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Latest market news

Brazil inflation falls below ceiling in November

  • Market: Agriculture, Biofuels, Electricity, Fertilizers, Oil products
  • 10/12/25

Brazil's headline inflation decelerated to an annual 4.46pc in November, the first time it stands below the central bank's 4.5pc ceiling since September 2024, according to national statistics agency IBGE.

Annualized inflation decelerated from 4.68pc in October and 5.17pc in September. On a monthly basis, inflation accelerated to 0.18pc in November from 0.09pc in October.

Housing costs accelerated to an annual 6.54pc in November from 4.36pc in October. Power costs accelerated to 11.41pc in November from 3.11pc in October. Brazil maintained power tariffs at R4.46 (¢0.81)/100MWh in November, as below-average rainfall for the period partially hindered hydroelectric generation.

Transportation costs decelerated to an annualized 3pc from 3.69pc in October. Motor fuel costs decelerated to 2.55pc in November from 2.72pc a month prior, with gasoline and diesel prices decelerating to 2.22pc and 2.01pc from 2.49pc and 2.11pc, respectively. Ethanol prices increased by 6.2pc in November, accelerating from 5.59pc a month earlier, while compressed natural gas costs further contracted by 4.86pc from a 4.28pc contraction in October.

Airplane ticket costs decelerated to an annual 0.13pc in November from 9.75pc in October.

Food and beverage costs decelerated to an annual 3.88pc from a 5.5pc increase in October. Soybean oil prices decelerated to 8.89pc in November from 17.41pc a month earlier.

Brazil's target interest rate remained at 15pc in November. The central bank will likely keep it steady through year-end to push inflation closer to the government's main goal of 3pc. The bank's weekly Focus report — a forecast bulletin with market expectations for macroeconomic indicators — estimates a 4.4pc overall inflation rate for 2025.

By Maria Frazatto

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10/12/25

Netherlands slashes 2026 biomarine mandate

Netherlands slashes 2026 biomarine mandate

London, 10 December (Argus) — The Netherlands' government will cut GHG reduction mandates for international maritime and inland shipping supplies from the proposed draft earlier this year , according to a communication from the ministry of infrastructure and water management sent to market participants and seen by Argus , citing delays in Belgian transposition causing concerns of an uneven playing field for fuel suppliers. The statement confirmed that the new renewable energy directive (RED) III mandates will come into effect on 1 January, and will apply retroactively from that date if passed later. Maritime fuel suppliers will be subject to a 2.9pc GHG reduction target in 2026 compared with 3.6pc initially, 0.9pc of which will be a flexible credit allowance that can be fulfilled by overcompliance in other sectors. The inland shipping obligation will be reduced to a 2.5pc greenhouse gas (GHG) reduction target from a previously announced 3.8pc, with 0.5pc flexible credit allowance. The statement added that obligations from 2027 onwards will apply as previously announced in the draft bill. The previously announced ban on 9B feedstocks for international maritime is to remain in place, with the Netherlands to explore whether the overall Annex 9B biofuels cap can be increased to create leeway. Despite an initial agreement between Belgium and the Netherlands to align on marine targets under RED III, some divergence has already emerged as the Netherlands will treat 9B feedstock biofuels as fossil volumes under the maritime obligation — while Belgium may count such volumes as zero when calculating the overall fuel supply. Initial reactions from market participants pointed to expectations of some marine fuels demand shifting from Dutch ports towards neighbouring ports, as the German cabinet passed a version of RED III legislation today that excludes international maritime from the country's targets. Belgium has also yet to finalise its RED III transposition, with updates to come following the conclusion of a public consultation on 14 November. By Hussein Al-Khalisy Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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CEE, SEE yearly power CBC auction costs flip

