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Solar, Bess tax breaks clear Mexico's lower house
Solar, Bess tax breaks clear Mexico's lower house
Mexico City, 14 October (Argus) — Legislation to accelerate recovery of start-up capital for solar power and battery energy storage passed Mexico's lower house on Wednesday, clearing a final article-by-article review in a 322-115 floor vote. The clean energy incentives — structured as accelerated depreciation rules under the federal income tax law (Lisr) — advance as a core element of the 2027 revenue package. The initiative now heads to the senate for ratification, which is expected to conclude well before the chamber's 31 October legal deadline to pass the revenue side of next year's budget. If approved, the new rules will take effect on 1 January 2027. The tax reform proposal specifically aims to modify the federal income tax law, as part of an overhaul to Mexico's simplified tax framework (Resico). It establishes that eligible companies may double their annual tax depreciation rate on physical equipment and infrastructure to 40pc from 20pc. The provision could cut capex recovery times in half, typically to 2.5 years from 5 years, for small- and mid-sized solar and backup energy developers. However, industry analysts point out a significant trade-off that limits the reform's broader impact. As the incentive is strictly tethered to the Resico framework, it is bound by the regime's updated annual gross revenue cap of Ps50mn ($2.6mn). Renewable energy advocates argue the cap is too low and sets up a mixed outcome for the industry . While it stimulates small-scale distributed generation and commercial rooftop installations, utility-scale developers are largely excluded from the tax break. Under the new Lisr, amortization is now limited to 50pc of taxable profit for these companies, a limit analysts argue creates a baseline annual tax cash drain regardless of cumulative development capex. Furthermore, companies exceeding the revenue cap will now be restricted from fully utilizing the standalone 100pc immediate renewable asset deduction established under article 34 of the income tax statute. Financing costs for capital-intensive generation networks also face adjustment, as the legislation lowers the threshold for net-interest deductions on corporate project debt to 20pc from 30pc of adjusted taxable income. By James Young Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.
PJM defers 10,000MW of outages during Oct heat spell
PJM defers 10,000MW of outages during Oct heat spell
Houston, 13 October (Argus) — PJM Interconnection, operator of the US' largest grid, has asked power-plant owners to defer 10,000MW of planned outages to maintain reserve margins during this week's unseasonably warm temperatures. Generation outages are expected to total about 62,000MW on 14 October, the date for which PJM issued a maintenance outage recall. About 10,000MW of capacity was deferred to arrive at that sum, PJM said in an email to Argus . PJM forecast peak demand at roughly 111,500MW on 13 October and projected reserves would narrow to within about 900MW of required levels on 14 October even with the outage deferrals. PJM issued multiple emergency alerts covering 12-14 October, warning customers that the grid faces tight conditions. In response to the alerts, the US Department of Energy authorized PJM to temporarily suspend environmental restrictions, allowing it to implement emergency reliability measures, including asking some generators and transmission lines to remain operational or requesting some large-load consumers switch to back up generation if needed. The alerts come as PJM grapples with growing electricity demand and a shrinking window for routine maintenance, which typically occurs during North America's spring or fall seasons. Increasing baseload demand and increasingly unpredictable weather patterns are making it difficult to perform maintenance during periods that historically carried lower reliability risks. Earlier this year, the North American Electric Reliability Corporation warned that the nation's grid operators are increasingly facing reliability challenges outside of traditional peak demand periods, known as shoulder seasons. It noted that this year's March was the warmest in 132 years of recordkeeping, making the grid more vulnerable during a period when the system is not typically configured for high demand. "This is the new reality that grid operators are facing," PJM said. "Planned maintenance season will continue to present risks that we formerly faced only in summer and winter." Temperatures across much of the PJM region, which spans 13 states along the mid-Atlantic and into the Midwest and the District of Columbia, are expected to remain above seasonal norms through mid-October, boosting cooling demand. The winter heating season traditionally begins on 1 November. By Jasmina Kelemen Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.
