Japan’s Kyushu to test ammonia co-firing at coal unit

: Coal, Electricity, Emissions, Fertilizers, Hydrogen
23/10/30

Japanese utility Kyushu Electric Power plans to carry out trial ammonia co-firing at its Matsuura coal-fired power plant, in efforts to to achieve carbon neutrality by 2050.

Kyushu will start small-scale experimental use of ammonia at the 1GW No.2 coal-fired unit at Matsuura in southern Japan's Nagasaki prefecture from 2 November. The test run is expected to last for around one week, and use around 330 kg/hr of ammonia. The company will utilise ammonia that has been used for denitrification.

This is the second ammonia co-firing trial at Kyushu, following a study at the 700MW Reihoku No.1 coal-fired unit over 11-28 April. The company has confirmed there were no environmental impact or damage to a boiler through the study.

Kyushu is aiming to establish technologies that will allow a 20pc co-firing of ammonia, as well as a 1pc hydrogen mixture, at its power plants by the April 2030-March 2031 fiscal year. The company has a target to achieve a 60pc reduction in its scope 1, 2 and 3 greenhouse gas emissions by 2030-31, based on 2013-14 levels, through its supply chains while it aims to cut its domestic emissions by 65pc. This is a more ambitious target as compared with Tokyo's goal to attain a 46pc reduction.

By Motoko Hasegawa

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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.

Australia releases key IFLM carbon method draft

25/12/22

Australia releases key IFLM carbon method draft

Sydney, 22 December (Argus) — The Australian government today released the exposure draft for the long-awaited Integrated Farm and Land Management (IFLM) carbon credit method ahead of a public consultation starting in late January. The draft method includes the regeneration of native forest on suppressed land as a proposed eligible activity, meeting a key demand from carbon project developers, but it excludes a previously planned soil carbon module . The method's "framework" design will enable the addition of future activities, including improvements to soil, as well as updates to measurement approaches and carbon pools over time, the Department of Climate Change, Energy, the Environment and Water (DCCEEW) said on 22 December. The DCCEEW will allow two abatement-calculation approaches to estimate carbon stock change under the method, using Australia's Full Carbon Accounting Model (FullCam) — a model-only approach and a hybrid approach where modelled estimates are refined by measurements in the project. The hybrid approach will need to be legislatively drafted to be included in the final draft methodology determination. "The modular design enables more activities, technologies and carbon pools to be added over time, giving greater flexibility to land managers," the DCCEEW said. Three main activities The planned Australian Carbon Credit Unit (ACCU) method could be the first in the country to combine multiple activities that store carbon in the land on a single property. This aims to streamline participation and reduce the administrative burden compared with running multiple projects on the same land, the DCCEEW said. The module for regeneration of native forest on suppressed lands builds on the key human-induced regeneration (HIR) ACCU method, which expired in September 2023. But like the FullCam hybrid approach, it will require legislative drafting in 2026, as both components "are more complex than approaches already incorporated into the exposure draft". The method would also enable crediting of carbon from two modules which are already legislatively drafted — reforestation by environmental plantings, an activity with an existing method that was updated late last year , and regeneration of native forest on cleared lands, which is based on the expired native forest from managed regrowth (NFMR) method. Soil carbon is not in the draft because the Emissions Reduction Assurance Committee (Erac) — the statutory body responsible for ensuring the integrity of Australia's carbon crediting framework — is reviewing the Soil Organic Carbon 2021 method. This is because of the complexity of the review process , Erac chair Karen Hussey said last month. The outcomes of that review will inform the inclusion of a revised soil carbon module in the IFLM method in the future, the DCCEEW said. Contentious areas Uncertainties remained until recent weeks on whether a draft method would be submitted to Erac before the end of 2025. A summary paper of a stakeholder group meeting in September noted that some members had recommended postponing the IFLM method, as "a robust approach which clearly demonstrated integrity was more important than timelines". The inclusion of regeneration of native forest on suppressed land has proved to be a contentious issue. "There has been considerable research into the impacts of grazing management on the diverse ecosystems in Australia, including the different approaches to quantify the changes in vegetation, and in existing HIR projects," the DCCEEW said today. "Uncertainties remain and this issue is still an active area of research." But the IFLM draft settings provide confidence that the method is robust and that credited abatement is additional, as it will establish new eligibility criteria, require on-ground measurements and apply conservative abatement estimates in early project years, the DCCEEW noted. Projects will need to use the FullCam hybrid approach to estimate abatement for this activity module. This will reduce the potential for over-crediting or under-crediting abatement, particularly for lower-rainfall environments where there can be less certainty in attributing the regeneration to project activities. Projects will also need to have a low initial carbon stock at the start of their 25-year crediting period, and will need to achieve forest cover during that period. They will also have a baseline period of 20 years compared with 10 years for HIR projects. This is the time over which the project land area must not have had forest cover because of suppression mechanisms such as grazing pressure, chemical or mechanical destruction of regrowth, or the presence of non-native plants. Finally, the department is proposing to apply discounts when attributing carbon stock change to projects under that module, including a temporary 5-25pc attribution discount to address climate-related uncertainties. Existing HIR, NFMR or environmental plantings projects will be able to transfer their projects to become IFLM projects if they meet eligibility requirements in the final IFLM method. They will also be able to add additional land to the project area to undertake additional abatement activities. Consultation to start on 27 Jan The release of the draft method and other documents allows an early review of the material before a formal, 28-day consultation period starts on 27 January, the DCCEEW said today. Feedback will help Erac decide whether the method complies with Australia's offsets integrity standards and it will recommend it to assistant minister for climate change and energy Josh Wilson. The DCCEEW intends to provide a final IFLM methodology determination for Erac's consideration "in 2026", it said, without disclosing a specific timeline. By Juan Weik Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Viewpoint: Biogas growth uneven, shipping drives 2026

