CHICAGO — Local communities in eight states with a stake in the controversial and mostly bond-financed Prairie State Energy coal project in Illinois could face fiscal stress due to the significantly higher than projected rates they now face, along with future financial risks, a new report warns.
Customers in a total of 217 municipalities and 17 electric membership cooperatives in Illinois, Indiana, Kentucky, Michigan, Missouri, Ohio, Virginia and West Virginia will rely in part on the coal-fired plant for power.
The project — being constructed by Bechtel Power Corp. — was first estimated to cost $1.8 billion when initial owner Peabody Energy approached local publicly owned utilities about taking an ownership stake. The price tag then rose to $3 billion and the utilities and project managers in 2010 negotiated a fixed cost of $4 billion. Current costs for the project are estimated at nearly $5 billion, according to published reports.
Most of the nine power agencies participating in the project collectively borrowed about $3 billion, including Build America Bonds, to purchase an ownership stake in the plant located in Washington County, Ill. The Prairie State campus includes two pulverized-supercritical generating units with a combined 1,582-megawatt capacity and an adjacent mine. One unit came online in June, according to investor disclosure documents.
In a report released Wednesday, the Institute for Energy Economics and Financial Analysis, which promotes renewable energy sources, projects that more than 2.5 million rate payers in eight states will pay rates 40% to 100% higher than initially believed. That’s due to the additional borrowing and operating costs.
While the utilities previously disclosed higher megawatt-per-hour costs due to the cost overruns, the IEEFA outlines the difficulty in assessing what the final tally and impact for local communities will be.
“Elected officials, ratepayers, investors and market regulators should ask this question — did Peabody Energy disclose everything it could have in terms of the risks, the likely costs, and what would happen to the communities and co-ops when the coal company offloaded more than nine tenths of its exposure in the project?” said Tom Sanzillo, finance director at the IEEFA and a co-author of the report, titled “The Prairie State Coal Plant: The Reality vs. the Promise.”
The report charges that the project had promised affordable, low-cost electricity for 30 to 50 years. In addition, it was asserted that an ownership stake would allow for controlled costs, and that local municipalities could sell their surplus electricity on the open market at a profit.
Those perks all have failed to come to fruition, the report contends. Customers will pay rates far above initial estimates in 2007 of $41 per megawatt hour and in excess the current $40 market rate. One municipal utility, American Municipal Power Ohio, estimates a rate of $57.25. The study forecasts some communities will pay a total energy price of $80 per MWh in 2012 with higher than market rates expected for at least a decade.
A review of 13 communities in Ohio and Missouri shows annual losses per community through 2025 of between $3 million and $56 million, the IEEFA asserts based on its calculations of energy prices. It also warns that communities could face fiscal stress as they can’t recoup the prices paid for Prairie State energy on the open market for some time.
Peabody officials said they were still reviewing the report but called it an “advocacy piece in the guise of serious research.” The company challenges the report’s assertions based on assumptions involving competing fuels that were used “to make flawed estimates for a plant that will be in operation for decades.”
“Even so, the cost of coal for Prairie State is less than half the cost of natural gas at a time when gas is at historically low levels this year,” a spokeswoman said. “And solar and wind power, which this group advocates, are important but niche sources that have neither the scale nor cost profile to compete with baseload coal generation.”
A number of the public utilities and Bechtel did not return calls to comment.
The report also warns that fiscal risks remain despite the 2010 price fix agreement. It says the contract applies only to engineering, procurement and construction. “We anticipate that there are a number of pending financial risks and capital expenditures that are separate and apart from the terms of the contract and fall outside of the scope of Bechtel’s responsibilities. These include the potential need for additional mine resources, additional Ashfill resources and other anticipated capital expenditures to maintain the structural integrity of key infrastructure,” the IEEFA added.
The group charges that Peabody and AMP Ohio should have known the costs would rise as they cancelled other coal-related projects amid rising costs and greater federal regulatory scrutiny.
Supporters argue it will be one of the most advanced coal-fired facilities, with environmental controls that meet stricter pollution-control standards and that it still offers affordable rates and pricing certainty. In addition to higher-than-projected rates, detractors claim it will be a huge producer of greenhouse gases.
Most of the power agencies have either a take-and-pay contract with its members or a take-or-pay contract. The first and strongest requires members to make debt service payments regardless of the unit’s operation, mitigating the default risk of weaker and smaller participants. The second is also strong as participants must pay an amount typically tied to debt service regardless of whether service is delivered.
The participants with the largest stakes include AMP Ohio with a 23.26% ownership interest, Illinois Municipal Electric Agency, with a 15.17% interest, Indiana Municipal Power Agency, with a 12.64% interest, the Missouri Joint Municipal Electric Utility Commission, with a 12.33% interest, Northern Illinois Municipal Power, with a 7.6% interest, and Paducah Power Services, which has a 7.82% share.
Fitch Ratings in a 2010 report said it expected the ratings of JPAs with an ownership interest in the plant would withstand the burden of incurring the additional $1 billion for cost overruns, but further problems could have a negative impact.
In the event of further pricing strains, the Fitch report warned: “The credit impact will not be uniform across the owner systems, but will depend on each member’s share of PSEC as a percentage of its resource mix, as well as its ability to absorb or pass through cost increases.”
While the 2010 contract establishes a fixed price, given the size and complexity of the project, unforeseen problems could still arise, Fitch warned. Energy costs are fixed through 2042. The contract also provides a guaranteed completion date and provides compensation in the event operations are delayed, but does not address potential future operational challenges or the possibility of federal legislation imposing carbon emission taxes.
Energy costs based on the 2010 contract were expected to begin at $58 per megawatt hour, a $12 to $15 increase from 2007 projections. While the initial costs exceed market rates due to the recession’s impact on open market pricing and low natural gas prices, analysts believe that wholesale power prices will eventually jump.