High diesel prices weigh on US coal producers
High diesel prices weigh on US coal producers
New York, 13 October (Argus) — High diesel prices stemming from the US-Iran war are increasing costs for US coal production and transportation, potentially boosting prices and curbing available supply into 2027, according to producers and buyers. Diesel is a major operating expense for surface mines, and it is also factored into rail, barge and truck fuel surcharges. Rising costs first started worrying some coal market participants when prices rose sharply in March at the outset of the US-Iran war , and that concern has only grown with the war in its eighth month with no end in sight. US retail diesel price hit an all-time high in the week ended 21 September, averaging $6.529/USG, according to US Energy Information Administration (EIA) data. While retail prices fell to $6.199/USG in the week ended 5 October, that was still $2.30/USG higher than the weekly average before the start of the US-Iran war and 53pc above values in the first weeks of October in 2021-25. Producer margins under pressure High diesel prices are having the biggest effect on Powder River basin (PRB) and Central Appalachian coal mines. Surface mines are particularly exposed because diesel fuels large-haul trucks, loaders and other mobile equipment. Producers that did not fully hedge their fuel consumption have had little protection from the sharp increase, one coal producer said. Midwest miners who had to buy fuel not under contract would have paid an average $6.286/USG in the week ended on 5 October, while those in the Rocky Mountains would have paid $6.276/USG, EIA data show. A year earlier, average prices were were $3.67/USG in the Midwest and $3.671/USG in the Rocky Mountains. "Higher production costs will drive up the floor price that producers are likely to demand," another market participant said. But many producers cannot fully offset operating cost increases in the short term, at least partly because a majority of coal currently being produced is being supplied under contracts that predate the spike in diesel prices. Operators also have limited ability to reduce diesel consumption without cutting equipment use or production. The effect may be most consequential among producers operating near break-even levels. The two largest PRB producers, Peabody Energy and Core Natural Resources, reported negative PRB cash margins in the second quarter. Peabody's PRB segment recorded a $7.1mn loss in adjusted earnings before interest, tax, depreciation and amortization, while Core Natural reported a $5.8mn adjusted loss from its PRB operations. In Central Appalachia, mining costs had already trended higher for the several years because of thinning mining seams and higher labor costs. Added cost pressures from diesel prices since March have further amplified profit-margin pressures, according to producers in the basin. Going into 2026, producers indicated that costs to produce Central Appalachian coal at a surface mine, load the product onto trucks and transport it to railroads totalled $80-$90/short ton (st). Sources say those costs have increased since the start of the war by least $6-8/st, with much of the additional expense linked directly to surging diesel prices. Elevated fuel costs may prompt some US miners to scale back output as soon as next year, a few producers told Argus. To protect their margins, US coal producers may also seek higher prices or push for adding fuel-related adjustments to contracts. Fuel adjustments are already common in Central Appalachian term agreements to account for at least some of the costs related to shifts in diesel prices, but the number of utilities willing to enter these longer-term commitments have faltered in recent years, and many rely more on purchasing coal from the basin on a spot basis. Still, buyers facing escalating rail surcharges may resist paying more for the coal itself. Sustained increases could affect the relative economics of coal-fired power generation, particularly at plants receiving coal over long rail distances or competing against natural gas generation. Transportation costs climb with lag Fuel surcharge pricing mechanisms differ by transportation company and contract. Many railroads use a monthly average diesel price from one or two months earlier, meaning that the September spike will continue flowing into freight costs even after weekly prices retreat. This could influence some coal producers' interest in exporting coal, since producers pay the cost of shipping coal to export terminals. But the greater effect on the US coal industry might be on domestic buyers. Some US power plant operators, which pay for transportation to their facilities, have not yet adjusted coal consumption and purchasing plans because of high diesel costs, but they monitor diesel prices closely. The monthly average on-highway diesel fuel price for August, which some railroads apply to fuel surcharges on contracted October coal shipments, increased to $5.462/USG from $3.744/USG a year earlier, according to EIA. This raised Union Pacific's surcharge for southern PRB coal trains shipped this month to around 70¢/mile from the 41¢/mile charge applied to shipments in October last year, equivalent to about $2.58/st increase on PRB coal shipped to the St. Louis region, according to Argus calculations. With diesel prices rising further in September, the average fuel surcharge for PRB coal shipments in November will climb to 84¢/mile. Among eastern US rail carriers, CSX's surcharge for October deliveries nearly doubled to 87¢/mile from 44¢/mile a year earlier, and the surcharge will rise further to $1.07/mile for November deliveries. By Elena Vasilyeva and Anna Harmon Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.
