Duke Energy to retire coal fleet by 2035

Spanish Market: Electricity
10/02/22

US utility Duke Energy says it will stop burning coal by 2035, 13 years earlier than previously planned, as part of an expanded clean energy action plan.

The plan also calls for cutting coal's share of Duke's energy mix to less than 5pc by 2030. Coal accounted for 22pc of Duke's net generation last year.

The utility called its exit from coal the "largest planned coal fleet retirement in the industry." And the announcement comes less than a year after Duke said it planned to stop using coal by 2048.

Duke already started to suggest, shortly after last year's announcement, that it could hasten its coal plant exit. The preferred scenarios in integrated resource plans filed with state regulators in September and December 2021 listed closing its coal fleet in North Carolina by 2030 and coal plants in Indiana by 2035. The company also had put retiring the Crystal River coal plant in Florida in 2034 and closing the East Bend generating station in Kentucky in 2035 in the preferred scenarios for integrated resource plans in those states.

"The energy sector must transform for the future in a way that also benefits our society today," Duke chief sustainability officer Katherine Neebe said yesterday. "Achieving this vision will require us to transition to low- and zero-emissions fuel sources, invest in our communities and develop and prepare a diverse workforce."

Duke also expanded its goals for having net-zero greenhouse gas emissions by 2050 to include no longer buying fossil fuel-based power from other generators. And it has added a new net-zero target for its natural gas business that includes upstream methane and carbon emissions related to purchased gas as well as downstream emissions from customers' energy use.

The company also is examining indirect emissions from its value chain and will eventually design a plan for Duke to limit those emissions in its portfolio. It said it will share more details on those initiatives during its ESG Investor Day later this year.

Duke said it is on pace to achieve its previously announced target of reducing CO2 emissions by at least 50pc by 2030 from 2005 levels, and to be carbon-neutral by 2050. Its emissions already are 44pc below 2005 levels, it said.

Duke has retired 56 coal units with a combined capacity of about 7,500MW since 2010. It has more than 16,000MW of remaining coal capacity spread across 11 facilities. Together, they consumed about 20mn short tons (st) (18mn metric tonnes) of coal from January-November 2021, according to the latest data from the US Energy Information Administration (EIA).

The coal units received about 14.7mn st of coal in the same period. Deliveries included about 7.8mn st of Illinois basin coal, 4.4mn st of Northern Appalachian coal and 2.4mn st of Central Appalachian coal, EIA fuel receipts data show. Alliance Resource Partners, American Consolidated Resource Partners, Consol Energy and Peabody Energy were among the top suppliers.

Duke would use natural gas and renewable energy to replace coal capacity in North Carolina and Indiana. In the latest integrated resource plan Duke filed in the Carolinas, its preferred roadmap for future load and generation calls for adding 9,600MW of natural gas-fired power through 2035 and nearly quadrupling its solar capacity to more than 15,500MW by that year.

The preferred scenario in Indiana modeled adding 7,325MW of renewable generation.

By Nick Georgiou

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08/01/25

Singapore, Malaysia to collaborate on CCS, RECs

Singapore, 8 January (Argus) — Singapore and Malaysia have signed agreements to collaborate on carbon capture and storage (CCS) as well as renewable energy certificates (RECs). The countries will engage in bilateral discussions to enable cross-border CCS, and discuss the components of a legally binding government-to-government agreement, said Singapore's Ministry of Trade and Industry (MTI) on 7 January. A joint committee comprising members from both sides will be established to facilitate this. The countries will also share best practices and information, and facilitate relevant research projects. The region has strong geological potential for CO2 storage, said the MTI. "Many countries are interested to pursue CCS to support their own decarbonisation plans and position themselves as CCS hubs for Asia-Pacific," it added. Malaysia has a geological abundance of deep saline aquifer reservoirs , which could be used to develop large-scale, permanent CO2 storage solutions. RECs Singapore and Malaysia will also study the formation of a credible framework that recognises RECs associated with cross-border electricity trade. The development of the framework will catalyse demand for cross-border electricity trading projects, which will lead to higher investment that can support the long-term viability of regional renewable energy projects, said the MTI. Singapore's licensed electricity importer Sembcorp Power signed a supply agreement with Malaysia's state-owned utility Tenaga Nasional Berhad (TNB) last month to import 50MW of renewable energy issued with RECs , with the renewable energy to be imported via existing infrastructure. Flows into Singapore began on 13 December. The agreement is part of Malaysia's inaugural "green electricity" sales through its Energy Exchange Malaysia (Enegem) platform, which allows for cross-border green electricity sales to neighbouring countries. Almost 28,000 MWh of electricity has been traded under the Energem platform as of 7 January, according to MTI. State-owned electricity firm Singapore Power and TNB are also undertaking a joint feasibility study to expand interconnector capacity and infrastructure between Singapore and Malaysia, said the MTI. Cross-border power initiatives in the region have been growing, such as the recent increase in capacity of the Lao PDR-Thailand-Malaysia-Singapore Power Integration Project (LTMS-PIP) to up to 200MW under its second phase . Inaugural flows from Malaysia to Singapore began in September 2024, and almost 8,000 MWh of electricity has been traded under this phase as of 7 January, according to MTI. By Prethika Nair Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Brazil's EV sales hit record high in 2024

