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Japan’s election leaves energy policy in limbo

  • Spanish Market: Coal, Electricity, Hydrogen, Natural gas
  • 28/10/24

Japan's ruling Liberal Democratic Party (LDP) and its coalition partner Komeito were heavily defeated in the country's election on 27 October, and this is likely to leave the country's energy policy in limbo, especially for nuclear power.

The LDP's first defeat in 15 years means no single party holds the majority of seats to govern parliament now. Forming a fresh alliance, if not a coalition government, would be essential for any party, but depending on who teams up with whom, the country's energy policy could deviate from its present course, especially because of the parties' different approaches to nuclear power policy.

The LDP and Komeito together won 215 seats, falling short of the 233 seats needed to hold the majority and take control of parliament. The LDP is now faced with the choice of seeking other parties to join its coalition, or to remain as a minority in the government. Komeito could also face challenges in establishing a new structure, as Keiichi Ishii, the leader of the party, was defeated in the election.

"We have to take the outcome seriously," said Shigeru Ishiba, the current prime minister and the LDP's governor, indicating he intends to take immediate action for political reforms.

But the LDP's weakened position may make it difficult to push for its pro-nuclear energy policy to ensure the country's energy security, economic growth and decarbonisation as part of its 2050 net zero emissions goal.

The second-largest opposition party with 38 seats, the Japan Innovation Party (JIP), also called Ishin, holds a similar stance on nuclear policy as the LDP. But it is unwilling to align itself with the current coalition government, because of distrust against the LDP resulting from a political fund scandal that was part of the reason for the current political turmoil within the LDP. JIP is not planning to form a coalition with any parties, said its leader Nobuyuki Baba.

The Democratic Party for the People, also named Kokumin, which quadrupled its number of seats to 28, has also promoted the use of domestic nuclear and renewable power sources. Forming an alliance with Kokumin may keep the LDP's nuclear power policy in place. But Kokumin's leader Yuichiro Tamaki has also declined to form a coalition with the LDP and Komeito, although he said that co-operating on a specific agenda could be possible.

The biggest opposition party, the Constitutional Democratic Party of Japan (CDPJ), which won 148 seats, will step up efforts to co-operate with other opposition parties to change the government, according to the party leader Yoshihiko Noda. Noda served as prime minister of Japan and president of the then democratic party of Japan from September 2011 to December 2012.

The CDPJ pledged in its manifesto to not build a new nuclear fleet or expand capacity, while pushing for a swift phase-out of existing reactors. The party aims to cut Japan's greenhouse gas (GHG) emissions by more than 55pc by 2030 against 2013 levels, and ensure carbon neutrality by 2050, while lifting the share of renewable energy in its power mix to 50pc by 2030 and 100pc by 2050.

The climate goal by the CDPJ is ambitious compared with the LDP's strategies so far. Japan's strategic energy plan, which was updated by the LDP-led government in 2021 and is now under review, targets a 46pc reduction in the country's GHG emissions by the April 2030 to March 2031 fiscal year from its 2013-14 level, in line with its goal to have net zero emissions by 2050. The 2030-31 target assumes Japan relies on thermal generation for 41pc of its electricity demand, along with a 36-38pc share for renewables, 20-22pc nuclear power and 1pc hydrogen and ammonia. 

A special diet session is scheduled to be held before 26 November to appoint the new prime minister. Following the LDP's defeat, it remains unclear if Ishiba, who was just sworn in on 1 October, will be re-elected despite his willingness to hold onto power.


