Viewpoint: US midcontinent uncertain over return of E15

: Biofuels, Oil products
25/12/24

The US midcontinent fuel market is again poised to enter a spring driving seasonfraught with uncertainty over the future of 15pc ethanol gasoline (E15), which boosts demand for higher-cost, lower Reid vapor pressure (RVP) fuel.

Production of E15 requires blending with more costly, lower RVP fuel because E15 does not qualify for the 1-psi Clean Air Act waiver available for E10 production, a waiver that allows blenders to use less costly, higher RVP fuel.

On 17 March, non-waiver gasoline ballooned to a 19¢/USG premium against waiver fuel, as Magellan added storage for the boutique grade non-waiver fuel and market participants wondered whether the US Environmental Protection Agency (EPA) would intervene.From 17 March to 1 May, traders bought non-waiver gasoline for 10¢/USG more than in past years, before the EPA issued emergency waivers and closed the gap between the grades.

Ahead of the 2026 driving season, the situation is much the same. Market participants are uncertain whether non-waiver grades will return, or whether there will be an act of Congress or additional EPA waivers to resolve any price discrepancies.

Eight US states — Illinois, Iowa, Minnesota, Missouri, Nebraska, South Dakota, Wisconsin and Ohio — requested to opt out of the 1-psi waiver in 2022, a rule that was approved in 2024 and then briefly implemented in 2025, although Ohio and South Dakota deferred implementation.

The states requested to opt out of the 1-psi waiver to secure access to year-round E15, which otherwise cannot be produced during summer due to volatility limits. The waiver allows for E10 to be produced at 10 RVP while E15 without the waiver needs to be blended to 9 RVP.

EPA issued emergency waivers on 1 May 2025 that allowed for E15 to be made with 9 RVP gasoline. This marked the fourth consecutive year that the EPA had issued such waivers to eliminate the need for the non-waiver specification.

To waiver or not to waiver

When waiver/non-waiver gasoline was active from 17 March to 1 May, Magellan pipeline V grade suboctane non-waiver gasoline in the southern midcontinent, also known as Group 3, traded at an average 10.35¢/USG premium to waiver gasoline, or about 5pc higher. Conventional 91 gasoline A grade on the same pipeline averaged a 10.43¢/USG spread, or a 4.2pc premium.

Chicago, in contrast, had most of its non-waiver trade focused on the West Shore/Badger system, which runs through Wisconsin and Illinois, while the Buckeye Complex trading hub in Indiana remained on waiver product.

The West Shore/Badger pipeline system non-waiver CBOB averaged a 4.32¢/USG premium to Buckeye Complex's waiver CBOB, a difference of 2.1pc.

Those spreads could be even wider next year, depending on the approach of the regional pipelines and the overall availability of non-waiver product.

Looking ahead

Participants in the US midcontinent market have expressed uncertainty about the possibility of non-waiver returning.

The American Petroleum Institute (API) along with ethanol groups and fuel retailers have publicly endorsed a bill that would allow year-round E15 and curb small refiners' ability to seek exemptions from biofuel blend quotas.

A provision for extending the 1-psi waiver to E15 was included in a funding bill in December 2024, but ultimately did not make it into law.

Since then, the year-round E15 issue has become entangled with small refiner exemptions with API advocating for the year-round E15 bill with the caveat that the process for gaining exemptions for small refiners become more stringent. API is also seeking to avoid having larger refiners compensate for blending exemptions granted smaller refiners.

Barring an act of Congress or more EPA emergency waivers, the US midcontinent is poised to enter another summer driving season that includes both waiver and non-waiver product.