06/01/25

Brazil's EV sales hit record high in 2024

Sao Paulo, 6 January (Argus) — Brazil's sales of electric vehicles (EVs) increased by 90pc to a record 177,360 units in 2024, according to the electric vehicle association ABVE. EV sales last year rose from 93,930 units in 2023. That includes battery electric vehicles (BEVs), hybrid electric vehicles (HEV), micro hybrid and mild hybrid electric vehicles (MHEV), plug-in hybrid electric vehicles (PHEV) and flex HEVs. Disregarding micro hybrid units, which are not considered fully electrical, EV sales reached 173,530 last year, an 85pc increase from 2023. Plug-in market rising Sales of plug-in vehicles — including PHEVs and BVEs — totaled almost 125,625 in 2024, representing a 71pc of total EV sales and more than double from the 52,360 units sold in 2023. The expansion of the recharging infrastructure in Brazil drove the plug-in market growth, reducing concerns about the utilization of EVs in long-distance travels. There were more than 12,000 charging stations in the country as of early December, according to charging station management platform Tupi Mobilidade. Hybrid vehicles without external chargers — such as HEVs, flex HEVs and MHEVs — accounted for 29pc of total sales in 2024, with around 51,735 units, a 24pc hike from 2023. Sao Paulo keeps leading the way Southeastern Sao Paulo state remained the leader of EV sales in Brazil, with nearly 56,820 units sold and accounting for 32pc of total sales, followed by federal district Brasilia, with 9pc. Rio de Janeiro, Parana and Santa Catarina states represented 7.2pc, 6.8pc and 6.5pc, respectively, of Brazil's EVs sales. By Maria Albuquerque Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Italian gas-fired output down as RES grow in 2024

02/01/25

Italian gas-fired output down as RES grow in 2024

London, 2 January (Argus) — Italy's gas-fired generation in 2024 was the lowest in six years, owing to higher generation from renewable energy sources (RES), supported by additional capacity. Gas-fired generation fell to 10.7GW in 2024, from 11GW in 2023, accounting for 40pc of the power mix — the lowest percentage since 2019. Gas-fired output was displaced by growing renewables generation, which accounted for another 40.8pc of the mix, compared with 37.9pc in 2023. Higher renewable generation in 2024 was supported by a rise in installed capacity, up by 11pc to 75.8GW as of November. Solar capacity rose the most on the year, up by 6.8GW but still 3.6GW below the halfway mark for the 80GW target for 2030, and wind capacity rose by about 600MW. Solar output rose on the year, up by 400MW, while onshore wind generation fell by 200MW. While installed hydro capacity remained flat from 2023, hydro generation recorded the most significant increase, rising from 4.6GW to 5.9GW on the year and accounting for 22pc of the mix, as hydro stocks remained above the five-year norm up until the first half of April, owing to higher-than-average precipitation. Italy aims to have 131.3GW of installed renewable capacity by 2030, as laid out in the country's national energy and climate plan . As of November, there were almost 6,000 connection requests in place for solar plants, and onshore and offshore wind farms, with a total capacity of nearly 350GW. The Italian government has approved a renewables support scheme it hopes will speed up project authorisation. And the European Commission has approved a €9.7bn scheme to develop renewable plants for a total capacity of 17.65GW. Demand edged up on the year to 31.8GW, compared with 31.6GW in 2023, and domestic generation accounted for 26.6GW, up by 300MW on the year. Italy remained a strong net importer throughout 2024, despite net imports falling by 200MW to 5.9GW, compared with 2023. Total imports were the highest since 2018 at 6.6GW, with France and Switzerland accounting for almost 80pc. Total exports gradually increased in 2024, up by 90MW, compared with full-year 2023, reaching their highest in the fourth quarter at nearly 1GW and almost doubling from the fourth quarter of 2023. While exports to France nearly halved on the year to 70MW, combined exports to Slovenia and Montenegro recorded a 61pc increase to 272MW. By Ilenia Reale Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Viewpoint: Trump, macro issues ahead for US renewables

