CNPE define meta de 48mi de Cbios em 2026

: Biofuels, Natural gas
25/12/30

O Conselho Nacional de Política Energética (CNPE) aprovou hoje a meta de descarbonização no âmbito da Política Nacional de Biocombustíveis (Renovabio), definida em 48,09 milhões de créditos de descarbonização (Cbio) em 2026.

O valor está alinhado à proposta do governo na recente consulta pública do setor, mas é inferior aos 51 milhões-52 milhões de Cbios que os produtores de biocombustíveis recomendaram para promover maior cumprimento e impulsionar a demanda pelo crédito.

A Agência Nacional do Petróleo, Gás Natural e Biocombustíveis (ANP) estabeleceu metas individuais preliminares para distribuidores de combustíveis com base nos dados de participação de mercado entre janeiro-outubro deste ano. As metas definitivas serão publicadas até 31 de março de 2026, após os abatimentos de compras de biocombustíveis em contratos de longo prazo e ajustes ao cumprimento de normas dos anos anteriores.

O Itaú BBA projeta que a meta estabelecida, combinada com obrigações descumpridas de 2025 mais as deduções de contratos de longo prazo, totalizem cerca de 3 milhões de Cbios. As metas individuais podem chegar a aproximadamente 52,5 milhões de Cbios.

Os estoques que serão carregados de 2025 para 2026 podem chegar a 36,1 milhões de Cbios.

A geração de biodiesel deve somar 8,3 milhões de créditos, enquanto as de biometano podem contribuir com outros 200.000 créditos, somando uma oferta total de cerca de 44,6 milhões de Cbios ao longo do ano.

Com esses estoques, o Itaú BBA calcula uma disponibilidade agregada de 61,7 milhões de Cbios, muito acima do meta efetiva de 52,5 milhões. Até em caso de inadimplência zero, o superávit final pode chegar a 9 milhões de Cbios. Em um cenário-base de 85pc de adesão, o superávit pode diminuir para 17,1 milhões de Cbios, sendo ainda suficiente para manter os preços baixos.

O relatório afirma que os preços de Cbios devem permanecer sob pressão, barrando obstáculos judiciais ou alterações de enforcement pela ANP. O texto também destaca que aumentos de mesclas em combustíveis fósseis podem influenciar futuros ajustes da meta.

