Xcel Energy is proposing a new approach to powering the grid in Minnesota.

The utility recently told state regulators it wants to build a network of solar-powered energy storage hubs, located strategically on its grid and linked with technology so they can be operated in concert with each other.

The result would be what’s known as a “virtual power plant.” By simultaneously discharging the batteries, for example, the collection of distributed resources can function similar to a conventional power plant.

It’s a solution some clean energy advocates have long pushed for as an alternative to larger, centrally located projects that are more reliant on long-distance transmission and create fewer local economic benefits. Xcel’s new embrace of the concept likely reflects the evolving economics of clean energy and the urgency to replace generation from retiring coal-fired power plants.

“I welcome our now-agreement about the importance of distributed energy resources in their future procurement plans,” said John Farrell, director of the Energy Democracy Initiative at the Institute for Local Self-Reliance.

Virtual power plants 101

Virtual power plants use sophisticated software and technology to aggregate energy from batteries, smart thermostats, electric vehicles, storage and other connected devices. The clean energy nonprofit RMI predicts virtual power plants nationally could reduce peak loads by 60 gigawatts and cut annual energy expenditures by $17 billion by 2030.   

Several utilities, as well as solar and storage companies, have developed virtual power plant programs around the country. Perhaps the best-known is National Grid’s ConnectedSolutions program in New England, which includes residential batteries, electric vehicle batteries, and thermostats.  

In May, Colorado Gov. Jared Polis signed legislation requiring Xcel Energy to create a virtual power plant plan in that state by next February. 

Xcel is pitching the Minnesota project on its own as part of its latest long-range resource plan. In a recent Public Utilities Commission filing, Xcel proposes combining 440 megawatts of solar power with 400 megawatts of battery storage at dispersed locations. Designed to be flexible, the program might add backup generation and energy efficiency measures in the future. 

A virtual power plant, Xcel said, would save ratepayers money, improve reliability, accelerate clean energy development, and reduce energy disparities by playing assets in underserved communities. The “new approach equips us to confidently meet incoming load growth, deliver unique customer and community value, and support economic development,” the company said in its filing.

Kevin Coss, a spokesperson for the company, said the proposal “is part of a larger plan to better serve the grid and our customers while meeting anticipated growth in energy demand. The program would grow our distributed energy resources as a complement to our existing plans for additional utility-scale renewable and firm dispatchable generation to advance the clean energy transition.”

Advocates reaction

Clean energy advocates say the approach could reduce Xcel’s need to build more infrastructure at a time when electricity demand continues to grow and its fleet of aging fossil fuel plants reach closure dates.

A recent study in Illinois suggested that pairing solar with storage could be the most economical and environmentally beneficial way to maintain grid reliability as the state transitions to 100% clean energy.

“Utilities always treated distributed energy resources as something that happened to them and that they had to figure out how to accommodate because they were being told to,” said Will Kenworthy, Vote Solar’s Midwest regulatory director. 

The company’s interest in more distributed resources could lead to a more flexible grid, one that helps mitigate substations congestion and allows it to store energy from wind farms for use during high-demand periods, Kenworthy said.

One area of disagreement between the utility and some clean energy advocates is who should own the facilities. Unlike in Colorado, Xcel is proposing to own the Minnesota solar and storage hubs itself, collecting money to build them — plus a rate of return — from ratepayers. 

That’s not the best deal for customers, and it prevents local communities and developers from being able to share the financial benefits of distributed energy, said Farrell, of the Energy Democracy Initiative. If Xcel owns the virtual power plant, the cost could be higher than they would be with an open, competitive process.

Farrell pointed to the recent opposition to an Xcel electric vehicle charging plan in which it sought to own all of the chargers. Convenience stores and gas stations argued Xcel had an unfair market advantage as the incumbent utility and would own too much of the state’s charging network. Xcel withdrew the proposal in 2023 after regulators reduced the charging network’s size.

As Xcel’s plan evolves, Farrell wants Xcel to allow businesses, homeowners, and aggregators to also participate by selling their battery capacity or demand response into the program.

The Minnesota Solar Energy Industries Association, which promotes battery storage, also takes a dim view of Xcel owning a virtual power plant.

“This is an area where competition would likely provide better service, lower cost and more choice to ratepayers,” said regulatory and policy affairs director Curtis Zaun. “Monopolies are not particularly good at providing the best service at a reasonable rate because that is inconsistent with their investors’ interests.”

