Electrification, expanding data center deployments, increasing investments in manufacturing sectors — such as semiconductors — and more are driving new growth in electric demand. At the same time, existing power plants are aging, and increased amounts of intermittent renewable energy are getting added to the grid, whether by mandate or changing economics. Add in increasingly intense storms and other weather events, transmission constraints, and supply chain disruptions, and it’s no wonder that the question of where the future power supply will come from — and if there will be enough to go around — keeps utility leaders up at night.
The Department of Energy laid out some of these energy resource acquisition challenges in an April 2024 report, The Future of Resource Adequacy. In its report, the DOE called for utilities to create a diverse portfolio of resources and take advantage of provisions in the Inflation Reduction Act and the Infrastructure Investment and Jobs Act that have made billions of dollars in tax credits, loans, and investments available for deploying energy technologies.
“Reliability is a system attribute — no individual resource is perfectly reliable. Any single technology approach to addressing the combination of challenges is risky, partly due to substantial fuel delivery and availability issues that lead to correlated failures which can jeopardize the entire system during extreme weather,” said the report.
As public power utilities ponder how they’ll meet demand over the short- and long-term horizon, they also need to ensure their power supply choices keep costs to customers as low as possible. For utilities that buy power in the wholesale electricity markets, new and changing resource adequacy requirements could be contributing to increased projected costs. These requirements include setting appropriate planning reserve margins and identifying how much accredited capacity should be assigned to specific generation resources. These requirements aim to ensure there’s enough supply to meet demand based on a defined level of reliability for an upcoming period.
Following is a look at how two public power utilities — Orrville Utilities in Ohio and Truckee Donner Public Utility District in California — are exploring ways to ensure they have the resources required to serve their customers’ needs into the uncertain future.
Forecasting Big Changes
For Truckee Donner PUD, located between Sacramento, California, and Reno, Nevada, achieving resource adequacy requires both meeting California’s ambitious renewable portfolio standard and planning for the robust adoption of electric vehicles. The state’s RPS calls for 60% renewables in the utility mix by 2030 and 100% carbon-free by 2045. California already boasts the highest number of EVs, accounting for about 37% of all EV registrations in the U.S., and set a mandate for all new light-duty vehicle sales to be from zero-emissions vehicles by 2035.
Truckee Donner is ahead of the RPS target, with about 60% renewables already in its resource mix, said Jared Carpenter, electric utility director. But that doesn’t mean resource planning is a breeze. In fact, Truckee Donner recently completed its first integrated resource plan, even though, with a peak load of less than 200 megawatts, it isn’t required to file a plan with the state. But Carpenter wanted to map out all the resources available and plan for last-minute surprises, such as transmission constraints, low solar output, or unexpected outages, such as from wildfires.
The utility’s resource mix includes biomass, small hydroelectric plants, wind, and renewable energy certificates, mostly for solar. Outside of balancing the intermittency of these resources, there are other aspects of their availability to consider. Specifically, Carpenter is seeing more maintenance on the lines that run from newer renewable energy plants. Truckee Donner does not directly own the transmission infrastructure that carries power from its power plants to its distribution system, and that creates some uncertainty due to lack of control and information.
“I see a lot more transmission line maintenance on renewable energy generation projects like wind and solar. I’m sure they’re necessary, but the challenge is when we are told there will be unplanned maintenance that leaves our generation sources stranded,” he said. When that happens, Truckee Donner needs to replace that power from the market or other sources, generally within two weeks.
“You scramble fast, and you shop quickly and try to do it before everyone else does it, too, as best you can,” he said.
To aid in that scramble, as Truckee Donner completed its IRP, it also created an integrated resources balance sheet that shows resource options every hour of every day through 2040. If a generation resource needs maintenance, Carpenter can remove it from the balance sheet and use the document to consider other ways to fill the gap.
“It could be a bundle of energy in those blocks, or it could be by the hour,” he said. Solar would likely fill the gap during daytime hours, he added.
Another challenge in resource planning is accounting for the potential damage to power plants and transmission infrastructure caused by wildfires. For example, fires near the transmission lines that send power to Truckee Donner across Nevada, Utah, and California could burn plains or a forest near where a hydroelectric dam is located, damaging the power line coming from the hydroelectric facility. In that case, it might take weeks to rebuild the power line. If the hydroelectric dam is part of Truckee Donner’s renewable energy portfolio, the utility would try to replace that power with another source of renewable energy.
To help plan for such scenarios, public utilities need to diversify their resources, said Carpenter. And that strategy can create its own problems: With more power plants, more maintenance is required.
“It becomes very complicated,” he said.
