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Viewpoint: US utilities worry over railcar supply

  • Market: Coal, Coking coal, Electricity
  • 02/01/25

US utilities are concerned that they may not have enough railcars to haul coal in the future as multiple power plants are seeking to remain in operation longer than expected.

Power demand is forecast to rise in the coming years because of planned data centers in multiple parts of the country. Many data centers are expected to open before new generation, including natural gas, wind and solar-power units, go into service.

A number of utilities want to avert the temporary power shortage by extending the life of coal-fired power plants beyond planned retirement dates.

In response, demand is "poised to shift to a slight growth in the need for coal cars", according to railcar expert Richard Kloster, president of Integrity Rail Partners. Longer power plant lives as well as expectations of increased metallurgical coal exports are likely to provide demand for equipment.

But the supply of railcars for coal has been slowly shrinking. No new railcars for the coal industry — primarily gondolas or open-top hoppers — have been built in nearly a decade. Utilities and leasing companies have had little interest in ordering new railcars for a shrinking sector.

Many existing cars have also been scrapped, particularly during periods of low coal demand and high scrap prices during the last few years.

There also are thousands of coal railcars in storage, but those do not really count towards demand, Kloster said. The cost of pulling those cars out of storage and making them service-ready is not necessarily cost effective, he said.

About 21pc of North American coal cars were in storage at the beginning of August, up from 15pc in November 2022, according to Association of American Railroads data. In comparison, about 35pc of the coal car fleet was in storage at the start of July 2020, near the height of the Covid-19 pandemic.

Possibilities of new construction

There is a chance that "in the next 10 years, there will be coal cars built again", because many coal cars in the fleet are nearing 50 years of age, Kloster said.

The retirement of many cars means that equipment must be pulled from storage or new units built, driving potential construction.

Under Association of American Railroads (AAR) rules, railcars built after June 1974 can only be interchanged with other railroads for 50 years. After that, those cars are generally limited to operating on only one carrier.

Some of those older cars may be retired early if they need repairs. Maintenance expenses could cause car owners to take units out of service.

Utilities strategize

Some utilities are already implementing plans to secure railcars, but others think taking additional steps will be unnecessary, according to railcar expert Darell Luther, chief executive of rail transportation firm Tealinc.

The differing views are tied in part to whether utilities are regulated by states or merchant-owned, Luther said. Public utilities need to prove to regulators they can meet generating needs, including having enough coal and railcars. Privately owned operators have more flexibility in terms of contracting for coal and railcars.

Several utility rail managers told Argus they do not see the need to take extra steps to secure railcars, confident that they already have plenty or can lease whatever they need in the future.

But other utilities said they have taken steps to ensure they have coal cars in the future.

Some utilities have purchased single or multiple cars as other generators sell them off. Others are increasingly leasing cars, with one utility saying that having more cars than needed is a cheap way of ensuring future supply.