Por Rebecca Gompertz

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25/12/30

Viewpoint: Data centers set to raise east US gas prices

Houston, 30 December (Argus) — Hyperscale data centers could reshape natural gas demand across Appalachia and the US east coast, driving infrastructure buildouts and tightening regional price spreads. Utilities and pipeline developers in the US southeast are planning more than 3.3 Bcf/d (93mn m³/d) of new gas-fired generating capacity by 2040, largely to supply data centers, according to a January report by the Institute for Energy Economics and Financial Analysis (IEEFA). In Virginia, South Carolina and Georgia, these facilities account for 65-85pc of projected electricity load growth, the report said. Driven by demand for artificial intelligence (AI) and cloud computing, data centers are energy intensive. Operators are racing to secure firm supply from gas-prolific Marcellus and Utica shales, spurring gas pipeline projects like the Commonwealth Energy Connector Project in Virginia and the Mountain Valley Pipeline Southgate expansion, contracted to Duke Energy and Public Service Company of North Carolina. In Virginia's "data center alley", which holds the world's largest number of data centers, growth in power demand may be driven by other large load customers, such as the PJM Interconnection, which manages the electric grid for the District of Columbia and 13 eastern US states. Natural gas producers in the region have struck deals with tech giants such as Meta , that favor natural gas over renewables because of its reliability in the case of extreme weather. New and transformed projects have already started to emerge. Once a coal-fired gas plant, Pennsylvania's Homer City Generating Station has converted into the Homer City Energy Campus, a 4.5-gigawatt natural gas-powered data center leveraging proximity to affordable Appalachian gas. The Chesapeake Utilities Ohio transmission company and Aspire Energy have also signed a $10mn deal for data center supply. This growth in demand could elevate northeastern spot prices that are already pressured by cold weather in a region historically limited by takeaway capacity, especially in population-dense urban areas. Range Resources expects 2.5 Bcf/d of incremental US demand from data centers by the end of the decade and a 4 Bcf/d increase in US LNG export capacity coming online in 2026. "All of these projects will be competing for natural gas supply that could face supply challenges in that short timeframe," Antero Resources senior vice president of natural gas marketing Justin Fowler said during a recent earnings call. In response, Antero after nearly a decade has renewed its focus on the Marcellus Core Fairway Expansion project in West Virginia, where production is more expensive. The Columbia Gas index, a key indicator of New England prices, rose to $3.14/mmBtu in the week ended 29 December, up by 16pc from a year earlier and 76pc higher than two years prior. The TC Energy-owned Columbia Gas Transmission system in November launched an open season for up to 483mn cf/d of natural gas transportation capacity, aiming to meet rising demand from data centers and power generation in the Columbus, Ohio, area. The Leidy Line index, a bellwether for Appalachian spot prices, averaged $2.76/mmBtu in January-November this year, 75pc higher than a year prior and 65pc above two years earlier. Argu s forward curve data from 29 December showed Leidy Line prices for January-March 2026 at $3.83/mmBtu. Such impact on prices, however, may not hit until 2027 because of delayed permitting. The Federal Energy Regulatory Commission (FERC) has taken steps to provide greater flexibility and expedite installation of new natural gas infrastructure . The agency in December directed PJM to adopt new interconnection rules to speed large-load projects and improve reliability, driven by geopolitical tensions to build high-performing AI models in comparison with international competitors. "Clarifying new rules will help release the bottleneck of large load investments across the PJM footprint," FERC chair Laura Swett said. Still, uncertainty about over-investment lingers. AI-driven demand may not fully materialize, and ratepayers could face higher costs , according to a study by several environmental groups. The US Energy Information Administration expects national power generation to increase by 2.4pc in 2025 and 1.7pc in 2026, with recent adjustments reflecting slower-than-expected large-load additions, according to the agency's monthly Short-Term Energy Outlook . Historically, northeast US hubs trade at discounts to the US benchmark Henry Hub because of pipeline constraints. But as local gas loads grow, those discounts could narrow, especially in shoulder months, although winter volatility will remain weather-driven. By Angelica Ruzanova Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Viewpoint: EU policy to boost Asia spec tanker demand

25/12/30

Viewpoint: EU policy to boost Asia spec tanker demand

London, 30 December (Argus) — EU legislation and new biofuels mandates should drive up 2026 demand for specialised tankers to move biofuels and renewable feedstocks from Asia-Pacific. This could offset any loss in US demand because of new terms in its 45Z tax credit policy. Exports of biofuels and feedstocks to Europe make up the bulk of long-haul demand for specialised tankers in Asia-Pacific. This trade should grow in 2026 when EU states implement the revised renewable energy directive (RED III). But many of the EU's largest biofuels consumers — including Germany, France, Italy and Spain — missed the 21 May 2025 deadline, and some have pushed back launch dates to 2027, which may limit the export surge that market participants were forecasting for 2026. Germany's new legislation should offer partial support. As the EU's largest biofuels consumer, its RED III transposition is pivotal. The German cabinet approved legislation to implement the EU's RED III into national law on 10 December, including provisions to end double-counting of advanced biofuels made from waste products, such as used cooking oil (UCO) or tall oil. This would require a much higher amount of physical biofuels to reach the same level of greenhouse gas (GHG) credits, driving up consumption. The bill still needs to pass through Germany's lower and upper parliaments for debate, meaning it is unlikely it will pass into law until later in 2026. But the abolition of double counting will apply to the entire compliance year, so it will be retroactive to 1 January. Hydrotreated vegetable oil (HVO) is the primary way to reach blending targets, because ethanol and biodiesel have strict blend walls limiting any sizeable jump in consumption. Higher HVO demand will probably require a rise in imports from Singapore, given the EU has anti-dumping duties on US and Chinese product. This will buoy demand for specialised tankers in southeast Asia in 2026, although a larger demand rise will depend on RED III implementation across the bloc. Fading US incentives New terms of the US' 45Z tax credit scheme, which will only incentivise biofuels produced using feedstocks from the US, Canada or Mexico from 1 January 2026, have already weighed on imports from Asia-Pacific. Some wider trade should continue as certain biofuels producers buy feedstocks to produce for export markets. Prices of north American feedstocks should eventually be pushed up to parity with other feedstocks, making the latter competitive in US markets even without the 45Z. While this would kick out exports from Asia-Pacific again, these dynamics will take some time and will probably leave flows reduced in the early months of 2026. US demand for biofuels and feedstocks from Asia-Pacific had tapered off in 2025, meaning further losses in exports should be easily offset by growth in trade to Europe — supporting specialised tanker rates. Around 43pc of the 15.2mn t of biofuels and renewable feedstocks exported from Asia-Pacific in 2025 headed to Europe, and only around 13pc to the US, Kpler data show. This means a loss in exports to the US could be easily offset by growth in European demand. If exports to the US dropped by 50pc in 2026 to just under 1mn t, there would need to only be a 15pc jump in exports to the EU, to around 7.5mn t, to keep overall exports from Asia-Pacific flat on the year. By Leonard Fisher-Matthews Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Viewpoint: Northeast diesel faces 2026 supply risks