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13/06/25

EPA proposes record US biofuel mandates: Update

EPA proposes record US biofuel mandates: Update

Updates with new pricing, reactions throughout. New York, 13 June (Argus) — President Donald Trump's administration today proposed requiring record biofuel blending into the US fuel supply over the next two years, including unexpectedly strong quotas for biomass-based diesel. The US Environmental Protection Agency (EPA) proposal, which still must be finalized, projects oil refiners will need to blend 5.61bn USG of biomass-based diesel to comply with requirements in 2026 and 5.86bn USG in 2027. Those estimates — while uncertain — would be a 67pc increase in 2026 and a 75pc increase in 2027 from this year's 3.35bn USG requirement, above what most industry groups had sought. The proposal alone is likely to boost biofuel production, which has been down to start the year as biorefineries have struggled to grapple with uncertainty about future blend mandates, the halting rollout of a new clean fuel tax credit, and higher import tariffs. The National Oilseed Processors Association said hiking the biomass-based diesel mandate to the proposed levels would bring "idled capacity back online" and spur "additional investments" in the biofuel supply chain. The EPA proposal also would halve Renewable Identification Number (RIN) credits generated from foreign biofuels and biofuels produced from foreign feedstocks, a major change that could increase US crop demand and hurt renewable diesel plants that source many of their inputs from abroad. US farm groups have lamented refiners' rising use of Chinese used cooking oil and Brazilian tallow to make renewable diesel, and EPA's proposal if finalized would sharply reduce the incentive to do so. Biofuel imports from producers with major refineries abroad, notably including Neste, would also be far less attractive. The proposal asks for comment, however, on a less restrictive policy that would only treat fuels and feedstocks from "a subset of countries" differently. And EPA still expects a substantial role for imported product regardless, estimating in a regulatory impact analysis that domestic fuels from domestic feedstocks will make up about 62pc of biomass-based diesel supply next year. The Renewable Fuel Standard program requires US oil refiners and importers to blend biofuels into the conventional fuel supply or buy credits from those who do. One USG of corn ethanol generates one RIN, but more energy-dense fuels like renewable diesel can earn more. In total, the rule would require 24.02bn RINs to be retired next year and 24.46bn RINs in 2027. That includes a specific 7.12bn RIN mandate for biomass-based diesel in 2026 and 7.5bn in 2027, and an implied mandate for corn ethanol flat from prior years at 15bn RINs. EPA currently sets biomass-based diesel mandates in physical gallons but is proposing a change to align with how targets for other program categories work. US soybean oil futures surged following the release of the EPA proposal, closing at their highest price in more than four weeks, and RIN credits rallied similarly on bullish expectations for higher biofuel demand and domestic feedstock prices. D4 biomass-diesel credits traded as high as 117.75¢/RIN, up from a 102.5¢/RIN settle on Thursday, while D6 conventional credits traded as high as 110¢/RIN. Bids for both retreated later in the session while prices still closed the day higher. Proposed targets are less aspirational for the cellulosic biofuel category, where biogas generates most credits. EPA proposes lowering the 2025 mandate to 1.19bn RINs, down from from 1.38bn RINs previously required, with 2026 and 2027 targets proposed at 1.30bn RINs and 1.36bn RINs, respectively. In a separate final rule today, EPA cut the 2024 cellulosic mandate to 1.01bn RINs from 1.09bn previously required, a smaller cut than initially proposed, and made available special "waiver" credits refiners can purchase at a fixed price to comply. Small refinery exemptions The proposal includes little clarity on EPA's future policy around program exemptions, which small refiners can request if they claim blend mandates will cause them disproportionate economic hardship. EPA predicted Friday that exemptions for the 2026 and 2027 compliance years could total anywhere from zero to 18bn USG of gasoline and diesel and provided no clues as to how it will weigh whether individual refiners, if any, deserve program waivers. The rule does suggest EPA plans to continue a policy from past administrations of estimating future exempted volumes when calculating the percentage of biofuels individual refiners must blend in the future, which would effectively require those with obligations to shoulder more of the burden to meet high-level 2026 and 2027 targets. Notably though, the proposal says little about how EPA is weighing a backlog of more than a hundred requests for exemptions stretching from 2016 to 2025. An industry official briefed on Friday ahead of the rule's release said Trump administration officials were "coy" about their plans for the backlog. Many of these refiners had already submitted RINs to comply with old mandates and could push for some type of compensation if granted retroactive waivers, making this part of the program especially hard to implement. And EPA would invite even more legal scrutiny if it agreed to biofuel groups' lobbying to "reallocate" newly exempted volumes from many years prior into future standards. EPA said it plans to "communicate our policy regarding [exemption] petitions going forward before finalization of this rule". Industry groups expect the agency will try to conclude the rule-making before November. The proposed mandates for 2026-2027 will have to go through the typical public comment process and could be changed as regulators weigh new data on biofuel production and food and fuel prices. Once the program updates are finalized, lawsuits are inevitable. A federal court is still weighing the legality of past mandates, and the Supreme Court is set to rule this month on the proper court venue for litigating small refinery exemption disputes. Environmentalists are likely to probe the agency's ultimate assessment of costs and benefits, including the climate costs of encouraging crop-based fuels. Oil companies could also have a range of complaints, from the record-high mandates to the creative limits on foreign feedstocks. American Fuel and Petrochemical Manufacturers senior vice president Geoff Moody noted that EPA was months behind a statutory deadline for setting 2026 mandates and said it would "strongly oppose any reallocation of small refinery exemptions" if finalized. By Cole Martin and Matthew Cope Proposed 2026-2027 renewable volume obligations bn RINs Fuel type 2026 2027 Cellulosic biofuel 1.30 1.36 Biomass-based diesel 7.12 7.50 Advanced biofuel 9.02 9.46 Total renewable fuel 24.02 24.46 Implied ethanol mandate 15 15 — EPA Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Japan’s Jera signs LNG supply agreements with the US


