Violent protests torpedo Colombia’s tax reform

Spanish Market: Coal, Crude oil, LPG, Natural gas, Oil products
03/05/21

Colombia's government withdrew a controversial tax reform that would have raised revenue from coal and hydrocarbons use, amid violent protests in which at least 16 people were killed and hundreds more injured in recent days.

Demonstrations are continuing today on the streets of Bogota and other cities as the administration of conservative president Ivan Duque considers cabinet changes, including the possible removal of finance minister Alberto Carrasquilla.

The aborted tax reform would have raised around 26 trillion pesos ($7.22bn) in revenue, equivalent to 2.4pc of GDP, in 2022. The Duque administration is under pressure to shore up the country's finances after GDP dropped by 6.8pc last year amid the Covid-19 pandemic. The bill would have also increased taxes on individuals in order to preserve the competitiveness of the corporate sector.

The bill would have slapped a carbon tax on coal consumption in the power and industrial sectors. The tax on coal users would have been 47,000 pesos/t of CO2 equivalent (tCO2e), or around $ 12.4/tCOe, according to coal federation Fenalcarbon's new president Carlos Cante. Colombian lawmakers have tossed out a similar "green tax" on previous occasions.

Colombia consumes 9mn t/yr of coal for power generation and industries, including cement and brick makers. Coal-fired generators account for 1.32GW of a total 17.82GW of installed capacity as of September 2020.

The bill would have imposed a tax of up to 19pc on propane and butane for residential use, with the rate based on a sliding scale income scale. Currently, LPG is subject to a carbon tax only if it is used for industrial purposes.

The government was also seeking to increase the value-added tax (VAT) from 5pc to 19pc on gasoline, with the same rate applied to basic services in upper-middle-class areas. The bill would have taxed income on people who earn more than $656/month, a measure rejected by unions in a country where the minimum wage is $248/month.

The government said it would submit a revised tax bill in coming days.

By Diana Delgado

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24/12/25

Viewpoint: US midcontinent uncertain over return of E15

Houston, 24 December (Argus) — The US midcontinent fuel market is again poised to enter a spring driving season fraught 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 Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Tepco to restart Kashiwazaki-Kariwa No.6 reactor in Jan

24/12/25

Tepco to restart Kashiwazaki-Kariwa No.6 reactor in Jan

Osaka, 24 December (Argus) — Japanese utility Tokyo Electric Power (Tepco) plans to reactivate its long-idled 1,356MW No.6 reactor at its Kashiwazaki-Kariwa nuclear power plant on 20 January 2026, with the aim of beginning normal operations on 26 February. On 24 December, Tepco submitted the potential target dates for resuming tests and normal operations of the reactor in Niigata prefecture, northwest Japan, to the country's Nuclear Regulation Authority (NRA). Tepco will assess the reactor's integrity during the test runs. The submission came two days after the Niigata prefectural assembly passed a vote of confidence on its governor Hideyo Hanazumi on 22 December, who had sought the assembly's judgement on his plan to approve the restart of the No.6 and No.7 reactors at the Kashiwazaki-Kariwa. The return of the Kashiwazaki-Kariwa plant could be a milestone in Tepco's progress in nuclear power generation after the Fukushima nuclear crisis in 2011, with the No.6 unit marking the utility's first reactor to be restarted after the meltdown disaster. 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. The No.7 unit will be required to remain shut until August 2029 for the installation of anti-terrorism facilities. Tepco has yet to file an application with NRA for screening of the five other reactors, while it is mulling scrapping the No.1 and No.2 reactors. By Motoko Hasegawa Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Viewpoint: Indian term LNG to make 2026 imports pricier

24/12/25

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

23/12/25

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: Stable 2026 start for US steam coal