25/12/30

Viewpoint: Northeast diesel faces 2026 supply risks

Houston, 30 December (Argus) — The US northeast diesel and heating oil market enters 2026 with lingering supply vulnerabilities despite recent improvements in flows. While imports of conventional fuels have resumed, structural constraints and global dynamics suggest that volatility will remain a defining feature in the coming years. Inventories of ultra-low sulphur diesel (ULSD) and ultra-low sulphur heating oil (ULSH) at the southern US Atlantic coast fell to the lowest level in more than 11-years this summer at 7.67mn bl. That pulled barrels sourced out of the US Gulf coast via the Colonial pipeline away from the line's final destination in the US northeast. New York Harbor's dependence on imports will persist due to limited refining capacity. While Canadian and Mexican flows improved late in 2025, upcoming refinery maintenance in Canada and operational uncertainties at Mexico's Olmeca refinery could disrupt supply in early 2026. Canadian refiner Suncor began 15 weeks of maintenance on 11 December at its 137,000 b/d Montreal refinery in Quebec, according to an announcement filed with Association industrielle de l'Est de Montreal, a near-term risk for US northeast markets. US imports from Canada nearly halved on the month in October, according to Vortexa ship-tracking data, partially caused by a turnaround at Irving Oil's 320,000 b/d St John refinery that ended in November. Following the turnaround, US Atlantic coast imports of ULSD and ULSH were 134,000 b/d, nearly double the level from a year earlier. Multiple cargoes came from Irving's St John refinery, according to Kpler ship-tracking data. But upcoming refinery work may once again come into play. Mexico's state-owned Pemex's 340,000 b/d Olmeca refinery recently resumed exports to the US after a near six-month period of zero loadings. Olmeca was initially highlighted as a crucial element in the Mexican government's strategy for road fuel self-sufficiency. But Pemex has also explored profitable ULSD export opportunities as local infrastructure has had difficulties absorbing the road fuel output from the Olmeca facility. Medium-range tanker BW Wren loaded around 300,000 bl of ULSD at the Dos Bocas port on 22 November and discharged throughout the southern US Atlantic coast, according to Kpler data. European diesel demand, amplified by sanctions on Russian products, kept open the US arbitrage to the Amsterdam-Rotterdam-Antwerp (ARA) hub for much of 2025. If this trend continues, Gulf coast exports to Europe could again constrain diesel flows to the Atlantic coast. In the longer term, Nigeria's planned Dangote refinery expansion — scheduled for 2028 — may ease European demand for US barrels, but competition for supply will remain intense until then. Even though the US Atlantic coast remains heavily reliant on domestic and imported cargoes, the fungibility of diesel and heating oil grades provides leeway for sourcing these barrels. In mid-December, stockpiles of ULSD and ULSH at the central US Atlantic coast were down by 27pc on the year at 12.8mn bl, US Energy Information Administration data shows. Cash differentials that trade against the underlying Nymex basis — often a benchmark for regional demand — fell to 14-month and two-year lows during this period. Weaker demand for conventional diesel and heating oil in the New York region is partly driven by the growing availability and market share of B99 biodiesel. Three states across the northeast, including New York, are actively promoting biofuels adoption through legislative measures, tax incentives and infrastructure investments aimed at reducing emissions in heating systems and commercial transportation. The state of New York this year doubled its heating oil blend mandate to 10pc biodiesel (B10), while Connecticut and Rhode Island have similar B10 and B20 mandates, respectively. While biofuels help offset reduced inventories of conventional fuels, New York Harbor B99 biodiesel differentials to heating oil have traded at a premium for the first quarter 2026 because of feedstock and supply constraints, weaker credit incentives and policy uncertainty. Federal biofuel blending mandates for 2026 and 2027 remain unsettled, leading some producers to idle operations heading into the new year as they await clearer direction. In the short term, softer demand and renewed import flows suggest improved supply security for the US Atlantic coast. However, evolving federal policies and shifting global dynamics ensure that volatility will remain a hallmark of the region's diesel market. By Craig Ross and Blake Del Papa Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Viewpoint: Bruised US biomethane sellers pivot to Asia