02/01/25

Viewpoint: Trump, macro issues ahead for US renewables

Houston, 2 January (Argus) — A combination of substantial policy shifts under president-elect Donald Trump and macroeconomic issues puts the US renewable power sector on uncertain footing to begin 2025. Analysts expect the federal tax credits that have bolstered new renewable generation during its substantial growth over the past decade will survive in some fashion, although Trump campaigned on repealing the Inflation Reduction Act (IRA). He also has promised 60pc tariffs on goods imported from China, a major player in the solar and battery storage supply chains. The ultimate effects may vary by project type and what the new administration is able to accomplish. Chinese solar products already face 50pc tariffs , which could temper any effects on the industry from Trump's protectionist trade policies, said Tom Harper, a partner at consultant Baringa specializing in power and renewables. But the new administration could make it more difficult to claim IRA incentives and could roll back federal power plant emissions rules , creating an environment that could slow the adoption of renewables. Utilities may become more cautious in using renewables because of higher costs, while others, such as companies with sustainability goals, might be able to weather the change, according to Harper. "There might be some very price insensitive corporate [power purchase agreement] buyers out there who are looking at a $45/MWh solar [contract] and now it's going to be $50/MWh after the tariff, and they'll be fine," he said. In addition, the US renewables industry is still weathering headwinds from supply chain constraints, increased borrowing rates and inflation, which have hampered new projects. For example, the PJM Interconnection — which spans 13 mostly Mid-Atlantic states and the District of Columbia — had approved more than 37,000MW of generation at the end of third quarter 2024, with only 2,400MW of that partially in service. Developers have blamed the delays on financing challenges, long lead times for obtaining equipment and local opposition to projects. Global problems, local solutions Changes to state procurement strategies could help. Maryland state delegate Lorig Charkoudian (D) next year will propose new state-run solar, wind and hydropower solicitations that would first target projects that have already cleared PJM's reviews. Her approach would echo programs in New Jersey and Illinois, and ultimately reduce utilities' reliance on renewable energy certificates (REC) procured elsewhere. "The idea is to give a path for these projects, so presumably they can be built within a few years," Charkoudian said. Utilities would use the new procurements for the bulk of their RECs, covering remaining demand by buying legacy Maryland solar credits and other PJM RECs on the secondary market. But a quick fix for Maryland's broader renewable energy objectives is unlikely after utilities used the alternative compliance payment (ACP) for two-thirds of their 2023 REC requirements. The fee for each megawatt-hour by which utilities miss their compliance targets serves as a de facto ceiling on REC prices. Maryland's ACP is low compared to neighboring states, where the qualifying REC pool overlaps, meaning that credits eligible in the state can fetch a higher price elsewhere. While lawmakers could raise the ACP to mitigate those issues, those costs would ultimately fall on utility customers. "As best as I can tell, the options are raise the ACP or adjust how we do it," Charkoudian said. "We're really concerned about ratepayer impacts, and so I don't think there's a real appetite to raise the ACP." In other states, the policy landscape is less certain. Pennsylvania governor Josh Shapiro (D) has no clear path for his proposed hike to the state's alternative energy mandate, should he choose to revisit it, after Republicans retained their state Senate majority in November. New Jersey state senator Bob Smith (D) has been working for two years to enshrine in law governor Phil Murphy's (D) goal of 100pc clean electricity, but the proposal failed to escape committee in 2024 after dying in 2023 over opposition to its support for offshore wind . Is the answer blowing in the wind? Offshore wind is a slightly different matter. Trump has been critical of the industry and federal regulators control much of the project permitting in the US. Moreover, as a burgeoning sector with higher costs, it could be more sensitive to the loss of the investment tax credit (ITC). Based on current expenses, Baringa's analysis suggests that losing the ITC could increase project costs by "at least" $30/MWh and push offshore wind REC prices in some cases near $150/MWh. That would be a "difficult cost for states to swallow", according to Harper. "We've seen a few offshore wind developers already say, 'Hey, we're not going to spend a dime more until we know what's going on,'" Harper said. Despite the challenging landscape, Charkoudian expects Maryland will move forward in areas it can control, such as expanding the onshore transmission, that will make offshore wind viable, whether it's now or "eight years from now". By Patrick Zemanek Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Viewpoint: US utilities worry over railcar supply

02/01/25

Viewpoint: US utilities worry over railcar supply

Washington, 2 January (Argus) — 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. By Abby Caplan Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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