23/12/25

Viewpoint: Stable 2026 start for US steam coal

Cheyenne, 23 December (Argus) — US thermal coal markets are ending 2025 on a stronger footing than when they started the year, with producers expressing cautious optimism about 2026. Prices for most US thermal coal were at their highest levels since April-May 2023 in September and October. While steam coal prices have slipped in more recent weeks, they remain well-above year-earlier levels. US coal markets began to recover near the end of 2024, in response to a blast of colder-than-expected weather and higher natural gas prices. Coal-fired generation in at least some of the US continued to be above expectations through the third quarter of this year. This unanticipated boost offset lackluster seaborne coal pricing, leading US coal producers to focus their sales on US markets. Some producers expect to continue to favor domestic shipments over international markets in the coming year, given that US customers continue to be willing to pay more than international buyers. "We're still in negotiations for additional business next year," Core Natural Resources chief financial officer Mitesh Thakkar said on 6 November. "We certainly could increase some more volumes and get them exported. But I would say domestic is going to be year-on-year improved." The US Energy Information Administration (EIA) is expecting coal-fired generation to decrease next year largely because of continued power plant retirements. But generation may still be higher than in 2024. Some market fundamentals suggest generators could run remaining coal units at relatively elevated rates during peak demand seasons. Profit margins for running coal units in December, January and the first quarter of 2026 have been running higher than year earlier levels. In some cases, coal-fired generation also has been more profitable than power dispatch from some natural gas plants. For example, in the first 12 days of December, Argus assessed the peak day-ahead spark spread for 10,000 Btu/kWh coal units at the Indiana power hub — a reference point for central portions of the Midcontinent Independent System Operator — at an average of $27.44/MWh, while the margins for 8,000 Btu/kWh natural gas units were $26.14/MWh. Natural gas units also had less of a profit advantage over coal units in peak month-ahead and peak season Indiana power markets than they had in the first half of December 2024. Similar economic dynamics are present in the PJM Interconnection and Electric Reliability Council of Texas. President Donald Trump's full-throated endorsement of the coal sector, his moves to claw back environmental regulations and his administration's efforts to delay coal-plant retirements are boosting producers' confidence about US coal consumption in 2026. US energy secretary Chris Wright has invoked emergency powers to extend operations at Consumers Energy's JH Campbell plant until at least 17 February 2026. Consumers chief executive officer Garrick Rochow said on 30 October company officials expect the emergency orders for the Campbell plant to continue "for the long term". Independent of federal action, some utilities also have delayed a handful of power plant retirements and conversions previously scheduled for this year. All told, about 6,000-6,500MW of US coal capacity is being permanently taken off line or converted to another fuel this year, a sharp reduction from the 9,300MW projected at the very beginning of 2025, information collected by Argus and EIA show. The plant units that have delayed retirement dates consumed 6.7mn short tons (st) (6.1mn metric tonnes) of coal last year and 4.7mn st in the first eight months of 2025, EIA power plant operating data show. More retirements are scheduled for 2026, but some market participants have expressed uncertainty about their plans for next year, wondering if the Department of Energy (DOE) also will order their facilities to stay open. So far, DOE has directed Consumers' Energy's JH Campbell plant, which was scheduled to retire in May, three 90-day extension orders. And on 17 December, DOE also ordered Canadian utility TransAlta to delay retirement of its coal unit 2 in Centralia, Washington, for at least 90 days. Wright has indicated he could issue further orders. Some utilities — including CenterPoint, Dominion Energy, Southern Company subsidiary Georgia Power and Santee Cooper — have indicated they may delay coal plant retirements and conversions scheduled for 2026 and later. Most of the delays are short term and tied to revised timelines for bringing other facilities on line or incremental electricity growth, including potential data center additions. CenterPoint in October cited both economic reasons and greater load growth forecasts for reconsidering converting unit 3 of its FB Culley plant in Indiana to natural gas by the end of next year. The outlook for US exports is certain. Competition to place coal in European and Asia-Pacific markets remains steady. Those conditions could sustain downward pressure on some US thermal coal export prices and demand. But producers have expressed some optimism about 2026 US coal markets, with many having filled all of their projected sales book for next year and layered in contracts that have deliveries going out into 2027 and slightly later. And many market participants are thinking that stabilization might well continue into 2026. By Courtney Schlisserman Prompt season coal to gas differentials $/MWh Coal versus gas prompt month differentials $/MWh Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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Violent protests torpedo Colombia’s tax reform

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