More than half of all coal plants are, or will soon be, shuttered. Collaboration and compromise by some are beginning to reveal ways to reclaim the sites for new purposes.
What is to become of the 57% of U.S. coal generation sites that now, or in the near future, no longer burn coal?
Some are being converted to burn gas — a move opposed by environmental groups who prefer renewable energy — while others are finding a variety of non-energy uses. What are the challenges for those sites? and what about the majority of sites that have no current conversion plan?
From 2008 to 2016, the U.S. saw nearly 35% of its coal generation capacity shut down, converted or scheduled for one or the other, according to the Union of Concerned Scientists (UCS).
The most common reuse of shuttered coal sites has been conversion to natural gas generation. But more than 95% of them remain unremediated and unrepurposed, UCS found. Site owners, leaders of the local communities and power sector stakeholders are starting to see a missed opportunity.
Two significant barriers block access to the opportunity, according to both utility and community activists. One is the knotty question of what to do with decades of accumulated toxic coal ash. The other is the thorny economics of a transitioning power sector.
Stakeholders say negotiating their way between these challenges is “complicated”. But collaboration and compromise by some pioneers on this power sector frontier is beginning to reveal ways to reclaim old ground for new purposes.
Fossil Fuel Conversions
Duke Energy has retired 5,424 MW of coal generation since 2011 and plans to retire an additional 2,006 MWs by 2024, spokesperson Kim Crawford emailed Utility Dive. Much of it will be converted to alternative fuels.
The only economically viable site conversions are those with “ready access to gas” that can be “relatively easily retrofitted with new gas burners,” Crawford wrote. Without these advantages, a new “more fuel efficient advanced gas turbine or combined cycle option” is a more cost-effective option.
Some existing boilers allow a "dual fuel" option, which is burning coal and alternative fuels like natural gas or biomass, Crawford reported. They are converted if “extensive analysis” forecasts lower fuel cost, improved efficiency, and reduced emissions and environmental risk, she wrote.
At most of the sites, the new natural gas facility is built and the coal plant is then "retired and demolished,” Crawford said. At other sites, “we have retired coal units without replacing generation.”
Duke’s extensive work on remediation of stored coal waste, in compliance with state and federal regulations, goes on “regardless of any planned plant modifications,” Crawford added.
The Omaha Public Power District (OPPD) has converted three of five coal units at its North Omaha facility to natural gas.
As with Duke, the available natural gas supply is key, Director of Corporate Planning & Analysis Brad Underwood emailed. The size and reliability of the existing coal units are weighed against the forecast “post fuel conversion” capacity factor of the converted units.
In addition, environmental impacts and cost savings are weighed against “the construction of a combustion turbine, combined cycle, or other solutions,” Underwood said. To date, “OPPD has not converted coal units to any other fuels.”
A challenge unique to conversions is how to decommission unneeded infrastructure, Underwood reported. Finding or building natural gas pipelines to supply a plant is a challenge common to both converted and greenfield units, he added.
The ash waste for the two remaining North Omaha units, now scheduled for conversion to natural gas, is still “marketed for beneficial use or landfilled on site,” Underwood said.
Remediation Before Repurposing
UCS found that of 1,256 coal-fired generating units (356.7 GW) operating in 2008, some 452 units (59.3 GW) had been shuttered by the end of 2016, 98 (13.4 GW) had been converted and 163 (51 GW) are scheduled for closure or conversion to another fuel.
Altogether, 39% of 2008’s MWs of coal generation are, or will soon be, eliminated.
UCS Midwest Policy Advocate J.C. Kibbey and Sierra Club Beyond Coal Campaign Organizer Ian Karra agreed the sites have one important thing in common.
“There will be a need to address and remediate the environmental damage those plants have done,” Kibbey said. Site owners, stakeholders, and local community leaders should work with policymakers “to put smart policies in place to facilitate redevelopment.”
Karra said Sierra Club’s campaign is moving beyond plant shutterings. “We're dealing with economic transition and how communities can replace lost tax revenues and retrain workers because so many plants have no plan for adaptive reuse.”
The barrier to redevelopment at many of the sites is coal ash, Karra added. There are at least 1,424 coal waste disposal sites with nearly 1,100 ash ponds, according to the Sierra Club.
Coal ash is not classified as hazardous by the EPA “but we know it contains toxic metals like mercury, arsenic and cadmium, Karra said. Cleanup has sometimes been done by the community, but more often the plant owner has held the site “and it's never remediated and redeveloped.”
Both Sierra Club and UCS oppose conversion to natural gas. “The economics of renewable energy have changed,” Karra said. “We can skip natural gas as a bridge fuel.”
Kibbey said UCS research showed the last decade’s very low natural gas prices have resulted in the threat of over-reliance on natural gas. “The new battleground is between replacing coal with natural gas and replacing it with renewable energy,” he said.
An example is the just-resolved debate between Southern California Edison and California regulators over the proposed 264 MW Puente natural gas plant, Kibbey said. It culminated with an agreement to test the cost-competitiveness of renewables and storage for the greenfield site through a solicitation.
Karra said federal and state-level funding programs address communities’ job and tax revenue losses from coal plant shutdowns. But assistance is limited for the expensive removal or capping of coal ash ponds.
“There are things being done with retired coal plants, but they are the exception and not the rule,” Karra said. “We have far more plants sitting there than being actively reused.”
The complicated economics
With less than 5% of shuttered coal plant sites cleaned up, it is difficult to generalize about remediation costs. That is especially true because costs vary by site size, complexity and regulatory obligations.
