Decline in Current Production Fly Ash Steadies as Plant Retirements Slow

There is little question that U.S. coal-fueled electricity generation—far and away the biggest current source of fly ash—is decreasing and will continue to do so in the coming years. Less certain is the pace at which coal-fueled generators will be retired and thus the impact on supplies of current-production fly ash—particularly for projections beyond the short-to-medium term.

According to the Energy Information Administration (EIA), approximately 28 percent of U.S. coal-fueled electric generation capacity (88.7 GW) has been retired since the coal fleet reached its peak in 2011. Of that total, 48 GW of capacity was retired between 2016 and 2020 alone—a pace that has since slowed, with just 2.7 GW of capacity slated for retirement by the end of 2021.

Why Coal Plant Retirement Timing Is Hard to Predict

Personal investors are surely familiar with the regulatory disclosure that “past performance is not necessarily indicative of future results.” Similarly, utility investments in (coal-fueled) power plants are impacted by a range of unpredictable market and non-market factors that can influence plant retirement decisions, including but not limited to:

• Plant operating costs
• The price and availability of competing fuels
• Government policies (federal regulations, state legislation)

Addressing each of these variables in turn:

Plant Operating Costs—According to EIA, 68 percent of U.S. coal fleet retirements since 2011 were plants fueled by bituminous coal—generally smaller, older units than those fueled by subbituminous coal (the other coal rank primarily used in thermal units). In 2019, the delivered price of subbituminous coal was $1.86 per million British thermal units (MMBtu), compared with $2.26/MMBtu for bituminous coal. The lower delivered price for subbituminous coal (owing to more cost-effective mining practices) makes coal plants that use it more economically competitive than bituminous coal-fueled plants. As shown in Figure 1, these more efficient subbituminous plants now comprise a significantly larger proportion of the coal fleet.

Price and Availability of Competing Fuels—The Henry Hub natural gas spot price at this writing is $5.53/MMBtu, double its level of a year ago. In early October 2021, natural gas futures closed at their highest level since December 2008. Credit simple supply and demand: 2021’s unusually hot summer boosted air-conditioning use—and thus gas demand and prices—resulting in less gas being stored for winter. (In the UK, where soaring natural gas prices have been coupled with sagging wind generation, coal units scheduled for retirement have been activated to bolster electricity supply.) Whether or not a full-blown energy crisis may be headed for the U.S. this winter as some observers have suggested, the threat of one could influence utilities and/or policymakers to preserve more coal capacity than previously anticipated.

Government Policies—Enforcement of the Coal Combustion Residuals (CCR) rule has yet to fully play out. According to Firmographs LLC, there are landfills and surface impoundments at approximately 200 utility sites where plant closure dates have yet to be announced. EPA’s determination of how these sites will be treated in any given case could accelerate retirement of the relevant boiler. Further state legislative action, similar to California’s law mandating that all retail sales of electricity by 2045 in the state must derive from carbon-free sources, could likewise speed coal plant retirements.

Medium-Term Outlook for Coal Plant Retirements (2021-2025)

With the aforementioned qualifiers as background, Firmographs LLC has forecast coal consumption related to U.S. electricity generation, and subsequent fly ash production, for the years 2021-2025. Starting with EIA’s 2020 report data covering these same two areas, Firmographs:

• Examined the announced retirement dates of boilers through 2025;
• Assumed a constant capacity factor for coal units, based on 2020 data, going forward;
• Calculated the amount of fly ash generated by each boiler, assuming constancy of operation based on 2020 data;
• Forecast the coal consumption tonnage and fly ash production of the U.S. coal fleet for each year based on the above data inputs.

Forecasts for U.S. coal consumption and fly ash production are shown in Figures 2 and 3, respectively.