10/12/25
News
10/12/25

CEE, SEE yearly power CBC auction costs flip

London, 10 December (Argus) — Yearly net power cross-border capacity (CBC) costs switched for key directions in central and southeast Europe for 2026, reflecting structural changes to flows. Nearly 400MW in the Greece-Bulgaria auction sold at €7.56/MWh — the highest for the direction since Jao platform auctions began in 2019. And it cleared €5.87/MWh above the opposite direction, switching from a €0.76/MWh discount for 2025. This was the first time the Greece-Bulgaria direction cleared above the reverse, reflecting this year's changes to cross-border flows. Bulgaria has net exported just 2MW to Greece in the year to 10 December, well below the 302MW five-year average for the period, with Greece net exporting to Bulgaria in seven of the 11 full months of 2025. Greece has net exported 250MW to neighbouring countries, switching from 79MW of net imports in January-November 2024. Greece's net exports have been underpinned by renewable additions. The country's solar capacity was 9.9GW at the end of September, up by 21.5pc on the year, while wind capacity has risen by 4pc to 5.44GW. Wind and solar output have averaged almost 2.7GW in 2025, accounting for 46pc of Greece's mix, up by two percentage points on the year. Greece aims to have phased out lignite-fired generation by the end of 2026 and has already started replacing this with renewables and high-efficiency combined-cycle gas turbines (CCGTs). The 810MW Komotini CCGT is undergoing testing and expected to be operating commercially next year. Greece's first battery energy storage systems (Bess) will start operating next year — PPC has 146MW under constriction . Expectations that Greece will maintain net exports next year are also reflected in forward values, with the Greek 2026 contract most recently assessed at €95.15/MWh — €6.75/MWh below Bulgaria and at a €8.95/MWh discount to Romania and Hungary. Net CBC costs also flipped on the Romania-Hungary border. The 350MW Romania-Hungary CBC for 2026 sold at €3.58/MWh, its lowest in four years, but €1.07/MWh above the opposite direction, switching from a €0.60/MWh discount for 2025. This is despite Romania having net imported 592MW from Hungary in 2025, up by 248MW on the year and the most for the period in more than five years. That has brought overall Romanian net imports to 736MW, up by 313MW on the year and also a more than five-year high. The Romanian 2026 contract has regularly switched between a premium and a discount to Hungary since assessments began, having been at discount on 23 September-4 December, before being assessed at parity in the past three sessions. Romania has negotiated with the EU postponement of its lignite phase-out to the end of 2029 , pushing back from the end of next year. Romania added 1.23GW of solar capacity over the first 11 months of 2025, up from 303MW in all of 2024. Solar capacity stood just above 3GW at the end of November, while solar output has averaged 327MW in 2025, up by 75MW on 2024. But just 41MW of wind has been added this year, down from 69MW in 2024. Romania has not added any thermal capacity in recent years, while commercial operations at its long-awaited 430MW Iernut CCGT — previously expected at the end of this year — have been pushed back to the second quarter of 2026. The 1.75GW Mintia CCGT is due to come on line by the end of next year. Romania will also enter 2026 with hydro stocks at surpluses to a year earlier and the five-year average. Reserves were at 2.15TWh, or 73pc of stored energy potential, in week 49 — 308.2GWh up on the year and 130GWh above the five-year average. And new trends could be emerging in other CBC auctions. The 2026 CBC auctions on Serbia's borders with Bulgaria and Hungary close on 15 December, with 150MW and 200MW, respectively, available. For 2025, the 150MW Bulgaria-Serbia direction sold at €2.96/MWh, or €0.86/MWh above the reverse direction, while the 200MW Serbia-Hungary cleared at €4.40/MWh, almost the same as the reverse. But based on the forward market, the former could flip for 2026, while the latter could be sold at a large premium to the opposite. Argus most recently assessed the Serbian year-ahead at €96.85/MWh — a €5.50/MWh discount to Bulgaria and €7.25/MWh below Hungary. Risk from implementation of the EU's carbon border adjustment mechanism (CBAM) — centred on unclear methodology and delayed payments — will reduce cross-border demand from strong importers such as Hungary, creating oversupply in the six western Balkan countries, including Serbia, market participants have told Argus . Uncertainty around CBAM has already led Turkish transmission system operator Teias to delay the 2026 Turkey-Bulgaria CBC auction . By Apostolos Tsarikas Regional net CBC costs €/MWh Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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German cabinet passes EU RED III