25/12/22

Viewpoint: Biogas growth uneven, shipping drives 2026

London, 22 December (Argus) — Europe's biomethane market faces uneven growth in 2026, with numerous unsolved policy hurdles and as adoption of the EU's revised renewable energy directive (RED III) reshapes national compliance frameworks. Shipping demand will remain a key driver, particularly for certified subsidised product. RED III's overall 2030 target gives EU member states the option to reduce greenhouse gases (GHGs) by 14.5pc, or reach a 29pc renewable energy share. RED II only required countries to reach a 14pc renewable energy share. Some states have already transposed RED III, including the Netherlands and Germany , and pivoted incentive schemes to reward fuels on a GHG reduction basis. This is setting up biomethane with low or negative carbon intensity (CI) as a fuel of choice for suppliers obligated to comply with the regulation in the Netherlands, where previously it lagged behind cheaper, energy-intense biofuels. Another EU regulation that favours biomethane use is FuelEU Maritime, which came into effect in January 2025 requiring shipowners to reduce fleet emissions by 2 pc/yr in 2025 and 2026. Over-compliance can be sold under pooling schemes — which have proven profitable for bio-LNG bunkering. The mandate became a major market price driver for renewable gas guarantees of origin (RGGOs) — certificates issued to companies producing gas made from non-fossil fuel sources — and this should continue into 2026. New schemes, either under RED III or domestic obligations, that will come into effect in 2026 will compete with maritime demand for supply. Most 2026 Dutch and Danish supply has already been sold to the maritime sector. Growing Netherlands As well as a pivot to GHG-based compliance with a new ERE ticket system under RED III, the Netherlands began work on a Green Gas Blending Obligation in November. While implementation before late 2027 seems unlikely, progress should boost RGGO forward pricing. Dutch biomethane liquidity could be bolstered if the government approves mass-balancing , a method to track and verify biomethane when it is injected into the gas grid system and becomes indistinguishable from conventional gas. A motion was proposed in parliament in November, but a recent government response indicates this is unlikely. Bio-LNG must be unsubsidised, certified and physically delivered to qualify for ERE tickets, otherwise it will be treated with a fossil gas CI of 94g CO2e/MJ when calculating a fuel supplier's overall mandate level. Steady Germany, France Germany will remove double-counting for waste-based biofuels under its GHG reduction quota (THG) in 2026, but biomethane should remain the cheapest compliance route for fuel suppliers, as rising mandates will support demand. Most German imports come from the UK or Denmark. The former may benefit from Danish prices inflated by maritime demand, despite questions about UK eligibility with German schemes. France's biogas production certificate (CPB) blending mandate starts in January, which should significantly boost domestic demand. But the country has delayed its RED III transposition , which includes a new GHG-based IRICC ticket system, to 2027. The current energy-based TIRUERT transport ticket system will remain in place for a year, limiting transport-sector uptake. It is unclear if IRICCs can be generated from biomethane in 2027, but 3pc renewable gas obligations for transport will start in 2028, increasing thereafter. Cross-border trade and bio-LNG bunkering should remain limited. French biomethane can only be exported as an ex-domain cancellation , the cancellation of RGGOs in one country's registry for use in a different country. This carries risk to buyers, as ownership is not necessarily transferred. Subsidised biomethane cannot be liquefied at French LNG terminals for use outside the country. French bio-LNG must be exported via mass-balancing to other terminals in the EU, for use under FuelEU Maritime. Uncertain UK The UK's access to EU markets hinges on access to the Union Database for gaseous Biofuels (UDB), now targeted for launch by end-summer 2026. Uncertainty about third-country treatment could restrict EU trade — a critical issue given the UK exported more than half its RGGOs in the first three quarters of 2025, mostly to Germany, Norway and Switzerland. The UK is consulting on replacing volume-based RTFC tickets with a GHG-based system, but any changes would not be enacted until 2027. Overall in Europe, biomethane remains well positioned in GHG-based systems, but policy implementation delays will probably slow overall market growth. The Netherlands, Denmark and Germany should remain anchors for European pricing, and Spain should consolidate its role as a maritime hub. But several countries risk lagging behind without RGGO registries, export hub access, policy incentives and subsidy reform. By Madeleine Jenkins Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Viewpoint: High integrity and compliance to drive VCM

