European coal burn displaces gas in September

Spanish Market: Coal
01/10/18

European coal burn rose in September despite strong output from renewables, as natural gas supply tightness supported short-term prices and lifted coal plants in the merit order for thermal generation.

Aggregate coal-fired generation in Germany, Spain, the UK and France rose by 11pc on the year to a total of 12.9TWh in September, according to provisional data from grid operators and research group Fraunhofer Ise.

Coal burn rose despite record September output from renewable sources — which gained by nearly 17pc on the year to 34.2TWh — as surging gas prices lifted the relative profitability of coal-fired output in the thermal generation mix.

Total gas burn in the same four countries fell by 28pc on the year to a total of 12.6TWh last month, driven in large part by a sharp contraction in gas-fired generation in the UK. This meant that coal-fired generation across the four countries surpassed gas burn for the first time since December 2015.

UK coal burn recovers

UK coal burn rose by more than a fifth on the year to 1.3TWh in September and now looks likely to make further gains in the final quarter of the year.

Gas has dominated the thermal generation mix in the UK in recent years, but a supply crunch driven by weak LNG imports, heavily curtailed storage infrastructure and declining domestic production across northwest Europe has boosted prices and cut into the profitability of gas-fired power generation.

The premium held by day-ahead clean spark spreads for 55pc efficient gas plants over clean dark spreads for 38pc coal units was slashed to an average of €3.20/MWh in September, from €9.09/MWh in August and €11.26/MWh in September 2017. This drove a swing towards coal-fired output in the thermal generation mix in September, with gas burn falling by 24pc on the year to a 40-month low of 6.74TWh.

Gas-to-coal fuel switching was significant enough to lift coal burn on the year despite record September output from renewables of around 5.5TWh. Available wind capacity in the UK has risen above 20GW following the commissioning of the 659MW Walney Extension offshore wind farm in early September, up from a total of around 19.1GW at the end of 2017.

Outright clean dark spreads for winter generation were more than twice as high on the year in September and forward NBP gas prices suggest that coal will also become increasingly competitive with gas for thermal generation as winter progresses.

Day-ahead NBP gas prices were narrowly short of the threshold above which a 39pc efficient coal plant starts to compete with a 55pc efficient gas unit throughout September, but average prices for November, December and the first quarter of 2019 were all higher than the fuel switch level.

This suggests that coal could begin to displace a larger proportion of natural gas from the UK mix from next month, although gas-to-coal fuel switching will be limited by the UK's diminished capacity for coal-fired generation. The UK has around 10.4GW of coal-fired capacity going into this winter, down from 13GW a year earlier, which is enough to burn up to 3 mn t/month of NAR 5,700kcal/kg coal.

UK winter coal imports averaged around 2.6 mn t/month in 2014-15 but have since fallen to around 500,000 t/month in the past two winters, according to Eurostat data.

German coal burn resists rising wind output

German coal burn was only flat on the year in September at 6.9TWh, but increasingly favourable margins for coal generators ensured that gas plants bore the brunt of a surge in renewable output across the month.

Renewable output rose by a fifth on the year to 17.3TWh according to provisional Fraunhofer Ise data, with greater wind output accounting for 60pc of the overall growth. This more than offset a 12pc decline in nuclear output, but the impact on thermal generation was focused on gas burn, which fell by 48pc on the year to its lowest since September 2015 at less than 1.8TWh.

Day-ahead clean dark spreads for 38pc efficient coal plants averaged a €6.86/MWh premium to clean sparks for 55pc gas plants in September, compared with only a €1.40/MWh premium in August and a €1.19/MWh discount in September 2017.

German clean dark spreads for fourth-quarter generation from a 38pc efficient coal plant fell sharply at the end of September, but still expired at a significant premium to the previous two years amid concerns about nuclear availability in France, Belgium and Germany. The fourth-quarter margin averaged €8.69/MWh in September, up from €4.43/MWh and €4.60/MWh in September 2016 and 2017, respectively.

Fourth-quarter coal burn totalled 18.6TWh last year and peaked at 7.5TWh in November.

Spanish coal burn rises

Spanish coal burn recorded even bigger growth than in the UK in September, rising by 42pc on the year to 4.4TWh.

As in the UK and Germany, coal displaced some gas from the mix with gas-fired output falling by 27pc to 2.5TWh last month. Spanish renewable output was up less than 2pc on the year in September at around 6TWh, while nuclear generation increased by 6pc to 5TWh.

Fourth-quarter clean dark spreads for 38pc efficient Spanish coal units averaged nearly €22/MWh in September, up from €18.61/MWh last year, suggesting further growth in coal demand in the final months of the year. Spanish coal burn totalled 13TWh in the fourth quarter of 2017 and peaked at 5TWh in December.

Selected EU coal burn TWh

De, UK, Esp, Fr agg. power generation TWh

NBP vs coal/gas fuel switch vs coal burn p/th, TWh

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24/12/25

Tepco to restart Kashiwazaki-Kariwa No.6 reactor in Jan

Osaka, 24 December (Argus) — Japanese utility Tokyo Electric Power (Tepco) plans to reactivate its long-idled 1,356MW No.6 reactor at its Kashiwazaki-Kariwa nuclear power plant on 20 January 2026, with the aim of beginning normal operations on 26 February. On 24 December, Tepco submitted the potential target dates for resuming tests and normal operations of the reactor in Niigata prefecture, northwest Japan, to the country's Nuclear Regulation Authority (NRA). Tepco will assess the reactor's integrity during the test runs. The submission came two days after the Niigata prefectural assembly passed a vote of confidence on its governor Hideyo Hanazumi on 22 December, who had sought the assembly's judgement on his plan to approve the restart of the No.6 and No.7 reactors at the Kashiwazaki-Kariwa. The return of the Kashiwazaki-Kariwa plant could be a milestone in Tepco's progress in nuclear power generation after the Fukushima nuclear crisis in 2011, with the No.6 unit marking the utility's first reactor to be restarted after the meltdown disaster. 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. The No.7 unit will be required to remain shut until August 2029 for the installation of anti-terrorism facilities. Tepco has yet to file an application with NRA for screening of the five other reactors, while it is mulling scrapping the No.1 and No.2 reactors. By Motoko Hasegawa Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Viewpoint: Stable 2026 start for US steam coal

23/12/25

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

22/12/25

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

22/12/25

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

22/12/25

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.

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European coal burn displaces gas in September

UK coal burn recovers

German coal burn resists rising wind output

Spanish coal burn rises

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