Spanish gas demand forecasts cut further

Spanish Market: Natural gas
31/05/13

London, 31 May (Argus) — Unexpectedly weak power sector gas consumption has forced Spanish gas system operator Enagas to again cut its demand expectations for 2013, leaving the country looking even more oversupplied.

Power sector gas demand is now expected to fall by 14.9pc this year to just 72TWh, the least since 2004, when power sector gas demand totalled 66.7TWh, as utilisation rates at Spain's fleet of combined-cycle gas turbine (CCGT) power plants continues to languish at record lows. Spain had 8.2GW of CCGT generation at the close of 2004, while at the start of this year it had 25.3GW.

At the start of this year, Enagas had expected power sector gas demand to edge only 0.7pc lower this year, to 84.1TWh, reasoning that CCGT utilisation rates had likely already fallen as much as they could. But Enagas' view was based on the assumption of normal weather conditions, whereas rainfall has proven to be far higher than normal — over the first three months of the year, 30pc more rain fell than the long-term average. Accordingly, hydropower generation has been unusually strong, accounting for nearly 17pc of Spanish power production so far this year, up from just 6.7pc during the first five months of 2012.

The further reduction in forecast power sector gas demand means that Enagas now expects Spain to consume just 354.9TWh this year, a 2.1pc decline from 2012. In January, it had expected demand to rise by 0.5pc to 364.4TWh, while in March it revised its demand forecast to 361.4TWh, a 0.3pc year-on-year decline.

And taking into account cushion gas injections and exports to Portugal, Enagas now expects the total draw on the Spanish system this year to fall by 2.2pc on the year to 410TWh. In January, it had expected the system draw to rise by 0.8pc to 422TWh, while in March it revised the expected draw to 419TWh, flat to 2012.

In particular, far less cushion gas is now set to be injected than previously anticipated, after only a small proportion of the 10.7TWh needed at the new Castor facility was actually secured in an auction conducted by power market operator Omel earlier this month. Only 2.2TWh is now expected to be injected into the new Yela and Castor facilities this year.

The weaker call on the Spanish system means that the country now looks about 37TWh oversupplied — up from 28TWh in March and 31.9TWh in January — against the 447.1TWh of contracted supply that importers have reported to energy regulator CNE. That 37TWh would be the equivalent of about 5.5mn m³ of LNG, or 38.3 standard 145,000m³ cargoes — 5.3 cargoes more than in January.

Traders have argued that weaker interest in spot LNG cargoes in the Atlantic basin this spring could hinder Spanish re-exports, forcing the country to turn down its pipeline gas imports — or even reverse the flow of gas in the bi-directional pipeline on the French border at Larrau.

In the 12 months to the end of April, Spanish pipeline gas imports were up by 13.6pc year on year, with Algerian imports up by 14.5pc and imports from France up by 10pc. Traders have frequently argued that Spain's appetite for pipeline gas, which has allowed the country to re-export far more LNG cargoes than would have been made available just by the weakness of domestic demand — has been crucial to supporting prompt gas prices in southern France, which remain the highest of all the liquid traded hubs in western Europe.

But rising global LNG demand could yet provide an outlet for Spain's surplus supply. Following further nuclear shutdowns in South Korea — after more forged safety certificates were uncovered — and with temperatures in Japan forecast to climb above seasonal norms for the July-August power demand peak, interest in Asia-Pacific for spot LNG cargoes has begun to pick up, traders say.

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23/12/25

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.

