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Viewpoint: US utilities worry over railcar supply

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

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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25/03/21

Low snowpack, rain may lift Italian summer power prices

Low snowpack, rain may lift Italian summer power prices

London, 21 March (Argus) — Low snowpack and hydro reserves in Italy may increase the call on gas-fired power plants this summer, likely supporting power prices in days when renewable generation is weakest. Hydro generation from run-of-river installations, pumped-storage plants and hydroelectric reserves accounted for almost 20pc of the power mix on average over 2020-24 in the third quarter — the second-highest share after the second quarter at 22.2pc — compared with gas-fired generation covering 45pc. But prevailing conditions suggest that without unusually wet weather this summer, Italian rivers could be drier than normal, limiting scope for hydro output and potentially opening more space for gas in the power mix, driving up electricity prices. Snow water equivalent — or the estimated water content of snow — moved back to a deficit to last year's levels on 23 February after showing signs of improvement over the first three weeks of the month, according to Italian meteorological association Cima. Snowpack was at a deficit of 57pc to the 2011-23 average as of 8 March, narrowing slightly compared with a 58pc deficit around the same time in February. The deficit in the Po basin, which accounts for almost half of Italy's snow water resource, is currently at a 44pc deficit to the seasonal norm, Cima data show. In the Apennines, the Tiber basin is at a 95pc deficit to the long-term average, marking the worst balance of the last 13 years. And hydro reserves have been at a consistent deficit to last year since January and moved to a deficit to the five-year norm in the middle of February. Rainfall in Malpensa and Paganella, in the north of the country, was at an average deficit of almost 2 mm/d and 1.6 mm/d, respectively, to the seasonal norm over November and December last year. While precipitation picked up in January and moved to a surplus to the norm of 1.9 mm/d in Malpensa and 1.4 mm/d in Paganella, minimum temperatures were 1.6°C above the long-term average in Milan, reducing snow accumulation. The latest data show that hydro reserves have picked up for the first time this year in week 11, reaching 2.1TWh and narrowing their deficit to the 2020-24 average to 0.8pc compared with 5.2pc a week earlier. Still, they remain 6.6pc below last year, with the deficit standing even wider at 9.1pc, when compared with the 2015-24 average. Looking ahead, forecasts indicate that minimum temperatures in Milan will hold around 2°C above the 10-year norm until the end of April, possibly leading some snowmelt to support run-of-river generation early in the second quarter, when power demand is typically at its lowest. But this would also leave less snow to melt later in the summer, when cooling demand peaks and drives up overall demand for electricity. While solar capacity increased steadily by over 500MW a month last year, the share of the power mix covered by solar output in the third quarter of 2024 remained almost unchanged from the same period in 2023. Assuming a similar monthly growth in photovoltaic (PV) capacity this year, the solar load factor is expected to increase by 1.8 percentage points to 17.8pc in the third quarter of 2025 on the year. This means that even if solar capacity and output continue growing, it may not be enough to offset a lack of hydro generation in the third quarter of this year, and thermal generation may still need to cover a significant amount of residual demand. The third quarter of 2025 has averaged €135.85/MWh ($146.83/MWh) so far this quarter, well above an average €91.60/MWh seen over the same period last year. Clean spark spreads for 55pc-efficient gas-fired units for the third quarter of 2025 have averaged around €19.60/MWh since the start of the year, compared with an average of €15.50/MWh over the same time last year. As solar and wind capacity is set to increase over the coming years to reach a national target of 110GW by 2030, renewable output will cover an increasing share of Italian electricity demand — estimated to reach 335TWh in 2028. Thermal plants may become less economically viable and will likely be decommissioned unless they are kept operating through ancillary services. But turning on gas-fired plants from cold and with a stop-start operation would lead to exaggerated costs and higher maintenance prices, Argus heard on the sidelines of the KEY25 Energy Transition Expo in Rimini earlier this month. This could lead to electricity prices spiking in periods of scarce hydro availability, as hydro-run-of river is Italy's largest single source of renewable generation, accounting for 17pc of the power mix last year compared with less than 5pc of hydro-pumped storage and reservoirs. By Ilenia Reale Italian hydro stocks TWh Gas and hydro output, hydro reserves GW, TWh Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Australia's Simcoa may buy carbon credits until 2028


25/03/21
25/03/21

Australia's Simcoa may buy carbon credits until 2028

Sydney, 21 March (Argus) — Australia's silicon producer Simcoa will likely need to buy and surrender Australian Carbon Credit Units (ACCUs) until 2028 for safeguard mechanism compliance obligations before it completes a key decarbonisation project, it told Argus today. The project was awarded federal funds on 20 March. Australia's federal Labor government granted Simcoa A$39.8mn ($25mn) under its Powering the Regions Fund (PRF) to expand charcoal production at its Wellesley facility in Western Australia (WA) and remove the use of coal in silicon production. The project is expected to reduce the company's scope 1 emissions by around 90pc, or approximately 100,000 t/yr of CO2 equivalent (CO2e). Simcoa is Australia's only silicon manufacturer, which is a key component of solar panels. The funding will help maintain silicon manufacturing capability in the country in addition to cutting emissions, energy minister Chris Bowen said. The company currently uses 35,000 t/yr of metallurgical low ash coal in its operations, and anticipates usage will drop to zero after it doubles its charcoal production capacity by 25,000 t/yr to 50,000 t/yr. The completion date for the expansion is not expected before 2028. The firm may continue to buy [ACCUs] as it must use coal as a reducing agent for part of its production for calendar years 2025-27, or until the expansion project can be commissioned, the company told Argus on 21 March. Simcoa surrendered 22,178 ACCUs in the July 2022-June 2023 compliance year as it reported scope 1 emissions of 122,178t of CO2e with a baseline of 100,000t CO2e at its Kemerton silicon smelter. Figures were lower for the July 2023-June 2024 compliance period, the company said, without disclosing details. Australia's Clean Energy Regulator (CER) will publish 2023-24 safeguard data by 15 April . Simcoa anticipates scope 1 emissions at the Kemerton smelter to be "considerably below" the baseline once the charcoal expansion is completed and could make it eligible to earn and sell safeguard mechanism credits (SMCs), which traded for the first time in late February . "We will take whatever opportunity is available to us," the company said on potentially holding or selling SMCs in future. By Juan Weik Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Upper Mississippi River reopens for transit