By Zach Appel

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25/12/24

Viewpoint: Tax credits will shape US ethanol market

Houston, 24 December (Argus) — US ethanol investments and business decisions driven by 45Z and 45Q tax credits are slated to be the primary drivers of industry changes next year, as carbon capture and sequestration (CCS) begins to take hold in the midcontinent and Gulf coast regions. Major ethanol producers such as Archer Daniels-Midland (ADM), Green Plains and POET are investing heavily in CCS, which captures CO2 generated from ethanol production. The captured carbon is then piped to sites with geological formations suitable for injection and storage, some of which are located around Wyoming, the Dakotas and in the US Gulf coast. Ethanol production in conjunction with CCS allows for a lower carbon intensity score and creates a more valuable product that is eligible for 45Z and 45Q incentives. Sustainable energy company Tallgrass has successfully injected carbon via its Trailblazer pipeline in southeastern Wyoming. But other CCS companies have had bumpier journeys. Summit Carbon Solutions was denied a pipeline permit earlier this year in South Dakota but has since made progress in other states through which the company is looking to build its pipeline. Further south, EPA in November granted Texas permission to issue permits for CCS wells . There are 61 well applications under review in Texas, one-third of which were received in the last 12 months, according to EPA. Besides the backlog, the CCS industry is outpacing federal agencies in other ways. The US Internal Revenue Service and Department of Treasury recently issued stopgap guidance in the event that Environmental Protection Agency (EPA) tools for reporting CCS are not up and running by the middle of next year. Although tax credits allow for bigger producer opportunities, ethanol supply-demand fundamentals will be tested heading into next year. US ethanol production this year has reached all-time highs at multiple points, slowly driving ethanol stocks upward and putting more emphasis on currently robust export markets. Ethanol exports this year through September averaged 135,000 b/d, the highest level ever for the nine-month period in US Department of Agriculture (USDA) data going back to 2012. Market sentiment remains bullish on exports going into the first quarter, with robust demand coming from Canada, the UK and Europe, although trade routes are always subject to policy changes. Canada is mulling volume minimums to support domestic low-carbon fuels. Although not yet law, the bill indicates potential for Canadian renewable fuels to partially displace some US exports to that country. Domestic ethanol demand is poised to grow modestly over the next year as 15pc ethanol blends (E15) expand into new markets as the policy landscape becomes more welcoming. California passed legislation in October allowing E15 sales. However, the California Environmental Policy Council still needs to approve the legislation before the California Air Resources Board (CARB) can go about deciding how to implement the policy. The state's inclusion of E15 comes as oil refineries close and as the state faces a goal to achieve net-zero greenhouse gas emissions in a decade. At the federal level, fuel groups are lobbying to get the White House on board with a bill that would lead to higher ethanol blends year-round and remove the need for seasonal waivers from the EPA. Any permanent changes to year-round E15 would have to be in the form of legislation from Congress. Previous bills involving year-round E15 have been unsuccessful. Boosting biofuel blending has proven divisive as congress members attempt to manage interests from agricultural and oil constituents. By Thom Dwyer Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Viewpoint: LCFS ambitions lack diesel power

25/12/24

Viewpoint: LCFS ambitions lack diesel power

Houston, 24 December (Argus) — US low-carbon fuel standard (LCFS) programs are rumbling toward their steepest targets yet with little of the fuel powering them in the tank. West coast regulators and lawmakers have approved ambitious reductions in carbon levels for automotive fuel following a four-year deluge of renewable diesel production. The fuel grew over that time into the largest source of new credits needed to meet California, Oregon and Washington regulatory obligations. But federal uncertainty and feedstock challenges this year have left renewable diesel producers spinning their wheels. West coast states have claimed up to 90pc of all US renewable diesel consumption in recent quarters. Made from seed oils, animal fats or used cooking oil, and in some of the same equipment used to produce petroleum diesel, the lower-carbon alternative remains chemically identical to its conventional cousin. This means it can move seamlessly in the same supply systems and engines, leaving customers to manage only the higher price. Renewable diesel accounted for nearly three-quarters of California's total liquid diesel pool early this year, up from just a quarter of state supply in 2020. Programs in Oregon and Washington lured the fuel further north to account for around 25pc of the total diesel in those markets during recent peaks. That consumption produced a torrent of credits for the state LCFS programs. The fuel has generated as much as 40pc of new California quarterly credits in recent years, helping credits grow to 1.8 times more than new deficits in 2024. Inundated by supply and concerned about biofuel reliance, California regulators finalized much tougher carbon targets that also limit the types of feedstocks, including for renewable diesels, eligible to meet them. LCFS programs reshaped both the domestic refining sector and the west coast road fuel markets with incentives driving lowest-carbon alternatives. But this year demonstrated that federal policy remains the heaviest hand on the wheel steering fuel decisions. Federal proposals to favor US producers and domestic oilseeds with tax and other incentives, alongside hostility toward foreign lower-carbon feedstocks and fuels, stifled renewable diesel output. Total renewable diesel supplied in the US during the first 10 months of the year fell by 19pc compared with the same period of 2024, the first year-over-year drop in supplies since 2018. Diamond Green Diesel, the largest US renewable diesel producer, left one of its production units idled for most of an unprofitable 2025. Phillips 66 and Marathon Petroleum reduced runs at California facilities converted to produce renewable diesel, while CVR Energy will convert units from renewable to conventional diesel production at its Wynnewood, Oklahoma refinery . Oregon demonstrated the west coast's diesel dependency earlier this year. When facility downtime and other factors cut renewable diesel deliveries in late 2024 and early 2025, credits available for LCFS compliance began to shrink. Credit prices more than doubled from May to July in response to data reporting the supply drop. California's gasoline carbon intensity limit will start next year 12pc lower than the targets in place in January 2025. Previous years have fallen by 1-2pc. The state will also soon limit credit generation from crop-based diesels to just 20pc of the volume supplied, and require verification standards that agribusiness groups have decried as overly onerous. Washington state lawmakers early this year adopted a 5pc tougher carbon intensity target for 2026 to rekindle alternative fuel incentives in the state. Credit generation has slowed amid declining renewable diesel supplies this year. The right price can inspire the right supplies, yet the cost of these state incentives ultimately adds to what drivers pay at the pump. Fears of retail price hikes helped slow the adoption of changes to the California LCFS programs this year. Growing national sensitivity to costs could add scrutiny to rising low-carbon incentives in 2026. By Elliott Blackburn Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Mexico's trade surplus widens in Nov