Viewpoint: US, European LNG spread may narrow in 2026

22/12/25

Viewpoint: US, European LNG spread may narrow in 2026

Houston, 22 December (Argus) — The spread between US and European LNG prices will likely narrow further in 2026, but forward prices indicate US LNG supply under long-term contracts will remain comfortably profitable in international spot markets until at least summer 2027 as a wave of new supply comes on line. A recent rally in the US natural gas market highlighted US LNG's tightening margins. The indicative long-term LNG contract price — 115pc of US benchmark Henry Hub plus a $3/mn Btu liquefaction fee — surpassed the Argus Gulf coast (AGC) spot fob price in early December for the first time in more than two years amid cold weather in the US, mild weather in Europe and high Atlantic basin freight rates. But the premium over the spot price was brief and caused no change to export schedules. The front-month Henry Hub contract quickly shed its gains on warmer weather, falling to $3.89/mn Btu on 16 December from a nearly three-year high of $5.29/mn Btu on 5 December. Prices hovered around $4/mn Btu through 19 December. The impact was solely on profit margins rather than fundamentals. Customers of US LNG facilities did not need to cancel cargoes under take-or-pay provisions because a profit incentive to maximize exports remained. Liquefaction costs are considered sunk, and the spread between Henry Hub and European LNG prices remained wide enough to more than cover shipping costs. Though rising exports may add to domestic pricing volatility during cold winter weather through the end of the decade, US and European gas futures today indicate long-term offtake from US LNG terminals will remain profitable until the summer of 2027, assuming freight rates of $80,000/d and a 50¢/mn Btu discount to the European benchmark TTF for northwest European deliveries. At that time, contracts with $3/mn Btu liquefaction fees could surpass delivered LNG prices in northwest Europe, though the arbitrage for US gas would remain open for contracts with lower fees (see chart) . Fees now range between $2.50-2.80/mn Btu for US supply coming on line toward the end of the decade. Contracts with fees on either end of that range remain below European LNG prices until summer 2029 and summer 2028, respectively, assuming freight rates of $80,000/d. But cargo cancellations are not always necessary when long-term US LNG contract prices surpass international prices. Terminal operators and their customers finalize annual delivery plans as well as upward and downward delivery tolerances before the start of each year, leaving less flexibility later in the year. If a customer wishes to cancel a cargo, they typically must notify the terminal up to two months in advance, which would likely only happen in an environment where the cost of 115pc of Henry Hub plus freight stabilizes above European LNG prices. The spread between Henry Hub and delivered European prices is wide enough to absorb freight costs through winter 2030-31. If an offtaker opts for a lower quantity in its delivery tolerance or cancels a cargo, the volume returns to the terminal operator, which could still market and sell the cargo on the spot market. This effectively shifts the seller of a cargo from the LNG customer to the LNG terminal operator. The likelihood of cancellations beyond 2027 may be higher in the spring and autumn shoulder seasons, when demand in Europe is typically lower. Depending on the previous winter, this may be more likely to occur in autumn, given the annual rebuild of Europe's underground gas inventories that begins in the spring. Additional liquefaction capacity has already helped tighten margins for US LNG since Europe's conflict-driven volatility in 2022 . The AGC fob's premium over the long-term indicative contract averaged $3.95/mn Btu through 19 December this year, down from $4.63/mn Btu, $5.37/mn Btu and $20.13/mn Btu in 2024, 2023 and 2022, respectively. But the anticipated convergence of US and European LNG is not guaranteed. Geopolitical conflict could disrupt existing trade patterns. And lower prices in Europe will be contingent on new LNG projects, led by the US and Qatar, maintaining their timelines, which are prone to delays from supply chain issues and workforce constraints. This would add upside risk to international prices and downside risk for Henry Hub if the delays are in the US. By Tray Swanson European LNG spot prices vs long-term US LNG $/mn Btu Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