25/03/20
25/03/20

Upper Mississippi River reopens for transit

Houston, 20 March (Argus) — The first towboat arrived at St Paul, Minnesota, today, marking the start of the 2025 navigation season on the upper Mississippi River, according to the US Army Corps of Engineers (Corps). The Neil N. Diehl passed through Lock 2 at Hastings, Minnesota, with nine barges, crossing into St Paul on 19 March. Tows reaching St Paul signify the unofficial start of the navigation season, as St Paul is the last port to open on the Mississippi River after winter ice thaws each year. This is considered an average start time for the navigation season, which typically opens the third week of March. The first tow to reach St Paul in 2024 arrived on 17 March. The Corps released the final Lake Pepin ice measurements of 17in on 12 March and was unable to take new measurements this week since the ice had melted significantly. Lake Pepin measurements help determine when the ice will be thin enough for barges to transit up river. By Meghan Yoyotte Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Canberra backs Li battery projects in Western Australia


25/03/20
25/03/20

Canberra backs Li battery projects in Western Australia

Sydney, 20 March (Argus) — Australia's federal government will partly underwrite four lithium-ion battery projects in Western Australia (WA), boosting the state's energy storage capacity by 2.6GWh from late 2027. Canberra is supporting the projects through its Capacity Investment Scheme (CIS), which sets a revenue floor on big battery projects for up to 15 years. The government has not revealed the specific revenue floors linked to the newly underwritten projects. Australian renewable energy developer PGS Energy will build the largest of the four newly-underwritten batteries, a 1.2GWh energy storage system in Marradong. The company's Marradong battery will be co-located with a solar farm and connected to WA's South West Interconnected System (Swis), a grid stretching across its most populous regions, once it becomes operational. French energy producer Neoen is also developing a 615MWh project just outside Perth, under the scheme. The company has been building large batteries across Australia, with public support, for multiple years. Its Collie Battery Energy Storage System is connected to Swis, and has been storing and discharging 877MWh of energy since October 2024. The two other batteries underwritten on 20 March are smaller, with a combined capacity of 780MWh, and located in rural parts of the state. The Australian government's latest funding announcement comes just months after it on 11 December 2024 underwrote eight other Australian battery projects capable of storing 3.6GWh of power under the CIS. Those projects were scattered across the country, covering three states but excluding WA. Canberra will also underwrite another set of batteries, with a combined capacity of 16GWh, in September. Over 100 projects, with a combined capacity of 135GWh, have applied to be part of CIS' September funding round. By Avinash Govind Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Australia must rethink gas strategy: Grattan


25/03/20
25/03/20

Australia must rethink gas strategy: Grattan

Sydney, 20 March (Argus) — Australian think-tank Grattan's Orange Book 2025: Policy priorities for the federal government report suggests redesigning Canberra's future gas strategy, coordinating a shift away from gas for households and some industries while changing market control mechanisms. Australia's next federal government must act to address a shortfall of gas in the country's southeastern states by creating a demand response mechanism for the national gas market and bringing together stakeholders to permit initial LNG imports in mid-2026, according to Grattan. Australia has always been both an exporter and importer of LPG, proving it is possible to build infrastructure to ship gas to the nation's south for the next 3-4 years in line with expected shortfalls, director of Grattan's energy program Tony Wood told a Sydney forum on 19 March. Building or expanding gas pipelines would be expensive and inefficient as the nation decarbonises, Wood said, with less gas forecast to be used as Australia targets net zero emissions by 2050. Canberra should institute a working group involving producers, users, traders, terminal owners, governments and the Australian Competition and Consumer Commission — which reports on market supply — to achieve seasonal imports of LNG in winter months, according to the Grattan report. A rule change to create a demand response mechanism akin to that under national electricity market rules would assist in meeting small shortfalls, such as during severe weather or unexpected supply outages. Demand is expected to rise on the back the closure of coal-fired power stations in the 2030s, according to Canberra's future gas strategy released in 2024. Gas-fired power demand may double in the decade to 2043 because of the need to support a solar and wind-heavy grid. This requires a reworking of the future gas strategy to specify plans to reduce demand and clarify future gas requirements outside of power generation, Grattan's report said. Assistance for households and industries to electrify processes is also needed, together with optimising infrastructure to ensure residual users in power generation and industry can access gas supply. The main controls on east coast gas grids, the Australian Domestic Gas Security Mechanism (ADGSM) and code of conduct , should be revised to allow for interstate transfers of gas, Grattan said, likely from Queensland's Gladstone-based LNG projects to the southern states. The code of conduct, which mandates an A$12/GJ ($8/GJ) price on domestic gas, came into effect in 2023 amid booming global gas prices but must be reviewed in 2025. Australia's energy and climate change ministerial council met on 14 March but declined to decide on expanding the Australian Energy Market Operator's powers, to enable it to address the gas shortage possibly through underwriting LNG import terminals. More analysis will be commissioned ahead of a decision at the next meeting in mid-2025. By Tom Major Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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