An Illinois-backed 10-year reprieve that allows the municipal owners of two Illinois coal-fired energy plants to repay much of their debt before shutting down hasn’t won over some stakeholders.
State negotiators on a sweeping clean energy package that stalled late last month offered to delay the deadline to decommission the $5 billion Prairie State Energy Campus and the city of Springfield’s Dallman 4 plant to 2045 from 2035 conditioned on the capture of 90% of carbon emissions. Such technology doesn’t currently exist and whether it will by a 2034 deadline is unknown.
Some local Illinois municipalities were fine with the 2035 deadline as their contracts tied to Prairie State end by then and most of the more than $4 billion borrowed by municipal agenices across states is retired by 2045 but not all is as some extends several years out. Springfield’s debt is retired in 2040.
“I think there is an awful lot of room here for us to get what everybody wants which is keep the jobs and make sure you pay off the bonds that the various municipalities owe and get the kind of climate change action that we need,” Gov. J.B. Pritzker said last week after the latest pact stalled again.
Pritzker hopes to reach a deal between labor and environmentalists and bring lawmakers back in the next few weeks. “We are close,” he said.
But Pritzker has also warned that he won’t “sign a bill that does not match the gravity of this moment” by making progress on decarbonization that adheres to his 2050 target to reach 100% clean energy. Prairie State is the largest carbon dioxide emissions polluter in the state and in the top 10 nationally.
Some stakeholders say the compromise falls far short of protecting ratepayers from the double burden of paying off bonds supported by air-tight contracts while financing alternative energy sources and would hurt power grid reliability. Rating agencies say the early closure of Prairie State poses strains on the joint power agency ratings, but it will range as some have many members that can share the pain.
“That’s politically an empty promise that’s more part of a political game to try to present publicly that there’s been a compromise offered, but it’s not a compromise. Any reasonable person can look at it and see that the date is still 2035” because of the carbon capture conditions, said Gary Holm, president of the Northern Illinois Municipal Power Agency which is one of the nine municipal power agencies with a bond-financed stake in Prairie State Energy Campus, or PGEC.
“We still continue to say let us stay open until the bonds are paid,” Holm said. “The owners are going to have to continue to make bond payments while also purchasing replacement energy and capacity.”
NIMPA has been ramping up the use of clean energy sources like wind and solar, but more transition time is needed. NIMPA has $425 million of Prairie State bonds outstanding with a final retirement date of December 2041.
The power sales agreements leave municipal participants – that includes Batavia, Geneva and Rochelle – on the hook whether or not the plant operates. “We have to continue paying our bonds, that’s black and white,” said Holm, who also holds the position of director of public works for Batavia.
Springfield’s city-owned City Water, Light & Power utility which operates the Dallman 4 plant owes $36.6 million annually for a total of $366 million in payments with the final one due in March 2040. The city is working with the University of Illinois on a carbon capture project funded by the Department of Energy but whether it can achieve the 90% mandate by 2034 is unknown.
The project is underway with material purchases in the works and testing expected between 2023 and 2026, according to CWLP spokeswoman Amber Sabin. “What we’ve asked for” in the legislation is a 2040 or 2045 deadline without conditions, Sabin said, declining to comment directly on the latest version of the package.
Retiring Prairie State early would mark the latest headache for some of the nine public utilities in Illinois, Indiana, Kentucky, Missouri, and Ohio that issued $4.5 billion of debt to finance their ownership in project.
The sweeping energy legislation that provides nearly $700 million in subsidies over five years for Exelon Corp. to keep three nuclear power plants open appeared headed to a vote before the May 31 spring session was slated to end.
Originally Pritzker was prepared to back environmental activists’ preferred 2030 closure deadline for coal and 2045 for natural gas-powered plants, but moved it back to 2035 on coal at the request of legislators and labor activists.
Labor and backers of the Prairie State and Springfield plant then mounted an opposition campaign and passage of the package stalled.
