Australia to adopt fuel efficiency rules for EV uptake

Spanish Market: Electricity, Emissions, Oil products
19/04/23

The Australian government has released a long-awaited strategy paper that outlines plans to adopt fuel efficiency standards in a bid to increase electric vehicle (EV) uptake.

The National Electric Vehicle Strategy (NEVS) paper did not set a date to implement the new fuel efficiency standards, but promised a six-week consultation process to determine the finer details of a policy in order to be broadly consistent with other advanced markets.

But transport minister Catherine King said by the end of the year, technical details regarding emissions standards would be finalised and a draft of the legislation will be presented, meaning that the standards would commence in 2024 at the earliest.

Australia lacks efficiency standards for passenger and light commercial vehicles, with the government linking its new policy to increasing the supply of low- and zero-emissions vehicles. Canberra has been mulling changes to fuel and vehicle standards since 2015.

Just 3.8pc of Australian new car sales in 2022 were EVs, compared to 17pc in the EU, and new internal combustion engine (ICE) cars sold in Australia use on average 40pc more fuel than those in the EU. Transport contributes to 19pc of Australia's total greenhouse gas (GHG) output. Passenger and light commercial vehicles are responsible for 62pc of Australia's transport emissions in 2019, and 60pc in 2022. Emissions are projected to fall by only 6mn t/yr from 2019 levels by 2035 without intervention.

The new standards are likely to apply across suppliers' entire range to allow manufacturers to market a mix of vehicle technologies, meeting fleet average target emissions and customer needs. But ICE vehicles are likely to remain popular in remote parts of Australia because of the distance between destinations and limited recharging access, although the government has pledged to improve charging infrastructure across regional areas.

The federal Labor government has taken other steps to incentivise greater uptake, including a A$20.5mn ($13.8mn) scheme to subsidise car loans for EV buyers. It also joined a court challenge against a Victorian state government road-user charge that was levied on EV drivers at 2.6A¢/km, arguing the levy is an excise constitutionally only able to be imposed by Canberra. The NEVS paper said the impact on fuel excise collection is negligible, given current low EV uptake.

The Federal Chamber of Automotive Industries (FCAI) will support the efficiency standards approach, with chief executive Tony Weber saying the government had taken the correct approach to the issue.

"The questions and topics raised in the consultation paper highlight the complexity of the issue and demonstrates the government has done its homework, to ensure any future emissions standard is not a simplistic copy of an overseas standard but instead suited to Australia," Weber said, pledging to work alongside the government to develop the new regulations.

But while increasing EV sales can reduce transport emissions, some concerns remain about their impact on Australia's power grid. A report from Australian national science agency CSIRO last year warned that sufficient electricity distribution network capacity to meet coincident charging requirements of a high EV share could be an infrastructure constraint, if it is not well planned for.

Australia last year updated its 2030 emissions reduction target to 43pc from 2005 levels, banking on a new A$20bn power transmission fund to connect renewable energy zones across the country and an 82pc renewable electricity generation target.

By Tom Major

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22/12/25

Viewpoint: CSAPR sentiment bearish despite coal use

Houston, 22 December (Argus) — Expectations for lower prices is likely to persist in the federal Cross-State Air Pollution Rule (CSAPR) allowance markets next year as they remain oversupplied, even with higher levels of coal-fired generation. The seasonal NOx markets have been more active this year compared to 2024, when prices essentially flatlined due to regulatory and legal uncertainty brought about by a barrage of lawsuits filed against the US Environmental Protection Agency (EPA) for its "good neighbor" plan. That plan, which the agency finalized in 2023 under former president Joe Biden, sought to help downwind states meet the 2015 national air quality standards for ozone. The plan imposes more stringent ozone season NOx caps for power plants in more than 20 upwind states, as well as setting new limits on some industrial facilities. But the plan is now essentially defunct after the US Supreme Court halted its implementation in June 2024. This led the EPA to return to less-rigorous NOx emissions limits tied to older ozone standards and reshuffle the participating states into the Group 2 and "expanded" Group 2 markets. Argus launched its assessment of the latter in February 2025. EPA said in March it intends to reconsider the good neighbor plan in order to give states more freedom in developing their own ozone reduction plans. The announcement led to the US District of Columbia Circuit Court of Appeals pausing a lawsuit challenging the legality of the good neighbor plan until the agency completes its reconsideration, and which could culminate in new regulations by fall 2026. But those developments did little to move the seasonal NOx markets, which have already been sluggish due to oversupply and weak compliance demand, leading to more dramatic price fluctuations when trades do occur. Argus has assessed Group 2 allowances at $875/short ton (st) since 1 December and expanded Group 2 allowances at $850/st since 24 October. It is unclear how US president Donald Trump's current hostility towards environmental regulations will affect the administration's attitude towards the existing CSAPR allowance trading markets, but it seems likely that they are here to stay. The EPA likely is "digging into the air transport modeling that they have to understand what their options are," and which could potentially echo its determination during Trump's first term that states had adequately addressed downwind pollution, said Carrie Jenks, executive director of Harvard Law School's Environmental and Energy Law Program. "The EPA is committed to advancing cooperative federalism and working with states on state implementation plans (SIPs) to provide clean air for all Americans," the agency said in December. But extensive case law suggests that the EPA has little room to give states more power to manage emissions as they see fit. Both the DC Circuit Court and the US Supreme Court have made it clear that the EPA must intervene if a state does not sufficiently lower its emissions, Jenks said. "So the EPA's hands, regardless of who's in the White House, are really tied," she said. As a result, the EPA will likely try to prolong the issue by giving states more time to draw up their own ozone-reduction plans. The debates over those plans could revolve around how the modeling of emissions is conducted and interpreted. Even if that modeling is challenged in the courts, it can take years for litigation to get resolved. More coal, more emissions Despite the continued dearth of activity in the seasonal NOx markets, increases in coal-fired generation, a significant source of NOx and SO2 emissions, have buoyed the outlook in those markets, heightening expectations for higher emissions. During the past year, stronger power demand and higher natural gas prices have allowed coal to take a larger market share, which has resulted in increased coal-fired power in grids that serve states covered by CSAPR. But NOx emissions during this year's ozone season, which ran from May through September, were lower than expected, according to market participants. Cumulative emissions in the Group 2 and expanded Group 2 markets rose by just 1pc and 4.2pc, respectively, and remained well below their overall limits. It was likely more cost-effective for power plants to run their NOx controls than to purchase or surrender additional allowances for compliance. Still, given the Trump administration's pro-coal agenda, it remains to be seen for how long increases in coal generation will continue and to what extent that will affect the CSAPR markets. Conversations over ballooning data center demand have also bled into the seasonal NOx markets as the Trump administration seeks to leverage coal to power that boom. There are currently a lot of moving parts that make it difficult to make predictions, including how competitive coal is compared to other energy sources such as renewables, where data centers get built, their demand flexibility, and the federal and state regulatory landscapes in the coming years, Jenks said. By Ida Balakrishna Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

