Energize Weekly, May 23, 2018
An Xcel Energy proposal to close two Colorado coal-fired power plants as part of a plan to move to 55 percent renewable power by 2026 has drawn wide support, but how the closure is to be paid for has become a bone of contention.
The price tag for shutting the 660 megawatts (MW) at the Comanche 1 and 2 units, near the city of Pueblo, is about $193 million, in accelerated depreciation and decommissioning costs, according to Xcel.
Where that money comes from and even if the price is correct is being fought out in a docket before the Colorado Public Utilities Commission (PUC).
It is, however, more than simply a Colorado question as market pressure and clean energy policies are prompting more utilities to close coal-fired power plants.
Since 2009, 268 coal-fired units have been shut down, leaving 262 operating plants, according to the Sierra Club’s Beyond Coal campaign. Most of the closures came as plants became obsolete or uncompetitive in the market.
In 2018, another 12.5 gigawatts of coal-fired generation are expected to close, according to energy analyst Bloomberg New Energy Finance. That is equivalent to closing forty Comanche 1 units.
How unrealized amortization or stranded asset and the costs of dismantling units is captured is a growing question in the industry.
“Stranded assets are high on the list of problems, especially for regulated utilities,” said Zach Pierce, a spokesman for the Beyond Coal campaign. “This is a big challenge.”
In Xcel’s case, the question is complicated by the fact that the closures are tied to a comprehensive plan to shift to more renewable energy. The Colorado Energy Plan is a voluntary initiative on Xcel’s part, and one the utility says it will not pursue if it raises customer bills.
Under the plan, the two Comanche units would be retired about 10 years ahead of schedule, and Xcel would seek bids from developers for 1,000 MW of wind power, up to 700 MW of solar facilities and 700 MW of natural gas-fired generation or energy storage projects.
The plan, the company said, could lead to $2.5 billion in clean energy investments, producing 55 percent of its electricity from renewable resources, and cutting the utility’s carbon emissions 60 percent below 2005 levels by 2026.
Xcel has already issued a request for renewable energy projects and received 430 proposals with the median price for 96 wind projects of $18 a megawatt-hour (MWh) and 152 solar photovoltaic projects with a median of $29.50 a MWh.
By way of comparison, Xcel’s estimate for the all-in costs of operating the two Comanche units is about $31 a MWh. Xcel estimates that the plan could save customers $223 million.
The proposal drew broad support from labor groups, big industrial customers, consumer advocates, environmentalists, the solar energy industry and independent power producers who sell electricity to Xcel. Fourteen of these groups and the PUC staff signed an agreement backing the plan that was submitted to the commission.
The financing for the retirement of the Comanche units was split into a separate commission docket, where there has been more discord, even from those who signed the initial agreement.
Xcel has proposed creating “regulatory asset” as an accounting entity for the costs of the Comanche closures and using a General Rate Schedule Adjustment (GRSA), a sort of interim rate attached to the bill for specific projects, between 2022 and 2028. Xcel has multiple GRSAs proposed in its pending rate case.
“It is a special case in that the accelerated depreciation will be collected in a separate GRSA, otherwise this would have been collected through base rates,” said Scott Brockett, Xcel’s director of regulatory administration. “However, this is similar to the accounting of other units that have been retired early for public policy objectives as regulatory assets.”
To hold customers harmless, Xcel proposes diverting half of the 2 percent charge each customer pays on the monthly bill for solar energy projects, the Renewable Energy Standard Adjustment (RESA), to pay off and decommission the Comanche plants.
The Colorado Solar Energy Industries Association (COSEIA) supported the idea. “We don’t like the idea of reducing the RESA, but we are willing to let it go forward to close coal plants,” said Rebecca Cantwell, the association’s executive director.
Still, in the Comanche docket, the association and others took issue with how Xcel planned to use the RESA.
“This approach is needlessly complex,” Kevin Lucas, director of rate design for the Solar Energy Industries Association, said in PUC testimony on behalf of COSEIA.
Leslie Glustrom, who as a private citizen has intervened in more than 20 Xcel dockets including the Comanche case, said, “Their goal is to not have ratepayers’ bills change, but they are burying the costs so they can’t be seen.”
“There are lot of inscrutable items on the bill, and the GRSA is the most inscrutable,” Glustrom said.
Energy Outreach Colorado (EOC), which helps low-income households with their energy bills, is also against the approach. “We are opposed to GRSA because that goes into fixed costs, and one of our goals is to keep fixed costs down,” said Andrew Bennett, EOC’s director of advocacy. “Before you flip on a light switch for electricity, your bill would be higher.”
Both Lucas and Glustrom called for separate charge on the bill for the cost of closing the coal-fired plants. Xcel has similar separate charges, or riders, for items such as transmission improvements.
“A regulatory asset-GRSA approach is not more complicated than a rider for accelerated depreciation, both require similar information and justification,” Brockett said. “The company plans to evaluate this concern, however, for its rebuttal filing.”
The Colorado Office of Consumer Counsel (OCC), which also had signed on to the original agreement, has also challenged Xcel’s use of a regulatory asset and asking for a 7.5 percent return on that asset.
Regulatory assets are often used to gather the costs for new projects, “steel in the ground,” which require a utility to raise and spend capital, Cory Skluzak, an OCC analyst, said in testimony. In such a case, a return to reflect the weighted average cost of capital (WACC) is appropriate.
In the Comanche case, the asset for the most part is collecting the accelerated depreciation, and there are no capital costs. The OCC is calling for the PUC to not give any return. “This was not part of the agreement,” Cindy Schonhaut, director of the OCC, said.
Xcel’s Brockett said the company is seeking a return at WACC for “prudently incurred costs associated with Comanche 1 and 2” and that since under the plan the two units are being removed from rate base early, the proposal is a “compromise.”
One of the concerns among some of the intervenors in the Comanche case involves setting precedents and figuring out what happens to the $1.9 billion in other coal-fired assets Xcel has in Colorado, which at some point may also have to be retired.
“We can’t use the RESA for the eight other coal plants in the state,” said Sierra Club’s Pierce. The Sierra Club also intervened in the Comanche docket. “The commission needs to be thinking much bigger on how we deal with the remaining fossil resources in the state.”
Around the country, other utilities have found a variety of ways to deal with the expense of coal-fired plant closures. Puget Sound Energy applied federal wind production tax credits, which it had not been able to monetize because of operating losses, to help pay for closing the coal plant in Colstrip, Mont.
Tucson Electric Power (TEP) agreed to accelerate depreciation of its San Juan Unit 1 to 2022, five years ahead of schedule, by using funds from distribution reserves to offset the earlier depreciation and cushion any rate impact.
“We are going to have to find inventive ways to deal with this issue,” Pierce said.
