Ten years ago, some people in the utility sector were talking about a “death spiral” caused by shrinking revenues and flat demand. Now, some of the same voices are wondering how utilities will serve the coming loads from electrification while simultaneously increasing carbon-free generation in their portfolios. Things change, and an integrated resource plan, or IRP, can help a utility manage those changes. Here is a look at how three utilities are mapping out their plans for a shifting supply mix.
A New Pace
What exactly is an integrated resource plan? “It’s a strategic plan to help us document our intended path for the next few years to meet our reliability, resiliency, financial and decarbonization goals,” said Jackie Pratt, general manager at Stowe Electric Department, a Vermont public power utility serving nearly 4,450 residential and commercial customers.
Despite the common goal of defining in detail how a utility will maintain a reliable and affordable power supply, IRPs can vary in terms of frequency and implementation implications. In some cases, their production and frequency are dictated by state or local regulations.
Stowe is required to produce an IRP for its state regulators every three years.
Sikeston, Missouri, doesn’t have such a requirement, and 2023 is the first year the community-owned utility, which serves about 9,000 customers, has gone through the rigors of integrated resource planning. Utility staff are doing this because the city’s 235-megawatt, coal-fired generation facility went into service in 1981. “It’s 42 years old now, and we expected it to last 50 years, so it’s time to start looking at what the future looks like,” explained Rick Landers, Sikeston’s general manager.
Staff members at Eugene Water and Electric Board in Oregon aren’t new to the IRP process, but they’ve accelerated the cadence. EWEB, which serves about 96,000 customers, last went through the IRP process 10 years ago, but, moving forward, the utility plans to develop an IRP every two years, said spokesman Aaron Orlowski.
“It’s a good practice, especially in today’s environment, where the energy landscape is shifting so quickly,” he said.
EWEB manages the IRP process in-house. Orlowski said the utility uses a consultant for some guidance, and the utility also runs Aurora energy forecasting software to evaluate resources in a 20-year planning horizon.
Sikeston is using a consulting firm that runs proprietary forecasting software. It’s a firm well-known for working on IRPs. “There are many vendors and engineering firms that will do these studies, but some have only done one in the last five years,” Landers noted. “You’re best off using someone more active in doing IRP work for utilities.”
Stowe is also getting a little consulting support, but the utility mostly follows a highly “prescriptive” format required by state regulators, according to Michael Lazorchak, regulatory compliance manager at Stowe. “We are expected to work with that framework, and that guidance comes from statutory language and PUC rules,” he said.
Charting What Matters
Reliability is the No. 1 target for each of these utilities. In Vermont, cybersecurity and finance are also now among the items that must be addressed in an IRP. In any locale, the list of things to consider is a long one. In Sikeston, Landers said the utility is examining plant economics, environmental regulations, fuel availability, future costs, as well as market impacts from the regional transmission operator. He added that rate impacts are an essential factor in sourcing generation for the utility because it serves an economically challenged territory. “We have to balance affordability with the environmental issues,” he said.
Landers said Sikeston is looking at more options for renewables, particularly since the elective payment tax credits, passed as part of the Inflation Reduction Act in 2022, have made ownership of these assets more economically viable for nonprofit utilities. “There have been tax incentives for carbon reduction for quite some time, but as a municipal utility, we’re not a taxable entity, so we couldn’t get a 20% to 30% credit for investing in or building a solar or wind facility,” he explained.
Finding ways to incorporate a higher portion of renewable energy into the generation mix is critical in Eugene, where the utility has a requirement to be 95% carbon-free by 2030 and carbon neutral by 2050. (The utility’s current mix is approximately 90% from carbon-free sources due to receiving a significant portion from hydropower.) In Vermont, utilities need to be 75% carbon-free only for larger resources, like hydropower, and utilities there have until 2032 to achieve this. By the same year, the state also requires 12% of the utility’s retail sales to come from beneficial electrification programs, like getting heat pumps into customer homes and offering electric vehicle charging rates. “The renewable energy standard plays an outsize role in our power supply planning,” Pratt said.
