Viewpoint: US coal supply may tighten

Spanish Market: Coal, Electricity
31/12/24

More US coal production cuts may be on the horizon, setting up thermal coal supply to potentially be lower than demand starting in late 2025.

US coal producers have been scaling back mining operations since at least mid-2023 in response to lackluster demand. Market participants are continuing to contend with elevated power plant inventories following relatively mild winters and more competitive natural gas prices.

Some producers are signaling more production cuts are coming in the next few months. As a result, the US Energy Information Administration (EIA) recently forecast the country's coal output in 2025 would fall by 7.2pc from this year to 472.3mn short tons (428.5mn metric tonnes), the lowest level in agency data going back to 1949.

But US coal-fired generation and coal consumption is expected to grow modestly next year, to 643.7bn kWh and 409.4mn st, respectively, from 641.6bn kWh and 406mn st in 2024, because of greater electricity and industrial demand. Coal consumption for the electric power sector alone is expected to rise to 371.5mn st from an estimated 369.4mn st in 2024, EIA data show.

Generators are expected to draw from their existing coal inventories for the majority of the year to meet the slightly higher electricity demand, potentially bringing power plant stockpiles down to more normal levels. Coal producers also are expected to have less inventory at mines and loadout facilities as volumes that had been deferred to 2025 are delivered.

If the inventory withdrawals and expected slight increase in domestic consumption are coupled with higher export market prices and demand, "there could be an impetus for a slight ramp-up in domestic production, but currently, that prospect does not appear to be visibly on the horizon", EIA chief economist Jonathan Church said.

For example, Argus assessments for calendar year 2025 API 2 coal swaps averaged $112.85/t from 1-24 December, compared with $104.19/t for all of December last year.

The response from coal producers to any improvement in demand could be uneven, which could constrict competition and boost prices.

While larger producers with longwall mining equipment, primarily in northern Appalachia and the Illinois basin, can somewhat efficiently resume or increase production, other companies may struggle to ramp up operations.

Producers also may not have the financial support to increase coal output. A number of market participants expect smaller producers with higher-cost operations to be forced out of business as major banks continue to pull back on lending money to coal mining companies.

In the nearer term, recent or planned coal mine closures could further limit supply. Alliance Resource Partners said in November that it intends to retire its central Appalachian coal-producing MC Mining complex in Kentucky, and the company has already cut operations to two of its four production units. Earlier in 2024, American Consolidated Natural Resources closed its Pride Mine in western Kentucky and Hallador Energy idled two small Indiana mines in February.

Other producers have scaled back operations but kept mines open. Coal miners worked an average 45.5 hours/wk in October when not adjusted for seasonal factors, preliminary figures from the US Labor Department show. A year earlier, coal miners averaged 48.3 hours/wk.

Producers also have to contend with an uncertain outlook beyond 2025, including an expected shift in environmental policies under president-elect Donald Trump, how new data centers will affect electricity demand, and timelines for installing new generation and transmission upgrades.

Alliant Energy, Vistra Energy, Duke Energy and Louisville Gas & Electric and Kentucky Utilities are among utilities that recently announced plans to potentially delay retiring coal-fired generating units or plans to remodel coal units to co-fired natural gas and coal to try to meet load growth projections for the next few years. This could keep coal-fired generation and demand at least somewhat stable, but it may not provid long-term support.

"To have increased coal demand, you would have to have load growth outpacing new supply," said Robert Godby, associate professor in the economics department at the University of Wyoming. He and others expect new renewable generation and transmission projects to eventually accommodate projected electricity demand growth.

Increased load growth will be "at best just a reprieve from the ongoing downward trend in coal production and coal demand", Godby said.

As such, producers may continue to try to limit output in 2025, which could partially raise domestic prices from current levels that straddle the line of profitability for many coal mining companies. But the increases will likely be modest as alternative energy sources are expected to continue to suppress demand for coal generation.

By Anna Harmon

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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.

