While public power utilities are primarily accountable to their communities and don’t have the same regulatory requirements in terms of setting rates, they are still subject to federal environmental regulations. Various environmental rules and federal agency actions — whether on climate, air, water, solid waste disposal, or permitting — can affect public power operations.
Two public power utilities weighed in on how environmental regulations factor into their power supply planning process and what other considerations affect their long-term decisions.
Seeking Clarity
As the Sikeston Board of Municipal Utilities in Missouri began reviewing its power supply options for the future, specifically how to transition the Sikeston Power Station, a 235-megawatt coal plant, it first started looking at all possible options, and then whittled down to the most practical and economical avenues.
Sikeston’s Power Supply Planning study, or PSP, kicked off in June 2023 and has produced a series of reports that detail the market, regulatory, and technical challenges of the various options available. A report of the PSP in January 2024 noted that closure of the coal plant is “inevitable,” and while the plant is currently the most economical option for the community, regulations and market conditions are likely to increase its operating costs.
Environmental regulations in SBMU’s considerations include the Mercury and Air Toxics Standard, Effluent Limitations Guidelines, and coal ash rules.
Rick Landers, general manager at SBMU, said the utility decided to dig further into four shortlisted options: moving toward all renewables, developing gas peakers, building combined cycle units, or deploying a combination of combined cycle and gas peaking units. While the utility was looking at data regarding these options in summer 2024, the Environmental Protection Agency announced its power sector greenhouse gas rules, and the Southwest Power Pool, the market in which Sikeston participates, announced an increase to its winter reserve margin.
Landers said SBMU re-ran the data on the shortlist options to reflect what effects it could expect with these changes. He said while the combined cycle units continued to look to be the most economical option, there was still not clarity on the regulations.
Landers noted how moving ahead with the combined cycle gas unit wouldn’t bring as much pressure from the suite of regulations, including the Good Neighbor Plan for the National Ambient Air Quality Standards, MATS, and ozone rules, “but what does become pressing is if carbon capture and hydrogen co-firing are the solutions. We can put a carbon capture system on our unit, but we can't do anything with the carbon captured. There's no pipeline to inject [the CO2] into, and we don't have a geology structure to inject it into the ground. We can say we're going to hydrogen co-fire. But where does the hydrogen come from?”
“Anybody that’s dealt with regulations knows they add uncertainty,” said Landers. “There’s got to be some clarity. Our timeline is to start taking actions in 2025.”
As for the all-renewables option, Landers said that SBMU would have to buy 80 MW of capacity from the market, which would be a high-risk option. He expressed concern on whether the capacity would even be available for purchase in a competitive market or if the transmission would be sufficient in that scenario.
Weighing Decisions
Derek Zeisler, manager of the Hastings Utilities Department in Nebraska, described the utility as “very dependent” on traditional fuels. The department operates two coal plants, including one in partnership with other public power entities, three natural gas units, two phases of a community solar farm, and has a small wind turbine in partnership with a local college. With some of those assets aging and the way regulations are currently written, he said the utility has some big decisions to make.
Hastings has been looking at whether it needs to refuel the coal units or put other measures in place to keep up with where regulations might go. One of its coal facilities was built in the early 1980s, and Zeisler said the unit has been well-maintained and has no reliability concerns. Another unit was added in 2011, with the intent of at least a 30-year life. However, regulatory changes have since called into question what the best choice for the community will be in the long-term.
“When a community makes an investment the size of that, you want to make sure you’re getting the most out of it. We love the idea of trying to transition out of these units in the most economical way possible while still being good stewards of the environment with the regulations in place,” said Zeisler.
That includes trying to make sense of changes in various emissions standards, as well as the power sector greenhouse gas rule requiring carbon capture, as in Sikeston. Zeisler also raised concerns about the nascent state of carbon capture technology, and its current limitations.
“Carbon capture has a huge potential parasitic load to your facility, so you have to come up with where you’re going to get the capacity that you lost from going with a process like that,” said Zeisler.