13/06/25
13/06/25

Japan’s Jera signs LNG supply agreements with the US

Singapore, 13 June (Argus) — Japanese power producer Jera said this week that it has signed multiple long-term LNG supply agreements with US partners over the past two months, to procure up to 5.5mn t/yr over 20 years. This includes 2mn t/yr from NextDecade and 1mn t/yr from Commonwealth LNG. It also signed non-binding interim agreements with Sempra Infrastructure for 1.5mn t/yr and with developer Cheniere for 1mn t/yr. The deals offer competitive pricing and flexible contract terms. All supply will be delivered on a fob basis priced against the US' Henry Hub, allowing Jera to optimise shipping routes and respond flexibly to domestic demand and market conditions, the company said. Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Law's sunset not an end for Argentina's renewables


13/06/25
13/06/25

Law's sunset not an end for Argentina's renewables

Buenos Aires, 13 June (Argus) — A law meant to increase renewable energy in Argentina will expire at the end of 2025 without meeting its target and with little hope of renewal, but other incentives may still bolster the sector. Law 27191, passed in 2015 to extend earlier legislation, called for renewable sources to reach at least 20pc of Argentina's energy mix by the end of its 2025 expiry. The legislation covers biogas, biomass, solar, wind and hydroelectric plants under 50MW of capacity. Renewables have expanded more than other technologies, increasing to 6,672MW of installed capacity at the end of last year from 381MW in 2003, but still far from the goal. Renewable sources accounted for 15pc of installed capacity at the end of 2024 and covered 16pc of demand, according to the state-owned energy wholesale company, Cammesa. New capacity is being added and renewables should come close to meeting the demand target — renewables covered 21pc of demand in April, according to Cammesa, and 572MW in new solar and wind capacity came online in June alone. But it is unclear what comes next as the government deregulates the economy and pulls back from market intervention. Marcelo Alvarez, head of the solar power committee for Cader, Argentina's renewable energy association, said that there is no indication six months before the law's expiration that it will be extended. "I do not think they are going to extend Law 27191," he said. "The government is not interested in anything that conditions or interferes with the free-market dynamic and [Law] 27191, with its model of quotas with fiscal incentives, goes against its ideological thinking." But the government's change in policy approach could help address some of the main infrastructure and economic problems that hampered the installation of more renewable sources. Argentina has some of the world's best solar and wind potential, according to Alvarez, but it does not have the transmission lines to get power from new plants into the grid. "The system is basically saturated and we are really going to hit a wall if we do not start to build new lines now," said Alvarez. President Javier Milei's government announced in late May a plan for new transmission lines, but the private sector would need to do the work. The plan includes 15 500kV lines that would cover 5,610km and increase the existing grid's scope by 38pc at a cost of $6.6bn. The government is also moving forward with a tender started by the previous administration for a battery energy storage system (BESS) for 500MW, one of the largest in Latin America. The winning bids should be announced in August, according to the most recent timeline. The critical point for any project is financing, which Alvarez said remains difficult and expensive in Argentina despite recent changes. He said that interest rates for a 100MW project in Argentina are around 8pc, while in neighboring Chile they can be as low as 3pc. The Milei government has started to tackle major issues, bringing inflation down to 47.4pc annualized through April from nearly 300pc in 2024, eliminating regulations on financing and exports and reducing currency controls. It also has in place an investment and legal stability mechanism, known as Rigi, to attract large-scale investment for projects over $200mn. It has awarded one power project so far, the 305MW El Quemado solar park planned by state-owned YPF. "The cost and length of financing are major obstacles," Alvarez said. "It is going to take time to lower the cost of capital." By Lucien Chauvin Argentina's renewable power capacity MW Technology End 2024 Apr 25 Wind 4,319 4,342 Solar 1,673 1,909 Small hydro 524 524 Biogas/biomass 155 192 — Cammesa Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Limited prompt impact on LNG from Israel-Iran conflict