25/12/23

Mexico's trade surplus widens in Nov

Mexico City, 23 December (Argus) — Mexico's trade surplus widened slightly in November from the previous month, despite sharp declines in both exports and imports in the non-oil category. Mexico posted a $663mn trade surplus in November, statistics agency Inegi said, up from a $606mn surplus in October, though on lower overall trade volumes. Total exports reached $56.4bn, while imports stood at $55.7bn, compared with $66.1bn and $65.5bn, respectively, in October. The result contrasted with the $391mn deficit forecast by Mexican bank Banorte. Inegi attributed the wider surplus to an increase in the non-oil trade surplus to $2.84bn in November from $2.74bn in October, alongside a widening of the oil trade deficit to $2.18bn from $2.13bn. Within non-oil trade, manufacturing exports fell by 16pc to $52.1bn in November from the prior month, while automotive exports declined by 2.2pc to $15.8bn, following a 4.8pc increase in October. The US absorbed 79pc of Mexico's light vehicle exports from January-November, with Mexico supplying 17pc of total US auto imports over the 11-month period, according to Mexican auto industry association AMDA. The "others" component of non-oil manufacturing exports dropped by 20pc to $36.3bn in November, nearly erasing October's 23pc gain to $45.5bn. The cumulative impact of US tariffs on Mexican goods is becoming clearer. Mexican bank Banco Base estimates the US levied an effective 4.69pc tariff on Mexican goods through September — below the 25pc blanket rate due to exemptions for goods complying with the USMCA free trade agreement. "The low tariffs have allowed Mexican exports to continue growing, particularly computer equipment, which rose by 83.39pc year to date through September compared with the same period in 2024, with a tariff of just 0.17pc," the bank said. Those "contrast sharply with passenger cars, which face a 15.29pc tariff," which maintain expectations of 7pc annual export growth in 2025, according to the bank. Agricultural exports rose by 3.8pc to $1.4bn in November after increases of 7.2pc in October and 4.1pc in September. Oil-related exports totaled $1.55bn in November, down from $1.82bn in October, including $1.03bn in crude and $514mn in refined products on lower prices and volumes. Mexico's crude export basket averaged $57.66/bl, down by $0.84/bl from October and $8.09/bl lower compared with a year earlier. Crude export volumes fell to 597,000 b/d in November from 717,000 b/d in October, remaining well below the 1.088mn b/d exported in November 2024. By James Young Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