US shale firms see subdued spending next year

22/12/25

US shale firms see subdued spending next year

New York, 22 December (Argus) — US president Donald Trump took to prime-time TV this week to reassure voters that 2026 will see a stronger economy, but US shale executives see little prospect of an imminent upturn in their business. US oil and gas firms plan to keep capital spending flat to slightly lower next year, according to a closely watched survey by the Federal Reserve Bank of Dallas, as the industry grapples with lower oil prices. Although activity edged lower in the fourth quarter, uncertainty grew and companies remained increasingly wary about future prospects in the poll of 131 executives from Texas, southern New Mexico and northern Louisiana that was carried out earlier this month. "Decreasing oil prices are making many of our firm's wells uneconomic," one exploration and production (E&P) executive said. "Capital efficiencies and returns drive our investment decisions," another respondent said. "If economic conditions worsen, drilling and completion activities will cease in 2026." The muted outlook for spending next year comes as producers have adopted a wait-and-see approach in recent months, given an increasingly uncertain macro backdrop, with crude prices trading near four-year lows this week on fears of global oversupply. A number of shale operators have posted higher-than-expected production this year. At the same time, spending has come in below expectations as drilling operations become more efficient, a trend UK bank Barclays says could be repeated in 2026. The executives who took part in the Dallas Fed survey gave varied responses when asked about their spending plans for next year depending on their size. Large producers — or those with output of 10,000 b/d or more — were more likely to say they expect capital expenditure to remain close to this year's levels. The most selected response among smaller firms — with production under 10,000 b/d — was for a slight increase. Although there are more small firms in the US, the larger companies account for more than 80pc of total US output. When asked about the oil price they were using for capital planning in 2026, the average response among executives was $59/bl for WTI. That was down from the $68/bl average price for the US benchmark that firms planned to use this year. The Dallas Fed said it was not necessarily a surprise that companies were not planning to trim spending further given weaker oil prices. Capital-intensive care "Oil and gas is a capital-intensive business," the bank's senior business economist, Kunal Patel, said. "It takes a lot of money to sustain the wells, even to keep production flat, and so that's why I don't think you're seeing as many people looking to significantly cut." Also, the prices that companies are using to plan next year's budgets are not too far from current breakeven levels. And producers may yet respond with deeper cuts to spending if prices tumble again. Oil and natural gas production was relatively unchanged in the fourth quarter, the survey showed, while costs rose at a slower pace than in the previous three months. "While oil prices have not been low enough this quarter to force a substantial cutback in activity, they were not high enough to support any growth either," Dallas Fed assistant vice-president Michael Plante said. In its annual E&P spending survey, Barclays expects upstream capital expenditure in North America to fall by 5pc in 2026, on lower US activity, reduced reinvestment ratios, and the impact of drilling and well completion efficiencies. That would mark its third consecutive annual decline. Barclays also revised down this year's upstream spending forecast to a decline of 5pc, from an initial estimate of a 3pc drop. The change was driven by further US rig count losses after Opec+ started to ramp up supplies, as well as the hit from Trump's tariff wars. By Stephen Cunningham 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.

Japan's Niigata assembly backs Tepco's nuclear return

22/12/25

Japan's Niigata assembly backs Tepco's nuclear return

Osaka, 22 December (Argus) — Japan's Niigata prefectural assembly has supported its prefectural governor's decision to approve the restart of the Kashiwazaki-Kariwa nuclear reactors operated by utility Tokyo Electric Power (Tepco). The assembly passed a vote of confidence on Niigata governor Hideyo Hanazumi on 22 December. He had sought the assembly's judgement on his plan to authorise the restart of the No.6 and No.7 reactors at the Kashiwazaki-Kariwa, each with a capacity of 1,356MW. Hanazumi had previously indicated that he would step down if the motion was rejected. The motion was attached to a supplementary budget request of ¥31mn ($197,048) for the April 2025-March 2026 fiscal year, intended to support activities related to the restart of the Kashiwazaki-Kariwa nuclear plant. Hanazumi plans to meet Japan's trade and industry minister Ryosei Akazawa on 23 December to discuss the restart of the nuclear plant. The endorsement will allow Tepco to move towards restarting its reactors for the first time since they triggered the Fukushima-Daiichi nuclear disaster, after a powerful earthquake and tsunami in March 2011. The plant, which has remained off line since March 2012, is Tepco's sole nuclear station, after it scrapped the damaged Fukushima Daiichi and nearby Fukushima Daini plants. The Kashiwazaki-Kariwa plant comprises of seven reactors with a combined capacity of 8,212MW, of which the No.6 and No.7 units have cleared the stricter post-Fukushima safety inspections. Tepco has yet to file an application with the country's nuclear regulation authority (NRA) for screening of the five other reactors. The utility is also mulling scrapping the No.1 and No.2 reactors. Tepco is expected to prepare for the restart of the No.6 reactor first, given that the No.7 unit will be required to remain shut until August 2029 for the installation of anti-terrorism facilities. The No.6 reactor is expected to resume operations after clearing pre-use inspections, which typically last for three weeks to one month. This means that Tepco will be able to restart the No.6 reactor in January at the earliest. The return of the Kashiwazaki-Kariwa plant could be a milestone in Tepco's progress in nuclear power generation after the Fukushima disaster, with the No.6 unit marking Tepco's first reactor to be restarted after the disaster. Electricity from the nuclear plant will be sent to the Tokyo metropolitan area, with the nuclear plant — located in the Tohoku region — mitigating the risk of a power shortage in Japan's capital. A single nuclear reactor can produce 10 TWh/yr of electricity, and can save the company an estimated ¥100bn/yr, Tepco previously said. The return of the No.6 reactor is also expected to reduce CO2 emissions by around 3.3mn t/yr, it added. 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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