10/12/25
News
10/12/25

German cabinet passes EU RED III

Hamburg, 10 December (Argus) — The German cabinet on 10 December approved legislation to implement the EU's Renewable Energy Directive (RED III) into national law. This will adjust the greenhouse gas (GHG) reduction quota and abolish double counting of advanced fuels from 2026. But it is unlikely to pass remaining legislative processes in time for the EU's 1 January deadline. The bill passed by the cabinet largely follows a draft dated 29 October that was leaked in November. The overall quota level will rise to 59pc by 2040. Aviation and marine fuels are exempt from the quota obligation. The law will end the eligibility of palm oil products, most notably palm oil mill effluent (Pome), for compliance towards the GHG quota. This exclusion, and a requirement for fuel producers to allow on-site audits, will not come into effect until 2027, leaving 2026 as a transitional year. The end of double counting for advanced biofuels removes a key point of market uncertainty. Under current rules, advanced biofuels can be counted as twice their energy value towards the GHG quota, provided the minimum sub-mandate for advanced fuels has been met. But the change to end double counting will apply to the entire compliance year and all subsequent years, meaning it will be retroactive to 1 January. The only exception is for fuels supplied prior to 1 January 2026. The law will enter into force on the second day after publication in the Federal Law Gazette, with selected sections taking effect a day earlier for procedural reasons. Before that can happen, the bill must be submitted to the Germany's lower and upper parliaments for debate. The lower house's approval is not required, and the upper house could initiate changes. The bill can only be submitted to the Federal President for his signature once the upper house has given approval. This process is likely to conclude in the first quarter of 2026. Changes to sub-quotas, RFNBOs, biomethane The sub-mandate for advanced biofuels, made from feedstocks listed in Annex IX of RED III, will rise to 9pc by 2040. The mandate for renewable fuels of non-biological origin (RFNBOs) — such as e-fuels and green hydrogen — is higher will rise to 2.5pc of an obligated company's energy mix in 2034, and then to 8pc in 2040. The penalty for non-compliance is €120/GJ. Imported biomethane can be counted towards the GHG quota, provided it meets certain conditions, such as a connection to the EU gas grid. The baseline emissions value is 94kg CO2e/GJ, aligned with the rest of the EU. The registration deadline with the main customs office is 1 June. The market for GHG certificates reacted immediately. Other certificates for 2025 are trading around €20/t CO2e higher than the previous day, and prices for 2026 certificates are rising. Prices for 2025 certificates are rising, although they are unaffected by the change. They are seen as a substitute for 2027 certificates because excess 2025 compliance will be carried over. Hydrotreated vegetable oil (HVO) could now play a central role in meeting the GHG quota, which can influence certificate prices. Demand for advanced HVO could increase significantly, as it can be counted without limit towards the GHG quota as a blending component and as a pure fuel and can be used in most of the existing diesel vehicle fleet. The end of double counting could increase demand for non-advanced biodiesel grades, such as rapeseed-based RME and used cooking oil-based Ucome. Although the eligibility of these is capped to a certain percentage of a company's energy mix, this limit has not always been fully utilised in the past. by Max Steinhau and Chloe Jardine Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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Urea market grapples with EU’s CBAM as revision delayed