25/12/30

Viewpoint: Bruised US biomethane sellers pivot to Asia

Houston, 30 December (Argus) — US biomethane sellers are increasingly looking to Japan and Singapore for niche opportunities in the year ahead, as policy roadblocks hinder demand closer to home. Japanese gas utilities are targeting a 1pc share of renewable methane sales by 2030 amounting to around 180mn Nm³/yr. While they are mostly targeting e-methane made from low-carbon hydrogen, the relatively lower cost and abundance of US biomethane makes it an attractive bridge for companies trying to navigate the energy transition. Osaka Gas has signed an agreement with BP subsidiary Archaea Energy to procure 26,000 Nm³ of biomethane from landfill gas that will be liquefied at the Freeport LNG terminal along the US Gulf Coast and shipped to Kansai. More deals between Japanese utilities and US biomethane producers are likely. Singapore launched a 300MW biomethane import trial in September and opened further applications in December for at least 200MW of new data center capacity, of which at least 50pc should powered by "eligible green energy pathways" including biomethane. But these are relatively slim pickings against a backdrop of US regulatory delays that may extend well into 2026. Slow horses While biomethane was incorporated into the new 45Z federal tax credit, offering a sliding subsidy scale depending on carbon intensity, specific guidance on how negative emissions would be treated remain elusive. While the Treasury Department submitted a proposal to the White House in December, regulators could spend months writing the final rules. Changes to the 45Z tax credit passed into law this summer "may" allow fuels from animal manure to claim negative emissions in future years, but that treatment still needs final sign-off by regulators. A similar story is playing out with the US Environmental Protection Agency's (EPA) renewable fuel mandates for 2026 and 2027, for which market participants may now have to wait until the first quarter next year. Biomethane makes up the vast majority of program credits in the cellulosic D3 Renewable Identification Number (RIN) category, and EPA initially proposed revising down the 2025 requirement to 1.19bn RINs from 1.38bn and setting 2026 and 2027 requirements at 1.30bn and 1.36bn RINs, respectively. The less-ambitious mandates reflect what the EPA sees as the market reaching a saturation point. Biomethane made up 86pc of all on-road fuel used in natural gas vehicles in 2024, according to industry association The Transport Project. Usage is closer to 97pc in California, the largest US market, where the fuel benefits from additional Low Carbon Fuel Standard credits. Some data suggest that EPA is underestimating future consumption growth, providing fodder for inevitable future court cases about the legality of these cellulosic targets. Industry has already sued the agency over retroactively slashing the 2024 target by 7pc, citing a lack of supply. Indeed, revised RIN data up to October 2025 shows cellulosic generation could be on track to exceed the original 1.38bn target. More natural gas fueling stations are also being built and could reach 1,400 going into 2026, the Transport Project said. Still, growth in the natural gas vehicle fleet and fueling stations has paled in comparison to renewable natural gas (RNG) supply growth, which has averaged around 24pc/yr since 2015, according to EPA. Compressed natural gas dispensers thus have more power to negotiate with producers, who have reported being asked for 30pc of the D3 RIN value — up from around 20pc previously — to pump the gas, as well as demanding a similar cut of the 45Z credit. This is having a knock-on effect for suppliers seeking alternatives in voluntary sectors, where buyers are more price sensitive than those in mandatory markets and can drive a harder bargain. Prices of Renewable Thermal Certificates (RTCs) — the environmental attributes associated with biomethane — have therefore failed to keep up with D3 RINs, falling from 60pc of their value in September to 50pc in December. Sellers are worried that even if RIN prices recover in early 2026 once the regulatory haze clears, a corresponding rise in RTCs may not materialize because of persistent oversupply. Several planned RNG projects have now been put on the backburner as a result, and producers are being forced to think creatively about accessing international markets. But the policy pendulum has swung away from them in many of those markets. One battle after another Many had pinned hopes on the International Maritime Organization adopting decarbonization targets for shipping in October, but the delay for at least a year could slow biomethane adoption in this area. EU member states imposing stronger Renewable Energy Directive III mandates for next year will fuel biomethane demand in the region. But many EU members, including Germany , are stipulating connection to the EU grid for imports. This aligns with conditions that will be imposed under the Union Database , the oft-delayed mandatory traceability tool for renewable fuels into the EU that is now targeted for a summer 2026 launch. While talks are ongoing to allow cooperation frameworks for product arriving from outside the bloc, progress so far has been slow. Protectionist measures could also hit US exporters closer to home. Canada is inviting feedback on whether to implement a credit multiplier for domestic fuel under its Clean Fuel Regulations program to help producers combat the 45Z and RIN incentives south of its border. A faint silver lining for sellers in 2026 does come at the state level, with New Mexico set to start its own low-carbon fuel standard scheme in April, which will boost RNG incentives in transport. But New Mexico's biomethane demand will remain relatively small. The industry is pinning its hope on Asian demand — and further lobbying in Washington — to recover from the bruises suffered in 2025. By Ammo Parmar Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Viewpoint: Brazil likely to delay biodiesel blend hike