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18/02/25

Japan approves new energy mix target, climate plans

Japan approves new energy mix target, climate plans

Tokyo, 18 February (Argus) — Japan has approved its targeted power mix portfolio for the April 2040-March 2041 fiscal year, as well as its new greenhouse gas (GHG) emissions reduction goal, it announced today. The new power mix goal, the centrepiece of the country's Strategic Energy Plan (SEP), is in line with Japan's aim to reduce GHG emissions by 73pc by 2040-41 compared to 2013-14 levels. Tokyo plans to submit the 2040-41 emission target, as well as a 60pc emissions reduction goal for 2035-36, to the UN climate body the UNFCCC on 18 February as the country's nationally determined contribution (NDC). The country has not made major changes to its draft proposal that it unveiled in December. The new SEP sees renewable energy making up 40-50pc of the country's power generation in 2040-41, up from 22.9pc in 2023-24. The share of thermal power will fall to around 30-40pc from 68.6pc, while that of nuclear will increase to around 20pc from 8.5pc during the same period. The 2040-41 target is based on Japanese power demand of 1,100-1,200 TWh, which is higher by 12-22pc from 2023-24. The government has planned the power portfolio so that it is not heavily dependent on one specific power source or fuel type, the country's minister for trade and industry (Meti) Yoji Muto said on 18 February, although the new plan suggests making maximum use of low-carbon power supply sources. Public consultation over 27 December-26 January revealed that some think Japan should slow or even stop the decarbonisation process, given the US government's reversal of its climate policies, including its withdrawal from the Paris climate agreement, said Meti. But global commitment to decarbonisation will remain unchanged, said Muto, adding that Japan will lose its industrial competitiveness if the country delays green transformation efforts. But US president Donald Trump's "drill, baby, drill" policy has prompted the Japanese government to delete a segment from the draft SEP that had initially proposed bilateral co-operation through Tokyo's green transformation strategy and the US' Inflation Reduction Act. Despite Tokyo's decarbonisation goals, the new SEP assumes that fossil fuels, including natural gas, oil and coal, will still account for over 50pc of primary energy demand in 2040-41 in all of its scenarios — although this is down from 93pc in 2013-14 and 83pc in 2022-23. The scenarios vary based on the degree of uptake of renewables, hydrogen and its derivatives, and carbon capture and storage (CCS) technologies, to fulfil the 73pc emission reduction goal by 2040-41. Worst-case scenario Tokyo also has also set out a potential worst-case scenario, assuming slower development of clean technologies, in which fossil fuels would still account for 67pc of primary energy supply in 2040-41. Under this scenario, which assumes Japan will only reduce its GHG emissions by around 61pc by 2040-41, natural gas is estimated to account for about 26pc, or 74mn t, of Japan's primary energy supply, which is higher than the 53mn-61mn t in the base scenarios that are formulated in accordance to the 73pc emissions reduction target. Japan would need to address the potential 21mn t gap in gas demand, which will mostly be met by LNG imports, in 2040-41, depending on the development of clean technologies. The gap is equivalent to 32pc of the country's LNG imports of 65.9mn t in 2024. When asked by Argus whether the government will continue to try securing LNG to ensure energy supply security when considering the worst-case scenario, a Meti official said Tokyo should continue pursuing its 73pc GHG reduction target, but it is necessary to consider the potential risks for each individual policy and the measures that need to be taken, instead of making decisions based on the worst-case scenario. The new SEP has highlighted the role of LNG in the country's energy transition and the necessity to secure long-term supplies of the fuel. It is unclear what ratio gas-fired capacity will account for in Japan's 2040-41 power mix, as the SEP does not include a breakdown of thermal generation. But gas-fed output is expected to take up the majority share, given that gas has already outpaced coal in power generation and Tokyo has pledged to phase out inefficient coal-fired plants by 2030. By Motoko Hasegawa and Yusuke Maekawa Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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India's domestic coal supply to utilities rises in Jan


18/02/25
News
18/02/25

India's domestic coal supply to utilities rises in Jan

Singapore, 18 February (Argus) — Domestic thermal coal supplies to Indian utilities rose in January as power plants continued to boost inventories. Combined coal supplies to utilities from domestic sources such as state-controlled Coal India (CIL), Singareni Collieries (SCCL) and captive blocks stood at 76.41mn t, up by 5.8pc from a year earlier, provisional data from India's coal ministry show. Supply was also up from 76.04mn t in December. Indian utilities continued to restock, although coal consumption at utilities was weaker than initially anticipated, as temperatures in most parts of the country were higher last month compared to historical averages, curbing power demand. India's coal-fired generation — which meets most of its power requirements — stood at 109.68TWh during January, down from 111.72TWh a year earlier, but up from 104.30TWh in December, Central Electricity Authority (CEA) data show. Higher domestic coal supplies and weaker coal burn supported stock positions at utilities. Combined coal inventories at Indian power plants stood at around 50.5mn t on 31 January, up from 45.2mn t on 31 December and higher from 38.59mn t as of 31 January 2024, according to CEA data. The inventory as of the end of January would last for over 17 days at the current daily coal consumption rate at utilities. Higher stocks and a steady uptick in domestic supplies might have pressured utility demand for imported coal and India's overall seaborne receipts last month. India imported 11.63mn t of thermal coal last month, down from 13.34mn t a year earlier, according to data from analytics firm Kpler. Imports reached 163mn t in 2024, down from 168.2mn t in 2023, Kpler data show. Indian power sector imports, which account for more than 40pc of the country's overall imports, dropped on the year for the fourth straight month in December , and might have eased in January. Combined thermal coal imports by Indian utilities, excluding captive power plants, stood at 3.25mn t in December, down by 2.17mn t or 49pc from a year earlier, CEA data show. Imports could come under pressure if the government does not extend its directive to imported coal-fired plants, which have a combined capacity of 17.7GW, to boost generation under Section 11 of the Indian electricity law, which also gives some flexibility to such generators to sell excess production in the power market. The directive is due to expire on 28 February. Production, supply mix The increased supplies to utilities were supported by higher overall thermal production. India's coal output rose by 4.4pc in January from a year earlier to 104.49mn t. The country's supplies to all sectors stood at 93.21mn t last month, up by 6.7pc on the year. CIL produced 77.79mn t in January, down from around 78.41mn t a year earlier, while it supplied 69.26mn t, rising from 67.52mn t last year, ministry data show. Of this, 55.01mn t of coal was supplied to the power sector in January, easing from 55.15mn t a year earlier. Meanwhile, output at coal producer SCCL rose by 5pc from a year earlier to 6.97mn t in January. But its overall supplies in January fell by about 1.5pc on the year to 6.12mn t, while dispatches to the power sector rose by 2.2pc on the year to 5.6mn t. Captive coal block producers and other small government mining entities comprised the remainder of the supplies to utilities in January. Output from captive coal blocks and other mining companies rose by over 31pc on the year to 19.72mn t in January, while supplies rose by nearly 30.7pc to 17.83mn t. Data on domestic coal supplies to Indian utilities do not include dispatches to captive power plants set up by industries. Supplies to such captive utilities — from sources such as CIL, SCCL and captive coal blocks — reached 6.29mn t in January, up by almost 9pc from a year earlier. Domestic supplies to steel and cement sector in January rose by 4.5pc and 31pc from a year earlier to 860,000t and 900,000t respectively, the ministry data show. By Saurabh Chaturvedi Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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Philippines to review shutdown of 232MW coal plant


