Data showing some US-headquartered oil and gas firms paid less in taxes to the US than to foreign governments could be a focus in an upcoming Congress tax policy debate. ExxonMobil reported paying nearly $1.2bn to the US in 2023, and $5.6bn to the UAE, according to a first-time ‘Form SD' report filed with the Securities and Exchange Commission. In its own report, Chevron says it paid nearly $1.2bn in the US, against $4bn to Australia. Independent Hess paid $190,000 in the US and $50mn to Malaysia. Industry officials say the data do not provide a comprehensive view of obligations, which can vary from country to country depending on the tax code and their operations. The payment disclosures also do not cover payroll taxes or state and local taxes, for example, and do not say if a company had carryover net operating losses or tax credits that reduced its overall tax bill in the US.
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Viewpoint: Indian term LNG to make 2026 imports pricier
Viewpoint: Indian term LNG to make 2026 imports pricier
Mumbai, 24 December (Argus) — India's LNG imports are likely to get pricier in 2026 on the back of a rising number of mid-term LNG supply deals that are linked to the US benchmark Henry Hub, at a time when spot prices have declined sharply. A total of 2.95mn t of LNG supply deals, making up 12pc of India's total LNG import volumes of 25mn t/yr is at risk of being pricier over crude-linked LNG deals, domestic gas prices, as well as the volatile spot market, especially when the domestic currency has reached its all-time low of 90 rupees against the dollar. India's LNG imports are expected to fall by 6pc on the year to 25mn t in 2025, predictive volumes from market intelligence firm Kpler show. Indian companies seeking to ensure domestic gas needs for downstream units are met and to better manage their risks signed a spate of LNG deals linked to US Henry Hub gas prices in late 2024 and in early 2025, in a bid to diversify their supply portfolios. Contracts linked to Henry Hub prices were seen as a stabilising anchor to reduce dependency on crude-linked contracts and spot prices. Supplies under contracts linked to Henry Hub prices have already begun weighing on city gas distributors in 2025, especially since they sought to increase their Henry Hub-linked supply, after the government slashed their allocation of domestic gas production in October 2024, and because of highly volatile spot LNG prices in recent years. India state-run refiners IOC, HPCL and BPCL each have 400,000 t/yr of LNG supply deals that are linked to Henry Hub prices. These supplies have already been arriving at Indian ports in 2025 , but are intended for consumption at their own refineries. State-owned Gujarat State Petroleum and private-sector Deepak Fertiliser will begin receiving their supplies from 2026. Nymex futures for delivery at the Henry Hub have increased because of stronger US domestic and export demand, coupled with lower oil prices reducing the outlook for associated gas production. This is translating into much higher costs for Indian buyers. The delivered price of LNG in Henry Hub-linked contracts in 2026 for city gas firms is expected to average at $13.40/mn Btu, while state-controlled gas distributor Gail's Henry Hub-linked import price is at around $12.80/mn Btu, based on Argus forward curves of the US benchmark. These prices are higher than that of domestic gas from conventional fields, at $6.55/mn Btu, imported LNG under crude-linked contracts, at $8.80/mn Btu, and domestic gas from high-pressure, high-temperature fields, at $9.72/mn Btu, oil ministry data show. Argus -assessed spot LNG prices for deliveries to west India are averaging at $11.90/mn Btu for 2025, marginally higher from $11.10/mn Btu in 2024. Under stress Two city gas firms that buy their supplies from state-controlled gas distributor Gail have switched part of their portfolio to Henry hub indexation. India's largest city gas distribution company, Indraprastha Gas (IGL), has close to 20pc of its total gas portfolio linked to the Henry Hub, while Mumbai-based Mahanagar gas has close to 30pc exposure, according to their respective quarterly earnings calls. But IGL and Mahanagar recently warned that their margins are coming under pressure because of higher procurement costs under their US contracts. Rising Henry Hub prices and a depreciation of the rupee against the dollar are squeezing margins, which has been exacerbated by the reduced government allocation of cheaper, domestic gas, IGL said in its November earnings call. IGL had previously expressed confidence in Henry Hub-linked contracts because they offered lower volatility. "Unless Henry Hub goes way beyond our target, it should remain competitive," IGL said in April. But the firm has faced a different reality in recent months. Gail force Gail's lower Henry-Hub-linked import price may be because it has opted for back-to-back indexation that guarantees margins, instead of pursuing arbitrage opportunities between Henry Hub-linked import costs and crude-linked sales contracts. City gas firms pay Gail a $6/mn Btu fixed premium on top of 119pc of Henry Hub prices, while Gail's import formula from state-owned Qatar Energy is 115pc of Henry Hub plus a fixed $5.66/mn Btu — intended to reduce price risks for Gail. Given the interplay between oil and gas prices in the US, a rally in crude prices can support revenue from downstream oil-linked contracts while at the same time weigh on Henry Hub-linked import costs. Conversely, weaker crude prices can swiftly erode margins, with a potentially significant impact on cash flows. By Rituparna Ghosh 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
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.
