry weather to ease Australia's coal queues

Sydney, 17 December (Argus) — Dry weather and minimal maintenance over January-March 2026 could support coal deliveries to Australia's Newcastle port, as well as exports from the thermal coal hub, which would help it recover from severe disruptions that took place during May–September. Newcastle has a 57pc chance of receiving 339–450mm of rain over the first three months of 2026, slightly above its historical median of 338.5mm but still below levels likely to cause port-side or rail disruptions, data from the Australian Bureau of Meteorology (BoM) show. The coastal city received approximately 517mm of rain during May–July this year, data from BoM show, during which Newcastle port implemented multiple rounds of vessel movement restrictions. The weather challenges pushed up the average vessel queue at the Port Waratah Coal Services (PWCS) up to 60 ships in July, from 41 vessels a year earlier. PWCS has partly cleared its ship queue since, but it still hovered at 36 vessels in November, up from just 11 vessels a year earlier. Demand in January-March Weaker demand during the first quarter of 2026 could help ease vessel congestion at Newcastle port's coal terminals. Exports to key markets in northeast Asia including Japan, China and South Korea typically decrease in the first quarter, after the peak winter season. La Nina weather conditions in Japan are expected to weaken in the second half of winter, according to the Japan Weather Association (JWA). The country faced a severe cold season in February this year, but the JWA predicts an arrival of spring-like conditions in February 2026. This could ease demand for coal exports to Japan during that period. But weaker demand could put pressure on coal producers if prices fall steeply next year. Newcastle high-calorific value (CV) NAR 6,000 kcal/kg coal prices trended downwards from February-April after the winter season in Japan, reaching its lowest level of $91.71/t fob Newcastle at the end of April. High-CV NAR 6,000 kcal/kg coal is usually exported to Japan and Taiwan, while China mainly imports high-ash NAR 5,500 kcal/kg coal from Australia. If the premium between NAR 6,000 kcal/kg and high-ash coal tapers, producers are likely to maximise profits by selling more coal to China. Chinese utilities usually buy Australian coal to take advantage of the price arbitrage compared with domestic Chinese coal supplies delivered from north China ports. But the price of domestic coal in China was volatile from November 2024-January 2025, owing to safety inspections at major coal mines in the country. Thermal coal exports out of Australia averaged 15.4mn t/month in the first quarter of 2025, according to customs data, which is consistent with averages recorded in the first quarters of 2023-25. But this is lower than the yearly average of 16.8mn-17.3mn t/month during 2023-25. Movements to port Producers are also likely to face fewer rail disruptions over the first quarter of next year. Australian state-owned rail operator the Australian Rail Track (ARTC) has just a single maintenance shutdown planned over the period. It will close its Hunter Valley coal lines — which link New South Wales mines to the port — for 72 hours in February (see table) . ARTC conducted four rounds of major maintenance over July–November this year, pushing down deliveries to PWCS' terminals at Newcastle port. Producers sent 87mn t of coal to the terminals in January-November, down by 4.4pc on the year, data from PWCS show. By Avinash Govind and Nadhir Mokhtar ARTC track maintenance Date Lines Length of Time (hrs) 10-13 February Warabrook/Kooragang to Muswellbrook 72 10-13 February Muswellbrook to Ulan 72 10-13 February Muswellbrook to Turrawan 72 30 March-2 April Warabrook / Kooragang to Muswellbrook 48 30 March-2 April Muswellbrook to Ulan 72 30 March-2 April Muswellbrook to Turrawan 72 16–19 May Warabrook/Kooragang to Muswellbrook 72 16–19 May Muswellbrook to Ulan 72 16–19 May Muswellbrook to Turrawan 72 16–19 May Islington Junction to Port Waratah 48 16–19 May Islington Junction to Telarah 72 21-24 July Warabrook / Kooragang to Muswellbrook 72 21-24 July Muswellbrook to Ulan 72 21-24 July Muswellbrook to Turrawan 72 22-25 September Warabrook / Kooragang to Muswellbrook 72 22-25 September Muswellbrook to Ulan 72 22-25 September Muswellbrook to Turrawan 72 17-20 November Warabrook / Kooragang to Muswellbrook 72 17-20 November Muswellbrook to Ulan 72 17-20 November Muswellbrook to Turrawan 72 Source: Australian Rail Track Corportation (ARTC) Australia coal prices 2023-2025 $/t Send comments and request more information at feedback@argusmedia.com Copyright © 2025. 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