Erex starts second biomass co-firing test in Vietnam

Spanish Market: Biomass, Electricity
26/12/25

Japanese renewable energy developer Erex started its second test runs of coal and biomass co-firing at a thermal power plant in Vietnam, the company announced on 24 December.

Erex began the trial co-firing operations at a 57.5MW unit of the 115MW Cao Ngan plant in northern Vietnam on 20 December. The test runs are expected to last around a month, burning up to 20pc of wood pellets secured domestically, according to the company. The thermal power plant is owned by Vietnam National Coal and Mineral Industries (Vinacomin).

Erex has successfully carried out biomass co-firing test runs at a 55MW unit of the 110MW Na Duong plant in Vietnam over September-November, burning up to 20pc of domestically secured wood chips with coal. It was the company's first co-firing test at a Vietnamese thermal power plant.

Vinacomin and Erex will renovate both plants in 2026-27 and start commercial co-firing operations around 2027-28. The Japanese company also plans co-firing test runs at the 670MW Cam Pha plant in 2027-28 and to start commercial operations around 2029-30.

The company aims to carry out co-firing operations at six Vinacomin thermal power plants in Vietnam, with a total capacity of 1,585MW, including the Na Duong, Cao Ngan and Cam Pha plants.

The co-firing projects underscore Vietnam's net-zero strategy. The country currently relies on coal to meet around half of its electricity demand, with power consumption increasing by 10 pc/yr. Vietnam has looked to biomass fuels as self-sufficient renewable energy sources.

Meanwhile, Erex is eyeing carbon credits from the co-firing projects and is in negotiations with the Vietnamese government on this. The company is considering selling some of the carbon credits to other firms in Japan, after commercial co-firing operations begin in Vietnam.

Erex is expanding its renewable energy business in Vietnam and Cambodia. Other than co-firing projects, the company plans to operate 19 biomass-fired power plants in Vietnam. The 20MW Hau Giang plant in southern Vietnam, which came on line in April, is the Japanese firm's first biomass-fired generation project in Vietnam

By Takeshi Maeda

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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.

Singapore plans 130MWp floating solar farm by 2029

24/12/25

Singapore plans 130MWp floating solar farm by 2029

Singapore, 24 December (Argus) — Singapore's national water agency PUB aims to build a 130MW-peak (MWp) reservoir solar farm by 2029 to offset its carbon footprint, according to project documents published by the agency on 23 December. When built, the facility will help Singapore close in on its solar capacity target of 2GWp by 2030. The country is just about 200MW short of its target. Construction of the project is scheduled to start in 2026, pending feedback on an environmental impact assessment and final government approval. The latest capacity figure for the project is higher than the PUB's earlier estimate of 100MWp possible for the site, which is a flood control and rainwater collection reservoir. Australian engineering firm Aurecon is providing consultancy services, while a solar developer has not been specified. The PUB also did not disclose commercial details for the project. Singapore currently has one completed and two other ongoing reservoir solar projects, all of which are headed by Singaporean utility Sembcorp. Sembcorp has a 25-year power purchase agreement (PPA) with PUB for the operational 60MWp facility, and another 25-year PPA with a subsidiary of US tech firm Meta for one of the projects under development, which has a capacity of 150MWp. By Liang Lei 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.