Viewpoint: Canadian heavy TMX crude to grow into Asia
Viewpoint: Canadian heavy TMX crude to grow into Asia
Houston, 23 December (Argus) — Heavy sour Canadian crude exports are likely to expand further into the Asia-Pacific market in 2026 as Canadian output increases and US west coast refinery closures weaken US demand. Around two-thirds of all Canadian crude exports from the 890,000 b/d Trans Mountain pipeline system were destined to Asia-Pacific year-to-date November 2025, with the balance heading to the US west coast. Just over three-quarters of the 375,000 b/d of Canadian heavy crude exports from Vancouver were destined to Asia-Pacific year-to-date November 2025, according to data from analytics firms Vortexa and Kpler. The balance out of the Trans Mountain system headed to the US west coast. This is up from a roughly 60/40 split in the second half of 2024 following the 540,000 b/d Trans Mountain Expansion (TMX) startup in May of that year. US west coast customers received 80,000 b/d of heavy sour Canadian crude during the first 11 months of 2025, 25pc less than the second half of 2024. This is despite total heavy exports from Vancouver averaging 27pc higher this year so far. Heavy crude exports are expected to keep growing in 2026 as increased western Canadian production meets limited southbound pipeline capacity to the US. In January 2026, Canadian pipeline operator Enbridge rejected 13pc of heavy and light crude nominations on its 3.1mn b/d Mainline to the US as Alberta production surges in the colder months. But the Trans Mountain system has accepted all crude nominations since TMX came on line in May 2024 and the system has room to export more crude. Trans Mountain reported that the pipeline ran at 87pc capacity in the third quarter of 2025 . Canadian crude and condensate production is projected to average a record-high of 4.85mn b/d in 2026, 80,000 b/d above 2025 levels, according to Argus Consulting, a division of Argus Media. China thirst for heavy grows Any increase in exports is expected to head towards the Asia-Pacific region, specifically China. Chinese interest in heavy crude is expected to grow next year as refineries bring on line increasingly advanced cracking units to improve petrochemical yields . This increase in petrochemical output will come at the expense of road fuels, as rising electric vehicle use and low construction-sector activity hit Chinese gasoline and diesel demand. Heavy Canadian crude tends to be the most competitively-priced, unsanctioned option for Chinese refiners. Asia-Pacific buyers more generally have sought Canadian heavy crude as a substitute for restrained supplies of heavy sour Venezuelan Merey and Arab Heavy. Saudi Arabia's state-owned Saudi Aramco may be keeping more heavy crude for refining, while market confidence in Merey supply is weak following a US seizure of an oil tanker off the coast of Venezuela on 10 December and the US declaring a blockage on Venezuela exports on 16 December. Meanwhile, shipments of Arab Heavy have dropped by 280,000 b/d to around 560,000 b/d this year, according to Vortexa data. As Asia-Pacific interest in Canadian crude continues to grow, US west coast demand will continue to fall. On the heels of Phillips 66 closing its 139,000 b/d Los Angeles, California, refinery, Valero is likely to shutter its 145,000 b/d Benicia refinery near San Francisco in April 2026. Valero is evaluating alternatives for its 85,000 b/d Wilmington refinery in Los Angeles. At the start of 2025, these three refineries made up 23pc of Californian refinery capacity, and combined took 30,000 b/d of Cold Lake during January-June 2025, according to EIA data. As available Canadian crude supplies grow, the ability to fully load Aframax vessels at the Westridge Marine Terminal in British Colombia will allow increased volumes to be exported. Dredging at the terminal is set to be completed by late 2026 or early 2027. Draft restrictions limit most Aframax vessels to around 550,000 bl at the terminal for heavy crude, and 600,000 bl for some lighter crudes. Post-dredging, those same ships could carry around 700,000-750,000 bl. In the long term, Trans Mountain is looking to boost pipeline flows to meet the increased shipping capacity, including the use of drag-reducing agents that should add another 85,000-90,000 b/d by 2027 to pipeline capacity, according to Trans Mountain. By John Cordner 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
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.
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