Getting the details right

Virtual power plants are different than demand response, such as thermostat savings programs, in that they add value to the grid “without any change needed to the homeowner’s behavior,” said Amy Heart, senior vice president for policy at Sunrun, a home solar and storage company that participates in virtual power plants in the Northeast and in Texas, California, and Puerto Rico. 

Heart said the “devil is in the details” when creating a robust demand response program. A program in Arizona failed, she said, because of the underperformance of the single company it selected to aggregate resources.

Sunrun developed a virtual power plant in four New England states, enrolling more than 5,000 solar and storage customers to share their capacity on the grid. In the summer of 2022, Sunrun’s virtual power plant shared more than 1.8 gigawatt hours of electricity.

Typically, Sunrun customers agree under contract to share a portion of their battery backup 30 to 60 times annually for three hours or less for each event. The process is automated, with Sunrun’s software connecting to customer batteries and sending utilities power during high-demand times or predictable peak loads. Customers receive payment for the electricity provided.  

Heart said the best systems are open to individual customers and aggregators using different battery storage brands. Giving a virtual power plant “room to grow, breathe, and adapt will be important,” she added.

The Xcel virtual power plant proposal is part of the multi-year Upper Midwest Integrated Resource Plan, which regulators have been reviewing and will likely approve, with many changes, later this year.

In Minnesota, Xcel Energy looks to mimic power plant with solar and storage networks is an article from Energy News Network, a nonprofit news service covering the clean energy transition. If you would like to support us please make a donation.

This article was originally published by Canary Media.

A hefty chunk of U.S. emissions comes from the energy used to heat buildings. That means millions of homes must be converted to electric heating in order to meet climate targets. 

In Colorado, a 2021 law spurred the state’s largest investor-owned utility to produce a plan that could transition a lot of homes to clean heating — and fast.

Xcel Energy’s Clean Heat Plan was approved this May. It directs more than $440 million over the next three years mainly to electrification and energy-efficiency measures that are meant to reduce reliance on the gas system and cut annual emissions by 725,000 tons.

The utility, which provides both gas and electricity to its customers, filed an initial plan that included proposals to spend heavily on hydrogen blending, biomethane, and certified natural gas. But after strong opposition from clean energy advocates who say these routes do not represent viable pathways to decarbonization, those proposals were reevaluated. Following a motion filed by the Sierra Club, Natural Resources Defense Council, and others last November, Xcel amended its original plan filed with the Colorado Public Utilities Commission.

Now the majority of funds will go toward building electrification and energy efficiency, which the commission found to be the ​“most cost effective and scalable ways to reduce emissions from burning gas and buildings, both in the short run as well as in the long term,” said Meera Fickling, building decarbonization manager at Western Resource Advocates.

Electrification efforts will primarily take the form of incentives that make it cheaper for customers to switch gas heating appliances to electric heat pumps. The incentives can be combined with federal electrification tax credits and extend to all-electric new construction as well. One-fifth of the program’s funding is earmarked for low-income customers. The plan’s funding is roughly three times the $140 million that the Inflation Reduction Act allocated to Colorado for similar measures.

The utility forecasts gas sales to decline by 14 percent between this year and 2028, The Colorado Sun reports.

While many states have incentives and rebates available for upgrading to energy-efficient appliances and heating solutions, Colorado specifically directs its gas utilities to lead those programs — and holds them accountable for contributing to the state’s climate goals.

That’s why Xcel’s new clean heat program will be ​“a test case of a utility-led model towards decarbonizing the gas distribution system,” Fickling said. ​“It really serves as a model — a nationwide model — for how gas utilities can allocate resources to decarbonize their system in the long term.”

From state laws to utility plans 

Colorado’s push to clean up home heating started three years ago with the Clean Heat Law, which requires gas distribution utilities to create concrete plans to reduce their greenhouse gas emissions 4 percent below 2015 levels by 2025 and 22 percent by 2030. Xcel’s recently approved Clean Heat Plan will carry the utility through 2027, and the utility must propose a new plan in the coming years to meet the next target.

“I expect the next plan to really take a close look at the 2030 target and the trajectory to achieve it,” said Jack Ihle, regional vice president of regulatory policy at Xcel.