25/12/30

Viewpoint: Brazil likely to delay biodiesel blend hike

Sao Paulo, 30 December (Argus) — Brazil's biodiesel sector anticipates that a planned March increase in the blend mandate to 16pc from 15pc will be delayed because technical feasibility tests are not expected to be completed until the second half of the year. The mines and energy ministry MME in November outlined a two-phase schedule for testing higher biodiesel blends. The first phase will evaluate blends of up to 20pc, with completion expected between August 2026 and January 2027, while the second phase will focus on blends of up to 25pc, scheduled for testing from August to December 2027. Brazil's Future Fuels Law proposes annual increases of 1 percentage point in the mandatory biodiesel blend, reaching 20pc by 2030. The government also intends to increase the biodiesel blend to 25pc by 2035, but this is a future goal and not yet mandatory. The initiative aims to decarbonize the transportation sector by fostering the production and consumption of advanced biofuels. Most biodiesel producers expect feasibility tests to follow the timeline set by the ministry, with no early completion likely. Consequently, they are keeping production plans aligned with the current mandate. To minimize risk, producers have avoided purchasing additional feedstocks for a 16pc blend and are adjusting profit expectations for 2026. Brazil's inflation is also a factor in the delay for a 16pc blend. In February, the national energy policy council (CNPE) postponed raising the biodiesel mix to 15pc from 14pc until August, citing concerns that biofuel costs might drive higher inflation. With 2026 as an election year in Brazil, the biodiesel blend mandate will likely slide to the bottom of the government's priority list. Maintaining the current 15pc mandate in 2026 could eliminate about 592mn litres (10,220 b/d) of biodiesel demand, resulting in 10.47bn l of total demand, according to estimates from state-owned energy research firm EPE. Biodiesel sales totaled 9.02bn l in 2024, according to oil regulator ANP. For 2025, EPE expects a 9.6pc increase to 9.89bn l. If the 16pc mandate takes effect in March 2026 as scheduled, annual demand could climb nearly 12pc to 11.06bn l. Long-term optimism Biodiesel producers are investing in capacity expansions and new plants, eyeing long-term profits, despite prospects of blend hike delays in the short term. Brazil's current biodiesel production can supply up to 15.5bn l/y at full capacity. Investments in new plants and units in various regions should increase capacity to 18.8bn l by 2028, according to ANP. The current biodiesel production capacity could already meet a blend exceeding 25pc in 2026, considering the diesel consumption projection from EPE. However, in view of the hike in diesel consumption and increase of 1 percentage point/yr in the biodiesel blending mandate until 2035, biofuel production capacity would need to exceed 22.2bn l/yr, EPE studies show. The sector's optimism is reinforced by tests already conducted in the market that have proved the possibility of using higher levels of biodiesel. Studies that make a case against increasing blend levels do not follow appropriate protocols, sources familiar with the matter said. Producers are also investing in certifications to export biodiesel. Europe is the main target market, given its higher demand compared to regions that already produce their own biofuels. Brazilian biodiesel exports totaled more than 83mn l in January-October 2025, up from 67mn l in 2024, according to data from the industry and trade ministry. By Natalia Dalle Cort Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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