17/02/25
News
17/02/25

Philippines to review shutdown of 232MW coal plant

Manila, 17 February (Argus) — The Philippines will review plans to retire the 232MW Mindanao coal-fired power plant in Misamis Oriental province because the rehabilitation of a major regional power complex could cause an electricity supply shortage. The country could put on hold plans to accelerate the retirement of the Mindanao coal plant to 2026 from 2031, the Department of Energy (DoE) said. The plant, majority owned by private-sector Aboitiz Power, started operations in 2006 under a build-operate-transfer (BOT) agreement with the National Power and Power Sector Assets and Liabilities Management. The plant was originally scheduled to be retired in 2031 once the BOT agreement had run its course and plant ownership transferred to the national government, but authorities later decided to shut it down by 2026. The plant consumes over 1mn t/yr of coal. Authorities might review the retirement plans to offset the loss of power supply from the 1,000MW Agus-Pulangi hydropower complex, which will be rehabilitated next year. The complex comprises seven hydropower plants and serves as a key source of baseload power in the Mindanao grid. It is currently capable of producing only 600-700MW of power because of siltation and ageing infrastructure. Parts of the power complex are over 50 years old and its oldest dam, Agus 6, started commercial operations in April 1971. The rehabilitation involves repairing, replacing and upgrading the components of an existing hydroelectric power plant to restore its functionality, improve efficiency and extend its lifespan. The complex will run at a derated capacity during rehabilitation works, which could take several years. This comes as power demand in the Mindanao grid continued to increase last year. Demand averaged 2.248GW in 2024, a 10.2pc increase from 2.040GW a year earlier. The Mindanao plant could supply enough power to keep the grid stable at its full capacity, by covering for the loss in generating capacity and meeting the increase in power demand, DoE added. By Antonio Delos Reyes Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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Japan’s economy grows in 2024