All three utilities have been very public with their IRP process. Press releases, town meetings, bill stuffers and social media are among the communication tools used. Stowe’s team also decided to conduct a customer survey. The results showed that 13.5% of respondents were planning to install heat pumps in their residences and 42% were planning to purchase an EV, meaning electrification could boost demand soon.
This affects much more than generation resources. “The biggest issue for me is prediction of energy use and how electrification impacts your system,” Pratt said. The adoption of EVs, heat pumps, rooftop solar and household battery energy storage prompts a host of questions, she added, and offered a few: “What should your rate structures look like? What should your system be engineered to handle? Where do you need to make upgrades?” She also noted that the IRP process will help the utility reexamine its rates.
Electrification is a huge driver for Eugene’s coming load growth, too, Orlowski said. Between the incentives for EV adoption built into the Inflation Reduction Act and Oregon’s ban on the sale of gas-powered vehicles beginning in 2035, utility management expects demand to grow by about 2% annually starting in 2030.
Along with that pressure, Eugene is affected by the Western Resource Adequacy Program. “It would require utilities to have a 15% buffer on their resources. If you think you need a certain amount of generation to meet peak demand, add 15%,” Orlowski explained.
Serving that increasing load with hydropower may be more difficult in the future, too. While hydropower is a go-to clean resource in the Pacific Northwest, there are increasingly operational mandates passed down by state regulators and legislators hoping to protect fisheries. “That means there is less flexibility in how those facilities are used to generate electricity,” Orlowski said.
Flexibility is crucial when you’re adding variable generation to the mix. “When you’re looking for a carbon-free solution, they haven’t yet come up with a replacement for a coal plant that is reliable and low-cost, too,” Landers said. “It may exist sometime in the future, but it doesn’t exist now.”
Eugene is seeing a similar issue. “There aren’t many low-carbon resources that generate electricity on demand,” Orlowski said. His utility team included small modular nuclear reactors, or SMRs, in its models because SMRs are expected to be commercially available in the early 2030s. Another resource the utility is considering is geothermal. “We did not include geothermal in this year’s IRP because the traditional style is site-specific, so there wasn’t good pricing data for it. There have been recent advances in the last couple of months for advanced geothermal, which promises to have more replicable abilities, so hopefully we can include pricing data for geothermal in our 2025 IRP.”
Because SMR units can be combined to add generating capacity, they vary in size from 12 MW to hundreds of megawatts. Even with the pricing data available today, though, SMRs appeared promising for Eugene, which is a winter-peaking utility with a prolonged period of overcast skies when the cold sets in, so solar doesn’t work well there.
In fact, the analytic model the utility used didn’t even recommend solar power, but it did recommend demand response. This is in part due to a promising response earlier this year to reduce demand. When Eugene tried putting out a call for customers to conserve this summer, its 96,000 customers shed between 10 and 15 MW.
Ultimately, IRPs bring a variety of power management and generation ideas to the table. “To run the system, you need a resource mix that has different attributes. What I hope for our customers to learn from the IRP process is what makes sense and what doesn’t,” Landers said.
“One of the things people need to understand is that when it comes to renewables, there is no postage-stamp solution that works nationwide,” he noted. “What works in Kansas may not be close to what works in Kentucky.”
Orlowski said much the same thing, noting that renewables provide low-cost energy, storage can shift consumption patterns, and on-demand resources have an important place on the grid, too. “We’re going to need that whole mix, and that’s something we need to tell our customers because there is no easy solution to achieve this energy transformation,” he noted.
In addition to a lack of easy answers, there aren’t likely to be exact answers, either.
“The Department of Public Services always says, ‘There is no right or wrong answer. We just want to see that you’re thinking these issues through, that you’re giving a good-faith look at all the factors impacting the system,’” Stowe Electric’s Lazorchak said. “They want us to think about the future, but they’re not telling us which direction to take. They’re leaving that up to the distribution utilities and our customers.”