10/12/25
News
10/12/25

Urea market grapples with EU’s CBAM as revision delayed

Amsterdam, 10 December (Argus) — A considerable lack of clarity remains as to how the urea market will trade following the rollout of the EU's carbon border adjustment mechanism (CBAM) next month, with the market still waiting on confirmation from the EU regarding key aspects of the charge calculation. Market participants are split as to how the market will react to the additional carbon-related costs associated with the CBAM, and under which trade terms — whether fob, cfr, cif or fca — the most liquidity will be found. No clear consensus has emerged as to which part of the supply chain will bear the increased costs. Some expect importers to absorb most of the CBAM charge when the import market is in season, while others think that the levy will weigh on fob prices from origin markets. Some expect the cost to be spread across producers and importers. The CBAM charge depends heavily on individual plants' reported carbon emissions per tonne of urea produced, with lower fees for newer, more-efficient plants that emit less carbon and are less susceptible to unplanned outages. Plants' reported emissions vary widely, and this translates into a similarly wide carbon levy range. The fee could be as low as €15/t ($17/t), or up to as high as €70-80/t and beyond for some origins. Market participants are still waiting for the EU to confirm some key aspects of the CBAM charge calculation, even though it is set to be implemented in three weeks' time. The costs will be partly based on average quarterly prices of emission trading scheme (ETS) contracts, which adds another layer of complexity to risk management for importers. At current ETS prices, imports from Egypt — the top urea supplier to European markets — are expected to face an average carbon levy of around €40/t. But this average comes from a wide range, given that Egypt's multiple urea plants have varying rates of carbon efficiency. Product from central Asia — another key supply region — will face higher charges than Egyptian supplies. Urea production plants in Turkmenistan and Uzbekistan are older and less-energy efficient than plants in Egypt, according to trading firm Alkagesta's head of fertilizers, Vusal Muradov. Product from some central Asian plants will likely average a considerably higher CBAM cost at current rates, and European buyers will increasingly prioritise lower-emissions supply chains, Muradov said. The latest delay to the mechanism's planned revisions has not helped matters. The European Commission on Tuesday confirmed a delay to legislative proposals to revise the CBAM, which had originally been scheduled for 10 December. Officials have yet to confirm 16 December as the new date for the proposals to be presented. One major European importer speculated, likely out of hope, that the bloc may water down the CBAM charges on urea. The impending rollout of the CBAM prompted a surge in urea prices into Europe at the end of October and early November, with granular urea trading at above $500/t fob Egypt as importers scrambled to clear product through customs for their warehouses before CBAM charges are applied. The spike in north African prices saw importers look to atypical origins, with over 300,000t of urea from Nigeria, Oman, Malaysia, Qatar and China set to arrive in Romania, the UK and Turkey in November-December so far. By Harry Minihan Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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Japan’s Hokkaido approves Tomari nuclear restart

10/12/25
News
10/12/25

Japan’s Hokkaido approves Tomari nuclear restart

Osaka, 10 December (Argus) — Japan's Hokkaido prefecture has approved the restart of Hokkaido Electric Power's (Hepco) Tomari nuclear power plant, removing the final hurdle to restarting the first reactor in the northernmost prefecture since the 2011 Fukushima nuclear disaster. Hokkaido governor Naomichi Suzuki officially approved the restart of the 912MW Tomari No.3 reactor on 10 December, nearly two weeks after stating on 28 November that the use of nuclear power remains a practical option for the time being. His decision was supported by four local authorities — Tomari village, Kyowa town, Iwanai town and Kamoenai village — whose consent is also required to resume operations at the Tomari plant. Approval from local governments is essential before any nuclear reactor restart in Japan, even when reactors meet stricter safety standards designed to prevent a repeat of the Fukushima-Daiichi reactor meltdown following the 2011 earthquake and tsunami. The approval means the Tomari No.3 reactor is likely to restart once reinforcement work is completed, as the unit already received a safety clearance from Japan's nuclear regulation authority (NRA) in July. Hepco hopes to restart the reactor as early as possible in 2027. The Tomari plant is Hepco's sole nuclear facility, comprising the 579MW No.1 and No.2 reactors in addition to No.3 unit. The No.1 and No.2 reactors are still undergoing the NRA safety inspections. Hepco has been without nuclear power since May 2012, relying on thermal generation instead, which has increased costs. The utility consumed 1.78mn t of coal over April-September, up by 9.6pc from a year earlier, while oil usage edged up by 0.9pc to 3,884 b/d. LNG consumption fell by 61pc to 85,000t during the period, mainly because of maintenance at a gas-fired plant. Hepco expects household electricity rates under regulated tariffs to fall by around 11pc following the planned restart of Tomari No.3 reactor. For non-regulated tariffs, overall rates are projected to decline by an average of 7pc, including roughly 11pc for low-voltage customers and about 6pc for high- and extra-high-voltage users. 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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