17/02/25
News
17/02/25

Japan’s economy grows in 2024

Osaka, 17 February (Argus) — Japan's economy expanded for a fourth consecutive year in 2024 as corporate investment increased, even as oil product demand fell. Gross domestic product (GDP) rose at an annualised rate of 2.8pc in October-December, according to preliminary government data released on 17 February, following growth of 1.7pc in July-September and 3pc in April-June. This sent Japan's full-year 2024 GDP up by 0.1pc from a year earlier, its fourth straight year of growth after a Covid-19 induced slump in 2020. Nominal GDP amount totalled ¥609.3 trillion ($4 trillion) in 2024, exceeding ¥600 trillion for the first time. Investment by private-sector companies rose by 1.2pc from a year earlier in 2024, recording annualised growth of 1.9pc in October-December. The rise partially reflected a government push for a green and digital transformation of the economy in line with its 2050 net-zero emission goal. Such spending is expected to continue to increase under Tokyo's economic stimulus package. Japanese business federation Keidanren has forecast that nominal capital investment could rise to ¥115 trillion in the April 2027 to March 2028 fiscal year, up by 7.5pc from an estimated ¥107 trillion in 2024-25. But private consumption, which accounts for more than 50pc of GDP, dropped by 0.1pc from a year earlier in 2024, as inflation capped spending by consumers. This also probably weighed on demand for oil products such as gasoline, despite government subsidies. Japan's domestic oil product sales averaged 2.4mn b/d in 2024, down by 5.2pc from a year earlier, according to data from the trade and industry ministry Meti. Gasoline sales, which accounted for 31pc of the total, dropped by 2.2pc to 752,700 b/d over the same period. But Japanese electricity demand edged up by 0.7pc year on year to an average of 98.8GW in 2024, according to nationwide transmission system operator the Organisation for Cross-regional Co-ordination of Transmission Operators. Stronger power demand reflected colder than normal weather in March and unusually hot weather in October. Japan's real GDP is predicted to rise by 1.2pc during the 2025-26 fiscal year, following predicted 0.4pc growth in 2024-25 and a 0.7pc rise in 2023-24, the Cabinet Office said on 24 January. The figures are the Cabinet Office's official estimates and form the basis of its economic and fiscal management policies. 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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Brazil’s offshore wind gains momentum


14/02/25
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14/02/25

Brazil’s offshore wind gains momentum

New York, 14 February (Argus) — Brazil is preparing for its first offshore wind projects following the approval of legislation that establishes a regulatory framework for investments in the sector. Industry leaders anticipate that this legal foundation will accelerate development, with the first auction for offshore wind areas expected soon. The move comes as Brazil seeks to leverage its vast wind resources and address slowing growth in its onshore wind sector. "The offshore wind law was approved at the right moment," said Elbia Gannoum, president of Brazilian wind association Abeeolica. "Brazil has one of the largest wind generation potentials, and without this law, the country risked missing investment opportunities." The new legislation comes as onshore wind expansion slows. After nearly 5GW of new wind capacity was added in 2023, investment declined, with capacity expanding by just 3.3GW last year, according to Abeeolica. A lack of demand from power distributors in energy auctions and an oversupply of power generation capacity have contributed to the slowdown. With limited demand for new projects, equipment suppliers have scaled back operations, and in some cases, suspended activities in Brazil. With the offshore wind law in place, the sector is optimistic that the government will hold its first auction for offshore wind areas this year or in early 2026. Awarding these areas would pave the way for Brazil's first offshore wind projects to begin operations by 2031 or 2032. Before the auction, the government must finalize regulations for the sector, which Gannoum expects will be complete this year. Companies have already begun preparing for the auction, conducting assessments of wind speeds, power transmission infrastructure and supply chains, according to Ricardo de Luca, Brazil country director for UK offshore wind developer Corio Generation. Once the areas are awarded, project development could take up to four years, followed by an auction for power purchase agreements in 2028, de Luca estimates. Corio plans to develop five offshore wind projects in Brazil, totaling 5GW of installed capacity. Wind developers warn that Brazil must also prepare its power transmission infrastructure for future offshore wind projects. "Even though areas haven't been awarded, the mines and energy ministry must start planning transmission infrastructure in regions with significant offshore wind potential," said Fernando Elias, regulatory director at Casa dos Ventos. "Without long-term planning, infrastructure bottlenecks could prevent projects from moving forward." While transmission constraints could pose challenges, Brazil has an advantage in developing offshore wind thanks to its established offshore oil and gas industry, said Renato Machado dos Santos, regional director of renewable energy at RES. "There is significant overlap in the supply chains for offshore wind and oil, which will not only accelerate investment but also make Brazil a more attractive destination for investors." Opportunities ahead? Despite potential hurdles, offshore wind developers remain cautiously optimistic. US president Donald Trump's 20 January executive order suspending offshore wind leasing and permitting could shift more investor interest toward Brazil. "Trump's policies have redirected attention to Brazil," de Luca said, adding that the Brazilian government has demonstrated a long-term commitment to renewable energy development. Beyond the offshore wind law, other recent legislation is expected to bolster demand for power from future offshore wind projects. This includes the approval of the low-carbon hydrogen law, which will drive demand for green fertilizer production. Additionally, the expansion of data centers for artificial intelligence and growing electricity demand from electric vehicle adoption will contribute to future power consumption in Brazil, a share of which will come from offshore wind projects, Gannoum said. Brazil’s onshore wind capacity GW Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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