Viewpoint: Power demand could bolster RGGI allowances

31/12/24

Viewpoint: Power demand could bolster RGGI allowances

Houston, 31 December (Argus) — Regional Greenhouse Gas Initiative (RGGI) CO2 allowances in 2025 could get a boost from a projected increase in electricity demand, despite uncertainty over the RGGI states' ongoing program review. Allowance prices hit record highs this past year, particularly during the summer as high temperatures raised expectations for emissions, increasing compliance demand. The first three auctions of 2024 cleared at record levels, draining the cost containment reserve (CCR) — a mechanism where additional allowances are released to temper rising prices — during the March auction . Prices followed suit in the secondary market, reaching multiple all-time highs before peaking on 20 August, with Argus assessing December 2024 and prompt-month allowances at $27.82/short ton (st) and $27.31/st, respectively. The increases have been fueled by anticipated growth in electricity demand as states work to implement policies promoting electrification in the transportation, industrial and heating sectors. In New England alone, peak power demand is forecast to double from 27,000MW to 55,000MW by 2050, according to an Acadia Center report . But the biggest source of this demand — and the steady climb in RGGI allowance prices since late-2023 — is the rapid expansion of data centers, according to University of Virginia professor William Shobe, who studies emissions market and auction design. New CO2-emitting sources such as natural gas-fired plants must factor rising allowance prices into the future cost of electricity in the long-run, Shobe said. As prices rise, other cleaner sources of energy, such as offshore wind and small modular reactors, will become more competitive, he said. Review the review The member states of RGGI launched a review of the program in February 2021. As power demand creates a potential for a bullish RGGI market, the review remains a source of uncertainty for participants and volatility in the secondary market. The program review includes considerations for a more ambitious emissions cap plan beyond 2030. But it has faced a number of delays and was originally scheduled to wrap up last year . Member states have provided few updates on the status and timeline of the review, leaving participants and environmental groups alike on tenterhooks over how a finalized program review — and with it, an updated emissions cap plan — will affect the future supply of allowances. Participants "are always thinking about future scarcity", said Shobe. "The more information we can give them about the future path of scarcity (of allowances) now, the more efficient their own behavior can be." The latest updates were released in September. They included an emissions cap plan that combined two previously floated proposals where the allowance budget starts at about 70mn st, declining at a rate consistent with a zero-by-2035 goal from 2027-2033 and a lower rate consistent with a zero-by-2040 goal from 2033-2037. Member states are also considering adding a second CCR and eliminating the emissions containment reserve (ECR), a market mechanism designed to respond to falling prices by withholding allowances. The review is planned to end in early 2025. A draft rule with additional modeling was to be released in the fall, but there have been no updates regarding another change in timeline. RGGI has not responded to requests for comment. States in limbo The status of Virginia — which left RGGI in 2023 — and Pennsylvania as potential members is another point of uncertainty as those states' participation are under legal scrutiny in their respective courts. Virginia's Floyd County Circuit Court in November ruled that regulation enabling the state's exit from RGGI was unlawful since it was enacted without legislative approval. Governor Glen Youngkin's (R) administration intends to appeal to the Supreme Court of Virginia sometime in 2025, but has declined to specify when. While it is unlikely Virginia will rejoin RGGI in the interim, its participation would increase demand for allowances and put an "upward pressure on price", Shobe said. Much of this demand would be fueled by data center expansion, as northern Virginia is the largest market for data centers in the world, with 25pc of all reported data center operational capacity in the Americas and 13pc globally, according to a report by a state legislative commission. The Supreme Court of Pennsylvania is also reviewing a lower-court decision striking down CO2 trading regulation allowing the state to participate in RGGI. Governor Josh Shapiro (D) has reluctantly defended Pennsylvania's membership in the program as an issue of preserving executive authority, and Republican state lawmakers have been attempting to revive legislation that would cement the state's exit from RGGI. The state's high court could issue a decision sometime in 2025. But Governor Shapiro also proposed a state-specific power plant CO2 cap-and-trade program earlier this year — another development participants should keep an eye on. By Ida Balakrishna Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Viewpoint: US Supreme Court tees up more energy cases

31/12/24

Viewpoint: US Supreme Court tees up more energy cases

Washington, 31 December (Argus) — The US Supreme Court is on track for another term that could significantly affect the energy sector, with rulings anticipated in the new year that could narrow environmental reviews and challenge California's authority to set its own tailpipe standards. The Supreme Court earlier this month held arguments in Seven County Infrastructure Coalition v Eagle County, Colorado , a case in which the justices are being asked to decide whether federal rail regulators adequately studied the environmental effects of a proposed 88-mile railway that would transport 80,000 b/d of crude. A lower court last year found the review, prepared under the National Environmental Policy Act (NEPA), should have analyzed how building the project would affect drilling and refining. Business groups want the Supreme Court to issue an expansive ruling that would limit NEPA reviews only to "proximate" effects, such as how rail traffic could affect nearby wildlife, rather than reviewing distance effects. The court recently agreed to hear a separate case that could restrict California's unique authority under the Clean Air Act to issue its own greenhouse gas regulations for newly sold cars and pickup trucks that are more stringent than federal standards. Oil refiners and biofuel producers in that case, Diamond Alternative Energy v EPA , say they should have "standing" to advance a lawsuit challenging those standards — even though they could now show prevailing in the case would change fuel demand — based on the alleged "coercive and predictable effects of regulation on third parties". These two cases, likely to be decided by the end of June, follow on the heels of the court's blockbuster decision in June overturning the decades-old "Chevron deference", a foundation for administration law that had given federal agencies greater flexibility when writing regulations. Last term, the court also limited agency enforcement powers and halted a rule targeting cross-state air pollution sources. This term's cases are unlikely to have as far-reaching consequences for the energy sector as overturning Chevron. But industry officials hope the two pending cases will provide clarity on issues that have been problematic for developers, including the scope of federal environmental reviews and the ability of industry to win legal "standing" to bring lawsuits. Two other cases could have significant effects for the oil sector, if the court agrees to consider them at a conference set for 10 January. Utah has a pending complaint before the court designed to force the US to dispose of 18.5mn acres of "unappropriated" federal land in the state, including oil-producing acreage. Utah argues that indefinitely retaining the land — which covers about a third of Utah — is unconstitutional. In another pending case, Sunoco and other oil companies have asked for a ruling that could halt a series of lawsuits filed against them in state courts for alleged damages from greenhouse gas emissions. President-elect Donald Trump's re-election could create complications for cases pending before the Supreme Court, if the incoming administration adopts new legal positions. Trump plans to nominate John Sauer, who successfully represented Trump in his presidential immunity case, as his solicitor general before the Supreme Court. By Chris Knight Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Viewpoint: Bearish year ahead for NOx markets