A Tennessee Valley Authority study found the cost of closure-in-place to be between $3.5 million for a 22-acre pond to $200 million for a 350-acre site, according to a 2017 Resources for the Future (RFF) report. “Excavation and removal of [coal combustion residuals] to landfills was estimated to cost between 270 and 2,200 percent more than closure-in-place,” RFF added.
A 13 MW solar project by the City of Orlando, Florida's municipal utility was one of the first in the U.S to be built on a coal waste landfill, according to Chris Castro, the director of sustainability for the Orlando Mayor’s Office.
“The coal ash landfill had been retired and capped for many years, so there was no need for coal ash removal,” Castro emailed Utility Dive. “The community solar farm is a ballasted system, meaning the racking systems are not penetrating the capped landfill.”
ENGIE North America’s 5.76 MW Mount Tom Solar Project was built at the site of the shuttered Mount Tom Power Station coal plant in Massachusetts.
A study on site redevelopment found a solar project could take advantage of existing infrastructure while minimizing environmental issues. But a $3 million to $8 million remediation of the solid waste and ash landfills was found to be necessary “prior to any reuse.”
ENGIE has taken on the remediation, spokesperson Carol Churchill emailed. She declined to comment on how it impacts the project’s economics.
E.ON VP John Badeusz said the Stony Creek Wind Farm in Pennsylvania was built in 2009 “largely on a reclaimed strip mine” despite the “many engineering and construction challenges.”
The site was fully remediated prior to development but E.ON faced “unique challenges with the ground and soil conditions,” Badeusz said. The "filled land" made turbine foundation work complicated in the absence of costly geotechnical subsurface soil exploration. Developing the project required “non-typical” and “more expensive” foundations and subsurface cabling.
While some site are being converted to use gas or renewables to produce energy, others are being converted to non-energy purposes.
Kibbey said financing the redevelopment of a Lansing, Michigan, site into insurance company AF Group’s headquarters took over a decade because of liability issues and costly remediation and infrastructure upgrades.
When the insurance company stepped up, a package of federal, state and local incentives worth $59 million became available to support the public-private partnership. “The cost-benefit analysis made sense for the city and the developer to take on the $182 million project,” Kibbey said. “It transformed the site from an eyesore to a jewel of a revitalized downtown."
There is no “cookie cutter" approach to remediation and repurposing but “substantial dialogue” between site owners and communities can identify the “right local solution,” Kibbey said.
Karra offered three varied examples of repurposing. In 2016, Georgia Power donated its retired Kraft coal plant to the Georgia Ports Authority. Its proximity to Savannah River ports and the Norfolk-Southern Railroad make it valuable. But remediation and redevelopment have not yet begun.
Google is converting the shuttered Tennessee Valley Authority Widow’s Creek coal plant into a data center that will be powered entirely by renewables. The project is in the early stages of development. The complicated question of who will pay for site remediation remains unresolved.
Georgia Public Utilities Commission's order for a 10 MW solar demonstration project to be built by Georgia Power on a shuttered coal plant site is the third example, Karra said. The site has not yet been chosen. The utility is doing ash pond remediation at 29 sites.
“We want to use regulatory options to drive as much clean energy development in coal communities as possible,” Karra said. “When that’s not possible, we want there to be resources for those communities to transition to another option.”
The costs of remediation, site repurposing, and, where necessary, supporting the local community through an economic transition must all be part of the discussion, he added.
Both Kibbey and Karra agreed it remains complicated and unsettled as to whether utilities should be able to rate base those costs. There are sites with significant infrastructure that could be leveraged for repurposing, Karra said. “But whether the cost burden for the remediation that must precede repurposing is on the utility or the community is still a question."
Kibbey and Karra also agreed there is a big untapped opportunity in the transmission and other infrastructure that once served coal plants.
In Massachusetts, Dynegy sold the shuttered Brayton Point power plant to Commercial Development Co. (CDC). CDC CEO Randall Jostes told Utility Dive his company intends to find a new user for the site.
The plant’s infrastructure, its access to the regional transmission system, and its potential as a deep water port could make it a hub for Massachusetts’ mandate-driven, ready-to-boom offshore wind industry, Jostes said.
In the Pacific Northwest (PNW), existing transmission between Montana’s 2,094 MW Colstrip Power Station and regional load centers could be pivotal to the site’s future, Renewable Northwest Senior Policy Manager Cameron Yourkowski told Utility Dive.
Puget Sound Energy (PSE) and Talen Energy co-own units one and two, which are now scheduled to be closed by 2022. PSE, Talen, Portland General Electric, Avista Corp., PacifiCorp and NorthWestern Energy co-own units 3 and 4, which is likely to be shuttered by 2035 or sooner.
Power from Colstrip is transmitted 250 miles via two 500-kV lines co-owned by the five utilities to a substation in Montana. From there, the Bonneville Power Administration transmission system sends it to the individual utilities’ grids.
“We want to make sure the transmission becomes available,” Yourkowski said. Its cost is already in rates and Montana’s high capacity factor wind could both replace retiring PNW generation and meet state mandates, he added. “The only way ratepayers do not benefit from their transmission investments is if the lines are not repurposed.”
PSE Director of Thermal Resources Ron Roberts told Utility Dive there are challenges in repurposing both the site and the transmission. With six coal facility owners and five transmission owners, “Colstrip is probably one of the most complicated things on the planet,” he said. The cost of decommissioning and remediation of just units one and two is estimated at $110 million.
“We haven’t gotten to alternative site uses and we will entertain all possibilities,” Roberts said. But Colstrip’s extremely remote location “limits alternative uses.”
The cost-competitiveness of solar or wind will be determined by developers’ bids into the utilities’ solicitations, Roberts said. “It depends on where the renewables are located and who is buying them. It’s complicated.”