UK refiners seek unused CO2 allowances after closures

25/12/23

UK refiners seek unused CO2 allowances after closures

London, 23 December (Argus) — UK downstream association Fuels Industry UK has urged the government to reallocate unused free CO2 allowances from two recently closed refineries to help remaining plants cope with rising emissions compliance costs. The group wants allowances granted under the UK Emissions Trading Scheme (ETS) for the 150,000 b/d Grangemouth and 105,700 b/d Lindsey refineries to be redistributed. Each allowance permits the holder to emit one tonne of CO2 equivalent. Grangemouth and Lindsey were allocated 441,925 and 541,475 allowances for 2025, respectively. It is unclear how many remain after their closures in April and August. The association warned the sector "may not survive that long" without temporary support, citing carbon costs that exceed those faced by overseas competitors until the UK's carbon border adjustment mechanism (CBAM) takes effect. ExxonMobil's 270,000 b/d Fawley refinery — the UK's largest — will spend $70mn-80mn on carbon costs this year, rising to $150mn within five years, the company's UK chair Paul Greenwood told MPs during an Energy Security and Net Zero Committee hearing in October. Fuels Industry UK chief executive Elizabeth de Jong also addressed the committee, highlighting broader cost pressures. It remains unclear whether refined fuels will be covered by the UK CBAM, which starts in January 2027. Fuels Industry UK is seeking confirmation that they be included from January 2028, and it wants additional free UK ETS allowances distributed to sectors not covered by CBAM during a "volatile" period linked to expected UK-EU carbon market linkage. Such linkage would exempt UK and EU from each other's CBAMs, but talks have yet to start. UK refiners have also missed out on government energy price support schemes during the gas price surge triggered by Russia's invasion of Ukraine, de Jong told MPs. Refiners paid market rates to power operations at their UK sites, missing out on discounts afforded to UK companies under the Energy Bill Relief Scheme, which ran between October 2022-March 2023, and then under the Energy Bills Discount Scheme between April 2023-March 2024. By contrast, US refiners access natural gas at roughly one-third of UK prices, Greenwood said. By George Maher-Bonnett Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Ausblick Biomethan: Chancen und Hindernisse im EU-Markt