As would be expected, the trendlines for both thermal coal consumption and fly ash production are similar and show a modest decrease year over year during the forecast period. Thermal coal consumption decreases over the period from 433.1 million to 363.6 million short tons (a 16.1 percent decline), while fly ash production decreases from 32.26 million to 27.54 million short tons (a 14.6 percent decline).

The forecast horizon—2021-2025—was chosen due to the relative certainty of the conclusions that could be drawn: the longer the time horizon, the more that any of a number of variables (e.g., regulatory policy, legislation, deviations from historical averages in the price of competing fuels, etc.) can come into play that potentially impact the accuracy of the forecast. A June 2021 analysis published by the National Bureau of Economic Research found that the average time between the announcement of a plant’s retirement and its actual closing, over the past decade, was three years. Thus, the potential for a plant to be retired by 2025 that, as yet, has not announced plans to do so is also minimized.

National Production vs. Regional Availability

Beyond the question of total U.S. fly ash production over a given time period is the issue of where (and when) coal plant shutdowns will occur. The geographical breakdown of plant retirements can impact regional availability of fly ash, as its transportation over long distances can potentially add sufficiently to the delivered cost of the product that it is uneconomical for use by concrete and other manufacturers.

Table 1 lists planned coal plant retirements by NERC region (as reported to the EIA in 2019). The majority of announced retirements are in the Midwest and West, with the median planned retirements in the Midwest occurring sooner (2022) than those in the West (2025). Based solely on these announced retirements—64 percent (on a capacity basis) of which will occur by the end of 2025—NERC regions RFC (Midwest/Mid-Atlantic) and SERC (Southeast) will comprise approximately three-quarters of nationwide coal-generating capacity. The MRO (upper Midwest) will account for under 20 percent, while the NPCC (Northeast), TRE (Texas), and WECC (West) will collectively account for less than 5 percent of coal-generating capacity.

Table 1. Planned Coal Generator Retirements by NERC Region

Source: National Bureau of Economic Research

Further complicating the picture of the regional availability of fly ash are the announced plans by at least three coal plants to run only seasonally to improve the economics of their operations—and the potential for additional plants to do so going forward. Two such plants in Minnesota, totaling 1,193 megawatts (MW), have received regulatory approval to operate only during the higher-demand summer and winter months. A third plant in Arizona with 793 MW of capacity will operate only during the high-demand summer months, starting in 2023.

Longer-Term Outlook Through 2050

In EIA’s Annual Energy Outlook 2021—which includes a forecast of coal-fueled generating capacity retirements through 2050—the agency states, “Most of the coal-fired generating capacity retirements assumed in the [baseline] Reference case occur by 2025.” However, the Reference case includes legislation and regulation current as of September 2020, and so incorporated the EPA’s Affordable Clean Energy rule (viewed by some observers to have offered a modest regulatory reprieve to coal plants), which was subsequently vacated in the United States Court of Appeals for the District of Columbia Circuit in January 2021. Thus, EIA’s forecast may underestimate the pace of coal plant closures.

On the other hand, EIA notes in its 2021 Outlook, “Low natural gas prices in the early years of the projection period also contribute to the retirements of coal-fired and nuclear plants because both coal and nuclear generators are less profitable in these years, because natural gas generation generally sets power prices in wholesale electricity markets.” Nine months removed from the publication of EIA’s Outlook—released in February 2021—U.S. natural gas prices have, in fact, soared.

In any event, EIA’s “worst-case scenario” for the coal-fueled electricity generation sector—a high oil and gas supply environment through 2050—still forecasts a distinct flattening in the rate of decrease in coal-fueled electricity generation over the final 20 years of the forecast (2030-2050). During that period, coal-fueled electricity generation decreases from 90.8 GW to 73.3 GW—for a negative growth rate of just 1.06 percent annually.

By that time, it is likely that a variety of supplemental fly ash sources—harvested, blended, and/or imported—will have been developed sufficiently to make up for the deficit in fly ash from coal-fueled electricity generators.

John Simpson is editor of ASH at Work.