Lawmakers returned last week with a compromise backed by Pritzker that offered the 2045 deadline with the 2034 carbon capture mandate in place for Dallman 4 and Prairie State. That’s according to prepared comments from Deputy Gov. Christian Mitchell who had expected to deliver the testimony before a Senate committee last week. The committee cited the ongoing logjam and so did not take testimony.
“We’ve come a long way. We have moved substantially. The other side has not moved much,” Mitchell’s testimony read.
The governor’s team also clarified that declining caps on natural gas would be in the aggregate and would both allow the potential buildingof new plants and then advantage them to stay open the longest, according to Mitchell’s testimony.
Legislative negotiators and Senate President Don Harmon, D-Chicago, suggested it was those emission targets on natural gas-fired electric generation plants — that potentially could force some plants to close ahead of the 2045 gas deadline — that scuttled the revised package. The state also received warnings from the developers of one natural gas plant in the works that those phased in targets could kill the project.
The compromise legislation also established a Prairie State Transition Task Force to investigate carbon capture and sequestration and debt financing options for Prairie State and affected municipalities. It also would designate the Illinois Finance Authority as the climate bank and allows the authority to aid clean energy efforts by providing financial products and programs to finance and develop and implement clean energy.
The 2045 deadline is an improvement for Prairie State owners but it’s a risk. “I think it’s definitely more positive but whether carbon capture will be commercially available is the question mark,” said Jennifer Chang, public power sector lead at Moody’s Investors Service.
Moody’s rates six of the nine owners. The impact of an early closure will vary depending on the individual owners’ level of debt outstanding, the number of participants that can share in the cost, and strategies for dealing with the financial burden of finding new energy sources but the early closure generally “is not a credit positive,” Chang said.
“It would be a credit negative” as “there’s going to be financial burden” to both repaying the debt and finding new capacity but it will vary, said Dennis Pidherny, head of the municipal utilities group at Fitch Ratings which rates seven of the nine owners. “How it weighs on the credit quality of the underlying municipalities and how they respond — that’s where the rubber is going to meet the road.”
The obligation is air tight for local municipalities who are participants in the joint power agencies or cooperatives and any challenges face a tough legal road to get out from under that obligation, said Pidherny.
Moving the date back to 2045 improves prospects as it allows more debt to be retired and more planning time to adjust operations, but it’s not a panacea because of the carbon capture requirements. “The conditionality of the extension makes it — at this is juncture – unrealistic,” Pidherny said.
Peabody Energy Inc. initially sponsored the project in Washington County promoting it as an affordable source of energy with an adjacent mine and a cleaner one given its state-of-the-art technology at the time. Bechtel Power Corp. built it. It initially carried a $2 billion price tag that rose to a $4 billion fixed cost under the 2010 contract with utilities, but cost overruns drove the price tag up to $5 billion.
Higher-than-projected power costs fueled the ire of environmental groups who had long have warned that even with more advanced controls the plant would still be a major national contributor to greenhouse gas emissions that are warming the planet.
The plant became fully operational in 2012 after some delays. The campus includes a two-unit 1,629 megawatt pulverized coal, supercritical coal-fired generating facility at a site with an adjacent coal mine. It initially experienced outages and capacity reductions that were a drag on its operating performance.
The rising costs pushed on to customers triggered lawsuits from local participants, calls for state attorneys general investigations, and subpoenas from the Securities and Exchange Commission.
The SEC launched its probe in 2013 with the disclosure that Peabody and Ohio-based American Municipal Power Inc. had received subpoenas related to the development of the project. It was resolved without action in 2017.
Ratepayers in the far west Chicago suburb of Batavia filed a lawsuit accusing project planners of misleading their municipality on the benefits, but it was dismissed. Rating agencies said initial megawatt-per-hour costs were higher than expected but long-term prospects as the plant’s operations moved up to full speed are beneficial.
Majority owners include AMP Ohio, the Illinois Municipal Electric Agency, the Indiana Municipal Power Agency, the Missouri Joint Municipal Electric Utility Commission, the Kentucky Municipal Power Agency and the Northern Illinois Municipal Power Agency.
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June 22, 2021 at 01:07PM