What if President-elect Joe Biden’s plan to get to 100 percent carbon-free electricity by 2035 turns out to involve not radical disruption but a smooth transition?
A new paper in the journal Science shows that most of the country’s existing coal, natural gas and oil power plants would be past the end of their expected lives by 2035, leaving only a small share that would need to close early under the Biden policy.
Considering this, implementing the Biden plan “is probably easier than people expected,” said the author, Emily Grubert, an environmental engineering professor at Georgia Tech.
By showing when the country’s fossil fuel power plants are on track to go offline, the report helps to signal to state and local governments when to prepare to deal with job losses. Most of those job losses would happen regardless of climate policy.
“The overall takeaway is that we do have time to plan for this,” Grubert said.
She looked at every one of the 10,435 generating units at power plants that were operating in 2018 and estimated when each would close, based on the typical age of shutdown for other units that use the same technologies. Most large fossil fuel plants have multiple generating units. The plant reaches the end of its life when the last generating unit stops operating.
Grubert’s research is remarkable for its level of detail, allowing her to draw conclusions about fossil fuel power plants across the country in ways that have never been done in quite this way.
Some plants will close sooner than their projected retirement dates, and some will close later, but the report serves as a kind of actuarial table to get an idea of how long plants are expected to live.
This is different from an estimate of whether the plants will be profitable, or whether they might close because of economic factors. Indeed, some power plants in fully regulated jurisdictions are operating beyond their life expectancy and would struggle to compete on an open market, but can remain alive by passing costs on to ratepayers.
Grubert’s paper shows that in 2035, the large majority of fossil fuel plants will be past their life expectancy, leaving 15 percent that would need to shut down under a zero-carbon policy, despite having life remaining.
I need to explain that 15 percent, because it is not the number of generating units or the size of the remaining units. It represents “capacity-years,” which is weighted based on the size of the units and the number of years they are projected to have left. This is a useful measure because simply looking at the share of generating units would be skewed by the many small ones that communities use for emergency backup.
Based on Grubert’s estimates, every fossil fuel power plant would have reached its life expectancy by 2066, with a 3-megawatt plant in Rochester, New York, among the last to close.
One of the last large coal-fired power plants would be Prairie State Energy Campus in Illinois. The 1,766-megawatt plant went online in 2012 and would reach the end of its life expectancy in 2063.
Grubert devotes much of the paper to estimated job losses, and says that communities need to prepare. The report shows that fossil fuel plants operate in about 40 percent of U.S. counties and about 157,000 people work at the plants or in jobs related to extracting fuel for the plants.
She points to the collapse of the U.S. steel industry in the 1970s and 1980s as an example of the devastation that occurs when the government is not prepared to deal with the upheaval of economic change. Newer energy technologies will lead to new jobs, but not necessarily in the same places for the same people.
Legislation calling for 100 percent carbon-free electricity could also include, or be passed alongside, aid for communities that are losing fossil fuel plants.
Again, keep in mind that most of these plants are approaching their life expectancy and would be likely to close before 2035 regardless of policy, so climate legislation is an opportunity to have the double benefit of helping the environment and helping workers.
Grubert’s paper doesn’t speak to the other side of the equation, which is the need to build new plants to replace the generating capacity that will be closing. Utilities and many researchers are focusing on this problem, trying to figure out the right mix of new plants.
Some utilities are proposing to build new natural gas plants, which they say would provide reliable power during times when other sources, like wind and solar, are not meeting needs. Environmental groups mostly oppose new gas plants, arguing that the technology already exists for a clean grid through a combination of renewables, energy storage, and, depending on the environmental group, nuclear power.
Grubert told me that utilities and regulators should be wary of building new gas plants because the policy push for 100 percent carbon-free electricity is likely to only get stronger, which means there is a high risk that new plants would need to close early, leaving companies and ratepayers to pay for assets they they don’t fully utilize.
“The policies and the general climate needs that we’re seeing suggest that anything new would be stranded,” she said.
When she says “stranded,” she’s referring to the idea of stranded assets, which is when a company needs to write off an asset because it’s no longer usable or its value has dropped.
And, as her research shows, the number of stranded assets under the Biden proposal would be relatively small if companies could resist the urge to build more fossil fuel plants.