Australia’s NSW eyes gas-fired power tender in 2027
Australia’s NSW eyes gas-fired power tender in 2027
Sydney, 13 October (Argus) — Australia's New South Wales (NSW) government plans to launch a tender in early 2027 to support 1.5GW of mostly new gas-fired power capacity that would need to be on line by 31 May 2033 as more of the state's ageing coal-fired plants retire. The tender would be open to different technologies but projects would need to demonstrate "net energy contribution" — or that they increase the total volume of electricity supplied to the system and do not rely on energy consumed from the grid to deliver the contracted capacity — which would exclude standalone batteries or pumped hydro. Projects would also need to be able to dispatch power when required and maintain supply over periods of at least eight hours. Gas-fired plants would therefore be "well placed" to provide all three requirements and make a material contribution to addressing future reliability risks identified by tender operator AusEnergy Services (ASL), an arm of the Australian Energy Market Operator (Aemo), the firm said today. "We expect most of that [1.5GW] will be through gas peaking," NSW energy minister Penny Sharpe said today at the Australian Financial Review (AFR) Energy and Climate Summit in Sydney. Gas-fired power accounts for just around 2pc of NSW's annual electricity generation, a "small but very significant" part of the system, Sharpe said on 13 October. The share could increase to around 3.9pc by 2050, according to Aemo's 2026 Integrated System Plan (ISP) "step change scenario". NSW is forecast to face a power capacity shortfall of around 1.5GW from 2033-34 following the expected closure of the 2.71GW Bayswater and 1.36GW Vales Point coal-fired power plants. Public consultation on tender design Gas-fired projects have been allowed to bid in firming tenders in NSW under the state's long-term energy service agreement (LTESA) framework but have not been able to compete with batteries. ASL opened a public consultation today on potential changes to the design of a firming LTESA tender to specifically support gas-fired plants. It is asking feedback until 4 November on several points, including setting the default contract term to 20 years to provide long-term revenue certainty more closely aligned to the expected economic life of a gas-fired plant, as well as introducing a cost adjustment regime that takes into account currently "elevated" risks of significant price increases to procure gas turbines globally due to demand from data centres. Strong bids in the future tender are also expected to include long-term gas procurement arrangements and fuel storage capability. The NSW government had already flagged upcoming support to gas-fired power in its Future of Gas Statement released last week. Gas projects are not allowed in the federal Capacity Investment Scheme (CIS), which was launched in 2024 to support the country's legislated 82pc renewable electricity target for 2030. Some Australian utilities and market experts had been asking for support for gas-fired power in recent years, including from the federal government. Aemo forecasts Australia will need 17GW of gas-powered generation by 2050 to support the future electricity grid, up from less than 13GW currently. Australian utility and upstream operator Origin Energy last month disclosed plans to build a 1.2GW gas peaking power plant near Marulan in NSW that could begin operation in 2033, which might make it suitable for the tender. Utility EnergyAustralia is planning an even larger gas plant in that same region, the 1.43GW Marulan facility, which could come on line in 2032. ASL said it will decide closer to 2030 whether a contingent tender would be required. By Juan Weik Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.
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