13/06/25
13/06/25

Limited prompt impact on LNG from Israel-Iran conflict

London, 13 June (Argus) — Israel has halted production at two of its major gas fields and cut pipeline exports to Egypt, but resulting LNG demand may only come later this summer when Egypt builds out its LNG import capacity. Israel's Karish and Leviathan fields have stopped production following a government order issued in the wake of Israeli airstrikes on Iran . Israel's energy ministry today said it expects the minister to declare a state of emergency in the gas sector. Pipeline exports to Egypt and Jordan have since dropped sharply, market participants said, resulting in Egypt cutting gas supply to urea plants as it prioritises gas for power generation. But Egypt has access to only one LNG import terminal at present — the 170,000m³ Hoegh Galleon floating storage and regasification unit (FSRU) at Ain Sukhna. Three carriers were holding offshore today waiting to deliver, and the terminal is importing at maximum capacity already, so Egypt cannot import more than it already is through the facility. And Jordan no longer has LNG import capacity, with the 160,000m³ Energos Eskimo having departed ahead of installation later this summer in Egypt. The FSRU at present is at a shipyard in Egypt's Ain Sukhna, unable to import LNG for either Jordan or Egypt. The gas supply cuts from Israel also come ahead of the region's peak cooling demand season. LNG demand could rise if Israeli gas supply is constrained for an extended period of time. Egypt plans to build out its LNG import terminal capacity to three FSRUs later this summer, as well as an additional temporary FSRU for summer leased from Turkey's Botas, and additional LNG import capacity would allow for stronger imports if Israeli supply remains constrained. Two of these FSRUs — the Energos Eskimo and 174,000m³ Energos Power — are at Egyptian shipyards and could be installed in the coming weeks or months. Egypt is understood to have bought at least 110 cargoes for delivery this year , which is equivalent to just under 8mn t. But the country plans to add about 18mn t/yr of LNG import capacity for its peak summer season, assuming 750mn ft³/d of regasification capacity at three FSRUs. Egypt imported 10.2bn m³, or almost 8mn t, of pipeline gas from Israel last year, according to data from the Joint Organisations Data Initiative (Jodi), meaning that with three FSRUs, Egypt has enough capacity to substitute lost Israeli volumes with LNG imports. But it remains unclear for how long Israeli gas exports will be curtailed. Iran also struck Israeli targets with missiles in early October last year , with Israel's Tamar and Leviathan fields having gone off line temporarily, although production returned after one day. Another potential impact of escalating tensions in the Middle East is disruption to shipping around the Strait of Hormuz, but LNG carriers have continued to transit the route as normal today. The tensions could compound insurance costs, adding to shipping costs from the Middle East. More than 80mn t/yr of LNG supply, mostly from Qatar, has to transit the Strait of Hormuz to reach international delivered markets. By Martin Senior Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

CBAM to push renewable power export price above lignite


13/06/25
13/06/25

CBAM to push renewable power export price above lignite

London, 13 June (Argus) — Exports from renewable power production from Energy Community constituent states to the EU could cost more per MWh than exports from lignite-fired generation under the current implementation of the EU's carbon border adjustment mechanism (CBAM), Energy Community CBAM lead Peter Pozsgai said at the Energy Trading Central and South Eastern Europe (ETCSEE) conference in Vienna on 12 June. CBAM will be applied to all cross-border electricity flows from Energy Community states, including power generated from renewables. Producers will be able to deduct any payments made into a regional carbon tax or emissions trading system (ETS) equivalent — a key pillar of market coupling as laid out in 2022's energy integration package. But renewable energy producers will not pay into a regional carbon tax or ETS equivalent, and thus will not be able to deduct this carbon tax from the CBAM applied to all electricity exports. In effect, exports from renewable sources will be priced higher than those from lignite-fired plants in the Western Balkans six — Albania, Bosnia and Herzegovina, Kosovo, North Macedonia, Montenegro and Serbia. Pozsgai "hopes this can be amended" and emphasised that the Energy Community and the European Commission will hold a stakeholder meeting on 1 July with the aim of providing more clarity on CBAM's implementation. Electricity is treated separately from other physical commodities under the CBAM legislation. Carbon quantity will be based on average country-wide emissions rather than on individual plant efficiency. Each country's CO2 emissions factor will be calculated as the weighted-average emissions from all fossil fuel-fired generation in the country and is higher than the indirect emissions factor applied to other goods that are subject to CBAM when they enter the EU. This weighted-emissions factor will be applied to all cross-border power exports, regardless of generation source. CBAM loomed over discussions at ETCSEE, with the regulation being discussed on every panel over the two-day event. Market participants already have observed lower forward liquidity as uncertainty mounts on how CBAM will be implemented and expressed concern about taking financial positions while CBAM implementation evolves. But trading firms and regulators alike expressed a desire for market coupling, while acknowledging that CBAM's implementation instead may hinder regional market integration. "Regional integration is hugely important for security of supply and efficiency and should move forward regardless of CBAM, and if they meet requirements, there should be discussions of [CBAM] being lifted," according to the European Commission's deputy head of unit of the Directorate-General for Energy, Andras Hujber. "Price sensitivity will increase with the implementation of CBAM," Hungarian state-owned energy firm MVM chief commercial officer Laszlo Fritsch said. Provisions in the 2022 integration package provided a pathway to a four-year exemption for Energy Community states, provided they complete market coupling measures before CBAM's scheduled start on 1 January 2026. But no Energy Community countries have met these requirements yet. Serbia will be the first country to couple with EU neighbours Hungary and Romania in the fourth quarter of 2026, but it is unclear whether a CBAM exemption will be granted from that point forward or applied retroactively. European power transmission system operator association Entso-E earlier this week asked the EU to postpone the definitive period of CBAM to provide electricity markets with more time to adjust. By Annemarie Pettinato Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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