I wrote in October about how Ameren, Illinois’ second-largest utility, was reducing compensation for rooftop solar customers, and how a debate was raging about whether Ameren had used a faulty calculation to justify its sudden actions.
Regulators have now spoken and told Ameren to change course.
The Illinois Commerce Commission issued a ruling last week. The commission mostly agreed with environmental advocates that Ameren should have used different numbers, and the ruling requires the utility to go back to full net metering for customers that installed rooftop solar since October. This means the company must pay the full retail rate for electricity that solar owners send to the grid.
Illinois law says that once rooftop solar reaches 5 percent of the peak electricity demand in Ameren territory, it triggers the end of full-retail net metering.
Ameren, whose service territory includes most of the state other than the Chicago area, said in October that it was going to begin using a new rate, which was much lower than the existing one, because the 5 percent threshold had been reached. The company said it was following guidelines that had been in place for years and that the shift should not have been a surprise.
Environmental groups said that Ameren’s calculation was incorrect, and that the 5 percent level was not likely to be reached until at least 2022, unless the legislature passes new solar incentives, which is a possibility. I’m going to spare you a deep dive on the differences between the calculation methods.
The Commerce Commission ruled that the underlying law was not clear about which calculation was correct, but that the intent of legislators who crafted the law was in line with what the environmental groups were arguing.
The upshot is that rooftop solar owners will get the full retail rate, which is a small but important part of the economics that make solar affordable in a state where policymakers have said they want to increase the use of solar power. Companies that sell solar systems say that uncertainty about rates is bad for business, and they have been dealing with months of uncertainty.
Will Kenworthy, Midwest regulatory director for Vote Solar, told me that the ruling helps to resolve what has been a lamentable episode. It also allows for time for regulators to work on a separate case in which the parties are figuring out what compensation level should be the successor to full net metering. The case may be complete by the time Ameren reaches the now clarified 5 percent threshold, giving solar customers some certainty about the income they can expect from their solar panels.
Ameren said it is reviewing the ruling and has not yet decided whether to appeal. The company didn’t exactly say it disagrees with the ruling, but came pretty close.
“The regulatory process is just that—a process,” the company said in a statement. “It continues to evolve and change and there are times when we agree with an outcome and times we don’t—but the underlying policies are important and the debate that surrounds those policies is healthy and will continue.”
A planned California project would be the largest virtual power plant in the world.
Sidewalk Infrastructure Partners, which is affiliated with Google’s parent company, Alphabet, Inc., said this week that it is working with OhmConnect, a company that helps manage home energy use and provides services to the grid.
The project would use batteries at homes and businesses to collectively act like a 550-megawatt power plant, the companies say. This virtual power plant is larger than any that I know of, and the developers are calling it the largest in the world.
Regular readers will know I get excited about virtual power plants. They use networks of batteries that can provide backup power for homes and businesses, and also send electricity out to the grid at times of high demand.
The backup power is essential in California, where utilities have forced power outages at times of high wildfire risks. And the ability to serve the grid has the potential to change how we think of power plants, reducing the need to build big new plants in favor of decentralized networks.
In August, I wrote about projects in the Bay Area that would have up to 20 megawatts of capacity. Until now, projects that involve 1,000 or a few thousand customers were significant.
The newly announced project, called Resi-Station, would start next year, with the 150,000 customers that are already working with OhmConnect. This would be just the beginning of something much larger, with a goal of being fully built by 2023, an OhmConnect spokesman told me.
Jonathan Winer, co-CEO of Sidewalk Infrastructure Partners, said in a statement that the new plant is part of “rethinking the structure of modern power grids, allowing them to function more like a symphony than a solo—a sequence of energy-taking and energy-giving systems that communicate and cooperate with one another to deliver electricity safely, cheaply and efficiently.”
His company is committing $100 million, which includes $80 million for the project and $20 million to buy a stake in OhmConnect.
The news release announcing the project included comments from California state officials and Carol Browner, the former EPA administrator, calling attention to the project’s potential to be a major step in decentralizing the energy grid and making the grid cleaner and more reliable.
I’m eager to see how this unfolds. If this project happens at anything close to the scale being described, it would be a landmark.
Inside Clean Energy is ICN’s weekly bulletin of news and analysis about the energy transition. Send news tips and questions to [email protected].