Truckee Donner’s IRP looks at multiple scenarios for attaining a balanced portfolio, including low-, medium-, and high-growth options. Much of the growth is expected to come from residential and public EV charging and from electrification of homes.
Right now, about 90% of the projects Truckee Donner PUD is considering are renewables. Carpenter is also looking at natural gas-fired plants in the hope that they can be converted to green hydrogen plants down the line. This option is on Carpenter’s mind but isn’t included in Truckee Donner’s IRP, in part because it’s still unclear whether California will characterize hydrogen as a renewable resource.
Here’s how Carpenter envisions Truckee Donner would use hydrogen: It might buy into a portion of a gas plant in a region with high solar potential. It would then acquire solar energy when prices are low — when there’s too much solar available — and the energy could power an electrolysis machine, which requires electricity and water to make hydrogen. Truckee Donner would call on the hydrogen plant at night, when solar is no longer available, but the green hydrogen has been stored onsite.
Another challenge for Truckee Donner is meeting changing resource adequacy requirements, said Carpenter.
“As the markets in the West expand and change, resource adequacy is one of the things that will change the most by percentage of cost for many utilities,” he said. To prepare for changing requirements, he attends industry events and tries to forecast how and when the rules and markets will change. He also looks to invest in power plants that meet the utility’s needs and comply with the narrow flexibilities of resource adequacy — all under a timeline that aligns with regulation changes.
“For Truckee, we are doing this by building battery systems that we can dispatch to lower our coincidental peak and looking for generation like geothermal and hydrogen that will help us comply as the rules change and increase,” Carpenter said. “Really, it’s such an interesting puzzle to figure out.”
Maintaining Control
While Truckee Donner has a big focus on meeting California’s RPS, Orrville Utilities, a public power utility serving the small city of about 8,000 people in Ohio, is concentrating on keeping prices as low as possible while adhering to environmental regulations. Its resources in 2022 included 29 MW of natural gas and coal, 12.4 MW of hydropower, 2 MW of wind, and 3 MW of solar, all of which are used to meet peak demand of about 60 MW.
“But that’s not a long-term solution for us. We’re capable of doing that with a very old coal and natural gas plant, but it’s subject to the whim of the next round of Environmental Protection Agency regulations,” said Jeff Brediger, Orrville’s director of utilities. Older fossil fuel plants are also subject to high insurance premiums, he noted.
Through membership in American Municipal Power Inc., or AMP, which serves public power providers in nine states, Orrville Utilities can participate in a number of power supply options, including buying from the market.
Orrville can only buy power from its natural gas/coal plant during peak power periods because the EPA has imposed a generating limit on the plant. That means the utility buys about 35% of its power from the market and, as a result, is sometimes exposed to higher market costs during peak periods.
The bigger challenge in ensuring resource adequacy for Orrville Utilities is in overcoming transmission constraints.
“Buying the actual [kilowatt-hours] is one component of those market purchases,” said Brediger. “The more concerning issue that we have in the marketplace is transmission access.”
The Midcontinent Independent System Operator has placed limitations and restrictions on moving energy from a generation source to the end user because of transmission constraints. Three of AMP’s hydroelectric projects and a coal and gas project are in MISO territory. So, even though Orrville Utilities obtained this generating capacity, the power can’t always be moved from MISO, he said.
What’s more, the generating units aren’t always available when they’re really needed.
During Winter Storm Elliott in December 2022, for example, temperatures in Orrville’s territory dropped to 14 degrees below zero. Power plants froze up, and the utility couldn’t get natural gas flowing.
In the future, Orrville, working with AMP, wants to rely on more local, behind-the-meter distributed energy. The goal is to avoid depending on the grid and the wholesale market, which can cause planners to stay awake at night worrying, Brediger said.
“The more we can keep resources literally in our backyards, the less dependent we are on the grid to deliver that energy,” Brediger said.
Focusing on behind-the-meter assets is a good way to cope with changing resource adequacy requirements, said Steve Lieberman, vice president of transmission and regulatory affairs for AMP.
“Anything Orrville can do to supply its demand from contracts and other arrangements is good,” he said.
Orrville prefers to own and control power plants — natural gas or diesel generators or fast-start peaking diesel generators that are easier to permit and install. The few solar power acquisitions the utility might consider would have to include storage to address intermittency issues, Brediger said. And that might be too expensive.
A behind-the-meter strategy will help Orrville offset about 80% to 90% of transmission fees now levied by transmission system owners — fees that can be as high as 40% of customers’ bills, he said.
“If we have control and ownership of how much generation we want, the type of generation we want, we can better serve the needs of our customers,” he said.