30/12/24

Viewpoint: Bearish year ahead for NOx markets

Houston, 30 December (Argus) — The Cross-State Air Pollution Rule (CSAPR) NOx allowance markets will likely face a bearish year in 2025, as the incoming administration of president-elect Donald Trump creates uncertainty over the fate of the latest federal regulation to curb emissions. The US Supreme Court halted implementation of the US Environmental Protection Agency's (EPA) "good neighbor" plan in June with a nationwide stay. This left an already stunted regulation to cut NOx emissions, a precursor to harmful ground-level ozone, obsolete for the foreseeable future. EPA finalized a plan in March 2023 to help downwind states meet the 2015 national air quality standards by setting tighter ozone season NOx caps on power plants covered by CSPAR as well as new limits for industrial facilities in more than 20 upwind states. But by the time the justices issued the stay, the number of covered states had already shrunk by more than half because of lower-court orders pausing implementation in 12 states. Prices for seasonal NOx allowances have flatlined and the market has been illiquid over much of 2024 because of uncertainty over how numerous legal challenges against the good neighbor plan would play out. Argus has assessed Group 2 allowances at $775/short ton (st) and Group 3 allowances at a record low $1,250/st since January. This could change, albeit at a slow pace, because EPA finalized an interim rule in November to comply with the nationwide stay. Power plants that had been covered by the good neighbor plan are now under less-stringent NOx budgets tied to older air quality standards, and the 10 states that had been participating in the Group 3 market prior to the stay are now reshuffled into Group 2 and a separate 12-state "expanded" Group 2 market. All that remains is… uncertainty In the new year, the market will wait to see how the Trump administration will deal with the good neighbor plan and the associated legal challenges in the US Court of Appeals for the DC Circuit and the US Supreme Court. Because of the stay, there is no hurry for the new administration to address the legal woes, and it is unlikely the DC Circuit will soon rule on the legality of EPA's rejection of state ozone reduction plans. The Trump EPA, following precedent of prior administrations, will likely ask the court to pause litigation until it decides whether to continue defending the plan, according to Jeff Holmstead, assistant administrator at the agency under former president George W Bush. The agency will likely revoke the plan at some point and replace it with a rule that is more "modest" and would not significantly affect allowance prices, he said. The EPA under Trump could ultimately decide that upwind states do not significantly contribute to interstate pollution, reversing a determination that has underpinned the good neighbor plan. That could lead to downwind states asking the agency to address specific sources that contribute to their air quality problems, said Carrie Jenks, executive director of Harvard Law School's Environmental and Energy Law Program. The Supreme Court is also hearing a case to decide the proper court venue for Clean Air Act disputes, which involves the good neighbor plan. The Trump administration likely will agree with various states and industry groups that say EPA's rejections of individual state plans are not a "nationally applicable" action and must be litigated in the regional circuit courts, but the Supreme Court is likely to continue the venue case, Jenks said. Oral arguments will likely be held early next year. It is also unclear how Lee Zeldin, Trump's pick to lead EPA will affect the regulation. Zeldin is a moderate, given his history, and will likely "not want to impose significant new burdens on fossil fuel power plants", Holmstead said. Trump's plans to downsize the federal bureaucracy could also affect future rulemakings, according to Jenks. "Nobody really knows what's going to happen," she said. As a result, market activity is likely to remain limited in the coming months as participants await legal and regulatory clarity. In addition, markets are likely to be oversupplied now that power plants are under lighter NOx caps. Most states in the seasonal NOx markets were well below their limits for the 2024 ozone season, despite a 9.2pc increase in cumulative emissions in the expanded Group 2. EPA will also allow some power plants to convert vintage 2021-23 Group 3 allowances to Group 2 or expanded Group 2 allowances, adding to supply. With low demand and a potential oversupply, seasonal NOx allowances could see prices fall . By Ida Balakrishna Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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