25/12/22

Viewpoint: High integrity and compliance to drive VCM

London, 22 December (Argus) — Liquidity in the voluntary carbon market (VCM) will be increasingly driven by demand for compliance schemes and high-integrity credits over the next 12 months. Carbon project developers are increasingly shifting strategies to tap into the growing demand for offsets approved for the first phase of the Carbon Offsetting and Reduction Scheme for International Aviation (Corsia) or tagged with the Integrity Council for the Voluntary Carbon Market's high-integrity Core Carbon Principles (CCPs) label. The first phase of Corsia — between 2024 and 2026 — was hamstrung this year by a persistent supply bottleneck. Only one government-run forestry project in Guyana made up the entire supply of Emissions Eligible Units (EEUs) for most of 2025 — about 15.8mn credits. Developers faced difficulty obtaining letters of authorisation (LOAs) from host countries — documents indicating their intention to apply a corresponding adjustment (CA) to carbon credits to avoid double counting. And once projects receive LOAs, to issue EEUs they must either demonstrate their host country has applied the CA — through its Biennial Transparency Report (BTR) submitted to the UN — or secure private insurance policies in case the host country retracts the CA. But concerns eased in late 2025 after several projects crossed the line to eligibility, bringing the total number of tagged EEUs to about 17.5mn. Heading into 2026, Verra, the largest carbon registry in the world, is set to apply the tag to at least 5.1mn clean cookstoves credits after it approved insurance policies last week. And a significant chunk of supply is expected to come on line once countries submit their BTRs by the December 2026 deadline. On demand, uncertainty about participating countries and subjected airlines will be settled next year. The EU is expected to release a report reviewing the effectiveness of Corsia to achieve its climate target in July, based on which it might decide to expand its emissions trading system (ETS) to international aviation. This will partly hinge on whether the US — which so far has expressed public support for Corsia but has not taken any measures to implement it — will participate in the scheme. High-integrity credits tagged with the CCPs label have been assessed broadly steady by Argus over 2025, with only landfill gas (LFG) credit prices in the US, Brazil and Bangladesh slightly increasing since the beginning of the year. The widely expected support for pricing has not materialised because buyers are not prepared to pay a premium for LFG CCPs credits yet, according to market participants. And despite several Integrity Council for the Voluntary Carbon Market (ICVCM) decisions to expand the scheme with the approval of carbon removal, clean cookstoves, and improved forest management methodologies, most CCPs supply is still made up of LFG credits. Despite the relatively lacklustre premium for CCP LFG credits over their non-tagged counterparts, other areas of the market are expected to benefit much more significantly from the high-integrity label. Clean cookstoves developer Burn, for instance, will only issue CCPs-tagged credits or Corsia Phase 1-approved EEUs, it said, because these command a significant premium. Over-the-counter CP1 credits were assessed last week at $20.90/t CO2e and Burn said it has struck forward offtake deals for its CCPs supply at around $15-20/t CO2e. For developers, these markets are expected to unlock significantly more revenue than standard clean cookstoves credits in Africa, which are currently assessed at $3.15/t CO2e for vintages 2019 onwards. Lastly, the highly liquid Katingan reducing emissions from deforestation and forest degradation (REDD+) project in Indonesia is expected to resume issuing credits in the next quarter, following a supply crunch that supported the Argus- assessed price to more than double from the beginning of 2025. A ban on fresh issuances from the government of Indonesia was lifted in October, but prices have continued to rise since. The most liquid vintage, 2020, was heard trading at levels above $11/t CO2e last week, nearly triple the $4.60/t CO2e price assessed in January. And in the wider VCM, demand is expected to pick up next year after the Science Based Targets initiative publishes its second Corporate Net-Zero Standard, which could increase corporates' appetite for nature-based avoidance and removal credits. Emerging buyers' coalitions will continue to drive demand for tech-removal credits, with the anticipated launch of the Tech Gen group in the second quarter of 2026. By Alexandra Luca Projects generating Corsia Phase 1-approved credits t CO2e Project ID Credits issued Registry Developer Country 11677 1,508,719 Gold Standard Hestian Innovation Malawi 11732 184,500 Gold Standard Burn Tanzania 102 15,800,000 ART Guyana Forestry Commission Guyana Available CCP credits (% of total issued) 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.

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