An added consideration is how any capacity could fare in the SPP market. Zeisler explained that SPP’s capacity market focuses on firm capacity, which pushes participants to traditional baseload resources. While he said some participants have begun to explore hydrogen, “natural gas is just about the only option, and there’s a limited supply of what can be built there.”
Zeisler also pointed to changes in the SPP market since the winter storm in 2021, specifically how much useful life Hastings can continue to get from steam gas units originally built in the 1950s and 60s. “For years, we would run a test just to prove they could run and be available. This year, those units have been called up 20 times combined. We’re trying to figure out how these units play in the current market. If we can get a better understanding of where they are headed, it can help us make better decisions on what kind type of units we need for our customers moving forward.”
“When there is a lot of unknown in generation, you invest in the known,” said Zeisler. That’s why he said Hastings has invested in developing and updating its generation assets over the past few years and is “hoping to hold onto the units we have for a little while.”
“Even if [regulations] get loosened, the reality is that it is only a matter of time due to the age of our facilities,” said Zeisler. “Being a smaller utility, one of the struggles is always how do we keep up with regulations while trying to keep our rates low and competitive and have the least amount of impact on our customers.”
Looking Ahead
Landers noted that SBMU hopes that some regulations currently on hold will allow for state implementation plans, as those would negate the need to go through the lengthier federal process.
“If our state plan is accepted, that’s about as good as we’re going to get,” said Landers.
Outside of regulatory requirements, significant challenges to accurately determining costs for different sources of generation include the interconnection wait times and supply chain constraints leading to increased costs for materials.
“The construction time is one thing, the amount of time it takes to get through the queue is another,” said Zeisler. “It’s never an issue with a regulation as much as the timing and the ability to get there — where is the technology at, what are the lead times for materials.”
As public power utilities, there is still a formal local approval process for any actions that expect to have long-term effects on the community served.
“Before we make the next move, we need to know exactly what has the potential to last the next 30, 40, 50 years for our city,” said Zeisler. “It takes a lot of time to plan. With a municipality, we work off of our city budget, which means that we have to get approved a few months in advance of the year starting, and that budget is set.”
“If we try to pitch to city council that these are things we need to do to be prepared, we want to feel confident that the rule is something that is stable and don’t want to be sitting with something after two years that we don’t need or isn’t exactly what we needed,” he added. “When limits change for some of our units, you are making an investment at that limit, and if that limit changes while you’re making that investment, maybe the path you chose to go isn’t enough to get you to the next step. Knowing what the ultimate goal is, so we are being efficient with our customers’ funds is our biggest concern. A mistake or miscalculation can end up having a pretty big impact on a community of our size.”
Zeisler also noted how delaying decisions can lead to higher costs, especially for smaller communities that might not get as many bids for work and don’t have the resources internally to allocate to major projects. “We are trying to make sure we are prepared for whatever moves we have to make and have the time to bid them properly. [It’s] always a challenge in a more rural area to get companies to come out here and build something. We’ve got some great contractors, but some of these projects are bigger than what they have historically dealt with.”
A Tall Task
“Anytime there’s a regulation, you trust that there is good science and understanding behind why it is needed,” said Zeisler. “Advocates do a lot of work for us in making sure the proper people are educated. At the end of the day, you evaluate several different paths and hope that as regulations and markets change, one of those paths will become clear for what our future needs to be.”
Landers explained how decisions can be difficult as utilities weigh priorities within the local community, the regional entity that oversees the grid, and then federal oversight. “Let’s say the local utility is focused on low cost, regional is focused on reliability, and the federal wants you to emit the least amount of carbon possible. If I was to say that each of those was the top priority, how does the local utility make a decision that matches all those priorities? That's the conundrum that local utilities are in.”
“Public power is an amazing thing, and in Nebraska we are 100% public power, so we have a lot of support. We have had a lot of open and honest discussions about how, as a state, we’re going to work hard to get where we need to be,” said Zeisler. “We have a tall task ahead of us, one that I fully believe we are more than capable of obtaining. But if pushed incorrectly, it could lead to some inefficiencies that aren’t necessary and cause some hardships that we would prefer to avoid for our customers.”