25/12/23

Ausblick Biomethan: Chancen und Hindernisse im EU-Markt

Hamburg, 23 December (Argus) — Der europäische Biomethanmarkt wird in 2026 ein regional ungleichmäßiges Wachstum verzeichnen. Verzögerte Umsetzungen der RED III und ungelöste politische Fragen bremsen den Markthochlauf. Gleichzeitig bleibt die Schifffahrt ein zentraler Nachfragetreiber — vor allem für zertifiziertes, subventioniertes Biomethan. Die überarbeitete EU-Richtlinie für erneuerbare Energien (RED III) gibt den Mitgliedstaaten bis 2030 zwei Optionen, um die Klimaschutzziele der EU zu erreichen: Entweder können die Staaten ihre Treibhausgasemissionen bis 2030 um 14,5 % zu senken, oder sie können einen Anteil von 29 % ihres Energiebedarfs aus erneuerbaren Quellen decken. RED II verlangte lediglich einen Anteil von 14 % erneuerbarer Energien. Einige Länder wie Deutschland haben ihre nationalen Umsetzungspläne der Vorgaben von RED III bereits vorgestellt und planen, diese im kommenden Jahr umzusetzen. Mehrere Länder wie die Niederlande oder Frankreich setzen zukünftig auch auf ein THG-System, wie es in Deutschland nun schon seit Jahren existiert. Biomethan mit niedriger oder negativer Kohlenstoffintensität wird damit zum bevorzugten Kraftstoff, um die Verpflichtungen zu erfüllen — vor allem in den Niederlanden, wo es bisher hinter vergleichsweise günstigeren Biokraftstoffen zurückblieb. Eine weitere EU-Verordnung, die den Einsatz von Biomethan begünstigt, ist FuelEU Maritime. Diese trat im Januar 2025 in Kraft und verpflichtet Reedereien, die Emissionen ihrer Flotten in den Jahren 2025 und 2026 um jeweils 2 % pro Jahr zu senken. Übererfüllung kann über Pooling-Systeme vermarktet werden. Dies hat sich für das Bunkering von Bio-LNG in 2025 als besonders profitabel erweisen. Die Regelung hat die Preise für Herkunftsnachweise (HKNs, oder englisch: RGGOs) stark beeinflusst und dürfte 2026 weiter für Dynamik sorgen. Neue Systeme, entweder unter RED III oder nationalen Verpflichtungen, die 2026 in Kraft treten, werden Nachfrage erzeugen, die mit dem Bedarf aus der Schifffahrt um das Angebot konkurrieren muss. Der größte Teil des niederländischen und dänischen Biomethanangebots für 2026 ist bereits für den maritimen Sektor vorgesehen. Wachstum in den Niederlanden Neben der Umstellung auf die THG-basierte Verpflichtung im Rahmen des sogenannten ERE-Zertifikatssystem unter RED III haben die Niederlande im November mit der Arbeit an einer "Green Gas Blending Obligation" begonnen. Eine Umsetzung vor Ende 2027 erscheint zwar unwahrscheinlich, doch die Pläne stützen vorerst die Preise für HKNs. Die Liquidität von niederländischem Biomethan könnte steigen, wenn die Regierung die Massenbilanzierung von Biomethan genehmigt. Ein entsprechender Antrag wurde im November im Parlament eingebracht, doch eine jüngste Regierungsantwort deutet darauf hin, dass dieser nicht von Erfolg gekrönt sein wird. Bio-LNG muss, wie auch in Deutschland, unsubventioniert sein, zertifiziert sein und physisch geliefert werden, um sich für ERE-Zertifikate zu qualifizieren, andernfalls wird es bei der Berechnung des Gesamtmandats eines Kraftstoffanbieters mit einer fossilen CI von 94 g CO2e/MJ behandelt. Stabiles Deutschland, Frankreich Deutschland wird 2026 die Doppelanrechnung für fortschrittliche Biokraftstoffe wie Biomethan auf die THG-Quote abschaffen. Bislang war dies stets ein großer Anreiz für den Einsatz von Biomethan als Kraftstoff. Trotzdem bleibt Biomethan in Deutschland der günstigste Weg, um die THG-Quote zu erfüllen, denn insbesondere güllebasiertes Biomethan hat ein konkurrenzloses Einsparungspotenzial. Auch die steigende THG-Quote könnte die Nachfrage stützen, jedoch bleibt der Absatzmarkt in Deutschland durch die limitierte Anzahl an LNG- und CNG-Fahrzeugen begrenzt. Frankreichs Beimischungspflicht für Biogas-Produktionszertifikate (CPB) tritt im Januar in Kraft und dürfte auch dort die Inlandsnachfrage deutlich ankurbeln. Die Umsetzung der RED III-Richtlinie, die ein neues, auf Treibhausgasen basiertes IRICC-Ticketsystem vorsieht, wurde jedoch auf 2027 verschoben. Das derzeitige energiebasierte TIRUERT-Ticketsystem für den Transport bleibt bis dahin bestehen, und bremst die Nutzung von Biomethan im Verkehrssektor. Ob IRICCs ab 2027 aus Biomethan generiert werden können, ist noch unklar. Die Verpflichtung, 3 % erneuerbares Gas im Verkehrssektor zu verwenden, tritt 2028 in Kraft und wird danach weiter ansteigen. Der grenzüberschreitende Handel und die Bunkerung von Bio-LNG dürften weiterhin eingeschränkt bleiben. Französisches Biomethan kann nur im Rahmen einer Ex-Domain-Annullierung exportiert werden, also durch die Löschung von HKNs in einem Land zur Verwendung in einem anderen. Dies birgt Risiken für Käufer, da die Eigentumsrechte an den Nachweisen nicht zwangsläufig übertragen werden. Subventioniertes Biomethan darf an französischen LNG-Terminals nicht für die Nutzung außerhalb des Landes verflüssigt werden. Französisches Bio-LNG muss über Massenbilanzierung an andere Terminals in der EU exportiert werden, um unter FuelEU Maritime genutzt zu werden. Großbritannien: Zugang zur EU unklar Der Zugang des Vereinigten Königreichs zu EU-Märkten hängt vom Zugang zur Unionsdatenbank für gasförmige Biokraftstoffe (UDB) ab, deren Start nun für Ende Sommer 2026 vorgesehen ist. Unklarheiten bei der Drittstaatenregelung könnten den EU-Handel einschränken — ein kritisches Thema, da das Vereinigte Königreich in den ersten drei Quartalen 2025 mehr als die Hälfte seiner HKNs exportierte, hauptsächlich nach Deutschland, Norwegen und in die Schweiz. Das Vereinigte Königreich prüft derzeit den Ersatz volumenbasierter RTFC-Tickets durch ein THG-basiertes System, doch Änderungen würden erst 2027 in Kraft treten. Fazit Insgesamt bleibt Biomethan in Europa in THG-basierten Systemen gut positioniert, doch Verzögerungen bei der Umsetzung von Vorschriften dürften das Gesamtwachstum des Marktes verlangsamen. Die Niederlande, Dänemark und Deutschland sollten weiterhin Anker für die europäische Preisbildung bleiben, und Spanien dürfte seine Rolle als maritimer Hub festigen. Doch mehrere Länder riskieren, zurückzufallen, wenn sie keine HKN-Register, Export-Hub-Zugänge, politische Anreize und Subventionsreformen einführen. Von Madeleine Jenkins & Svea Winter Senden Sie Kommentare und fordern Sie weitere Informationen an feedback@argusmedia.com Copyright © 2025. Argus Media group . Alle Rechte vorbehalten.

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