P66, Kinder expand proposed western US fuel pipeline

22/12/25

P66, Kinder expand proposed western US fuel pipeline

Houston, 22 December (Argus) — Independent refiner Phillips 66 and midstream giant Kinder Morgan are expanding a plan for a proposed refined products pipeline system from the midcontinent to western US markets. An initial open season for the project, which closed on 19 December, resulted in significant interest, including shipper commitments for the proposed Western Gateway pipeline, the companies said Monday. As a result, a second open season will launch in January for remaining capacity and will include new destinations west of Colton, California, through a joint tariff with Kinder Morgan's existing SFPP pipeline that will be reversed between Watson, California, and Colton, allowing access to Los Angeles markets. The companies did not disclose the length of the second open season. The Western Gateway project, announced in October, includes a new 200,000 b/d pipeline from Borger, Texas, to Phoenix, Arizona, combined with the reversal of SFPP from Colton, California, to Phoenix, Arizona. Philips 66 owns and operates a 149,000 b/d refinery in Borger. In addition, the Phillips 66-operated Gold pipeline, which currently flows from Borger to St Louis, Missouri, would be reversed to allow refined products from midcontinent refineries to flow south to Borger and supply the Western Gateway system. The companies expect the Western Gateway project to be completed in 2029. The proposed pipeline system comes as two large California refineries are planning to close, including Phillips 66's 139,000 b/d Los Angeles refining complex. Phillips 66 stopped processing crude at the Los Angeles facility in mid-October as part of a planned shutdown announced about a year earlier. It expects to idle remaining units by the end of this month. In addition, Valero is planning to shut down or repurpose its 145,000 b/d refinery in Benicia, California, by April 2026. The planned closures have triggered major concerns about California's tight and often volatile oil products market and the impact on neighboring states . Another large US midstream company, Oneok, is considering building a 200,000 b/d pipeline — the Sun Belt Connector — to carry gasoline, diesel and jet fuel from El Paso, Texas, to Phoenix, Arizona. In addition, US independent refiner HF Sinclair is considering several pipeline expansions that would move more refined products from the Rocky Mountains region to markets further west. By Eunice Bridges 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

22/12/25

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.

German fuel demand rises before 2026 price increase

22/12/25

German fuel demand rises before 2026 price increase

Hamburg, 22 December (Argus) — German consumers increased fuels orders in the last full working week of 2025 to fill their tanks ahead of a probable price increase at the start of the new year. Low prices also boosted heating oil demand. Fuel demand rose significantly in the week ending 21 December, after stockbuilding failed to materialise in the previous week. Diesel spot sales for truck loading submitted to Argus increased by almost 50pc on the week, and E5 gasoline sales by 35pc. Diesel sales on 17 December were the highest in four months, while gasoline sales were the highest since September 2023. Gasoline filling stations, freight forwarders and other large-scale consumers waited until the last minute to fill their tanks before higher costs from the CO2 tax and greenhouse gas (GHG) quota take effect in 2026. Sellers recently offered B7 diesel for loading in January with premiums of €10-13/100l, and gasoline prices rose by a similar amount. Gasoline filling stations built up stocks ahead of the holidays, because the few remaining working days until the end of the year restrict logistics. Low prices also drove heating oil demand, at least in the first half of the week. The national average heating oil price reached its lowest point for the year on 16 December. This motivated consumers to buy, although the premiums for the new year are much lower than for road fuels at around €3-4/100l because of the CO2 tax increase. But some can only be delivered in January because of logistical bottlenecks. Heating oil spot volumes in 2025 so far are around 10pc above the 2024 level, mainly because consumers stocked up when the front-month Ice gasoil futures contract reached its lowest level since the end of 2021 in early April. The heating oil price fell to its lowest level in more than three years. Prices were subdued by the prospect of a global economic slowdown as a result of the trade conflict between the US and China and the so-called reciprocal duties for some of the US' most important trading partners. Lower Ice gasoil futures also triggered additional purchases at the end of November. Diesel spot volumes in 2025 were around 5pc below the previous year, probably because of a weak manufacturing sector. The average production index in January-October was almost two percentage points below the same period in 2024 and about six points below 2023. The truck mileage index lagged behind previous years in most months, with a noticeable affect on industrial demand for diesel. By Gabriele Zindel and Johannes Guhlke 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

22/12/25

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.

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