Ausblick Biomethan: Chancen und Hindernisse im EU-Markt

23/12/25

Ausblick Biomethan: Chancen und Hindernisse im EU-Markt

Hamburg, 23 December (Argus) — Der europäische Biomethanmarkt wird in 2026 ein regional ungleichmäßiges Wachstum verzeichnen. Verzögerte Umsetzungen der RED III und ungelöste politische Fragen bremsen den Markthochlauf. Gleichzeitig bleibt die Schifffahrt ein zentraler Nachfragetreiber — vor allem für zertifiziertes, subventioniertes Biomethan. Die überarbeitete EU-Richtlinie für erneuerbare Energien (RED III) gibt den Mitgliedstaaten bis 2030 zwei Optionen, um die Klimaschutzziele der EU zu erreichen: Entweder können die Staaten ihre Treibhausgasemissionen bis 2030 um 14,5 % zu senken, oder sie können einen Anteil von 29 % ihres Energiebedarfs aus erneuerbaren Quellen decken. RED II verlangte lediglich einen Anteil von 14 % erneuerbarer Energien. Einige Länder wie Deutschland haben ihre nationalen Umsetzungspläne der Vorgaben von RED III bereits vorgestellt und planen, diese im kommenden Jahr umzusetzen. Mehrere Länder wie die Niederlande oder Frankreich setzen zukünftig auch auf ein THG-System, wie es in Deutschland nun schon seit Jahren existiert. Biomethan mit niedriger oder negativer Kohlenstoffintensität wird damit zum bevorzugten Kraftstoff, um die Verpflichtungen zu erfüllen — vor allem in den Niederlanden, wo es bisher hinter vergleichsweise günstigeren Biokraftstoffen zurückblieb. Eine weitere EU-Verordnung, die den Einsatz von Biomethan begünstigt, ist FuelEU Maritime. Diese trat im Januar 2025 in Kraft und verpflichtet Reedereien, die Emissionen ihrer Flotten in den Jahren 2025 und 2026 um jeweils 2 % pro Jahr zu senken. Übererfüllung kann über Pooling-Systeme vermarktet werden. Dies hat sich für das Bunkering von Bio-LNG in 2025 als besonders profitabel erweisen. Die Regelung hat die Preise für Herkunftsnachweise (HKNs, oder englisch: RGGOs) stark beeinflusst und dürfte 2026 weiter für Dynamik sorgen. Neue Systeme, entweder unter RED III oder nationalen Verpflichtungen, die 2026 in Kraft treten, werden Nachfrage erzeugen, die mit dem Bedarf aus der Schifffahrt um das Angebot konkurrieren muss. Der größte Teil des niederländischen und dänischen Biomethanangebots für 2026 ist bereits für den maritimen Sektor vorgesehen. Wachstum in den Niederlanden Neben der Umstellung auf die THG-basierte Verpflichtung im Rahmen des sogenannten ERE-Zertifikatssystem unter RED III haben die Niederlande im November mit der Arbeit an einer "Green Gas Blending Obligation" begonnen. Eine Umsetzung vor Ende 2027 erscheint zwar unwahrscheinlich, doch die Pläne stützen vorerst die Preise für HKNs. Die Liquidität von niederländischem Biomethan könnte steigen, wenn die Regierung die Massenbilanzierung von Biomethan genehmigt. Ein entsprechender Antrag wurde im November im Parlament eingebracht, doch eine jüngste Regierungsantwort deutet darauf hin, dass dieser nicht von Erfolg gekrönt sein wird. Bio-LNG muss, wie auch in Deutschland, unsubventioniert sein, zertifiziert sein und physisch geliefert werden, um sich für ERE-Zertifikate zu qualifizieren, andernfalls wird es bei der Berechnung des Gesamtmandats eines Kraftstoffanbieters mit einer fossilen CI von 94 g CO2e/MJ behandelt. Stabiles Deutschland, Frankreich Deutschland wird 2026 die Doppelanrechnung für fortschrittliche Biokraftstoffe wie Biomethan auf die THG-Quote abschaffen. Bislang war dies stets ein großer Anreiz für den Einsatz von Biomethan als Kraftstoff. Trotzdem bleibt Biomethan in Deutschland der günstigste Weg, um die THG-Quote zu erfüllen, denn insbesondere güllebasiertes Biomethan hat ein konkurrenzloses Einsparungspotenzial. Auch die steigende THG-Quote könnte die Nachfrage stützen, jedoch bleibt der Absatzmarkt in Deutschland durch die limitierte Anzahl an LNG- und CNG-Fahrzeugen begrenzt. Frankreichs Beimischungspflicht für Biogas-Produktionszertifikate (CPB) tritt im Januar in Kraft und dürfte auch dort die Inlandsnachfrage deutlich ankurbeln. Die Umsetzung der RED III-Richtlinie, die ein neues, auf Treibhausgasen basiertes IRICC-Ticketsystem vorsieht, wurde jedoch auf 2027 verschoben. Das derzeitige energiebasierte TIRUERT-Ticketsystem für den Transport bleibt bis dahin bestehen, und bremst die Nutzung von Biomethan im Verkehrssektor. Ob IRICCs ab 2027 aus Biomethan generiert werden können, ist noch unklar. Die Verpflichtung, 3 % erneuerbares Gas im Verkehrssektor zu verwenden, tritt 2028 in Kraft und wird danach weiter ansteigen. Der grenzüberschreitende Handel und die Bunkerung von Bio-LNG dürften weiterhin eingeschränkt bleiben. Französisches Biomethan kann nur im Rahmen einer Ex-Domain-Annullierung exportiert werden, also durch die Löschung von HKNs in einem Land zur Verwendung in einem anderen. Dies birgt Risiken für Käufer, da die Eigentumsrechte an den Nachweisen nicht zwangsläufig übertragen werden. Subventioniertes Biomethan darf an französischen LNG-Terminals nicht für die Nutzung außerhalb des Landes verflüssigt werden. Französisches Bio-LNG muss über Massenbilanzierung an andere Terminals in der EU exportiert werden, um unter FuelEU Maritime genutzt zu werden. Großbritannien: Zugang zur EU unklar Der Zugang des Vereinigten Königreichs zu EU-Märkten hängt vom Zugang zur Unionsdatenbank für gasförmige Biokraftstoffe (UDB) ab, deren Start nun für Ende Sommer 2026 vorgesehen ist. Unklarheiten bei der Drittstaatenregelung könnten den EU-Handel einschränken — ein kritisches Thema, da das Vereinigte Königreich in den ersten drei Quartalen 2025 mehr als die Hälfte seiner HKNs exportierte, hauptsächlich nach Deutschland, Norwegen und in die Schweiz. Das Vereinigte Königreich prüft derzeit den Ersatz volumenbasierter RTFC-Tickets durch ein THG-basiertes System, doch Änderungen würden erst 2027 in Kraft treten. Fazit Insgesamt bleibt Biomethan in Europa in THG-basierten Systemen gut positioniert, doch Verzögerungen bei der Umsetzung von Vorschriften dürften das Gesamtwachstum des Marktes verlangsamen. Die Niederlande, Dänemark und Deutschland sollten weiterhin Anker für die europäische Preisbildung bleiben, und Spanien dürfte seine Rolle als maritimer Hub festigen. Doch mehrere Länder riskieren, zurückzufallen, wenn sie keine HKN-Register, Export-Hub-Zugänge, politische Anreize und Subventionsreformen einführen. Von Madeleine Jenkins & Svea Winter Senden Sie Kommentare und fordern Sie weitere Informationen an feedback@argusmedia.com Copyright © 2025. Argus Media group . Alle Rechte vorbehalten.

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.

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