The Clean Heat Law was the first of its kind in any state, Fickling said, though others have since taken steps to curtail the climate impact of heating.

Following Colorado’s 2021 law, in 2023 Vermont passed the Affordable Heat Act to reduce emissions from home heating, and Massachusetts drafted similar legislation. This year, Illinois and New Jersey have both introduced bills with clean heating and decarbonization standards.

In Minnesota, the state’s largest gas utility just received approval for a five-year, $106 million plan to reduce its emissions following the state’s 2021 Natural Gas Innovation Act. The utility, CenterPoint Energy, says the plan would ​“reduce or avoid an estimated 1.2 million tons of carbon emissions over the lifetime of the projects,” though advocates have criticized the approach.

But utilities in Colorado ​“have a lot more flexibility in terms of the portfolio that they propose,” said Joe Dammel, manager of carbon-free buildings at RMI. While Xcel can prioritize energy efficiency and electrification in Colorado, Minnesota’s Natural Gas Innovation Act requires gas utilities to produce emissions-reduction plans that spend at least half of their budgets on alternative fuels like renewable natural gas, which can still heavily pollute. In Colorado, a much smaller amount is dedicated to alternative fuels; only around $10 million out of the $440 million can be spent on renewable natural gas and recovered methane, and all projects must specifically be approved by the commission.

Another difference between the two recently approved plans is that Xcel delivers gas and electricity to about 1.5 million customers in Colorado, which gives it an opportunity to counterbalance lost gas revenue with increased sales from its electricity business. 

Meanwhile, CenterPoint serves gas to about 910,000 customers but has no electricity customers. That gives it fewer opportunities to make up for losses from its gas business driven by electrification mandates, and more incentive to prioritize the use of alternative fuels delivered through the pipelines it owns — and not electrification.

Investing in 100,000 heat pumps 

Now that the funds have been approved, Xcel is waiting on a final written order from regulators, which should arrive later this month. From there, it will start implementing the plan and work on defining rebate levels and informing customers on how to access incentives.

The details are still being decided, but customers will likely need to pay first and then get reimbursed later, as is the case for many current rebate programs, said Emmett Romine, vice president of energy and transportation solutions at Xcel. Customers would also get higher rebates if they choose more advanced technologies, like high-efficiency cold-climate heat pumps.

Beyond educating customers, the company is putting workforce-training plans together to ensure there are enough heat-pump installers ready to help customers convert. Xcel is also working with distributors and manufacturers ​“to make sure that there’s a supply chain that will come to Colorado when we stimulate demand,” Romine said.

The plan represents a significant step up from Xcel’s current pace of upgrades. ​“The goals are really aggressive,” Romine said. ​“When you look at the number of heat pumps and the number of water heaters we’ve got to contemplate getting into homes, it’s an enormous amount of work.” Currently, Xcel does around 10,000 rebates a year for traditional gas furnaces. Now, it’s aiming to do 20,000 heat-pump conversions this year and just under 100,000 total by the end of 2026, Romine said.

That supercharged effort won’t come without costs. Ratepayers will see electricity rates go up by 1.1 percent and gas rates rise by 7 percent over the next four years due to the plan. But advocates say it’s worth it to avoid pouring money into a gas system that must be phased out — and that the climate benefits outweigh the upfront costs. Even without the Clean Heat Plan, Xcel projected it would need to increase base rate revenue by 32 percent between 2023 and 2030, The Colorado Sun reported.

Colorado’s plan ​“is a very good example of needing to pursue both sides of the equation at the same time — decarbonization, electrification — but at the same time ensuring that we’re starting to shrink and eliminate unnecessary investments in the gas system,” said Alejandra Mejia Cunningham, senior manager of state buildings policy at the Natural Resources Defense Council.

The Public Utilities Commission has encouraged Xcel to report its progress by 2026, ahead of the legally mandated schedule, Ihle said. Advocates will be watching closely to see how it all plays out.

“We’re gonna have to make sure that we’re seeing the results of that in terms of participation, customer satisfaction, and ultimately emissions and cost reductions,” Dammel said. ​“There’s going to be a lot of utilities across the country following this.” 

Xcel Colorado’s new clean heat plan is a big deal. Here’s why. is an article from Energy News Network, a nonprofit news service covering the clean energy transition. If you would like to support us please make a donation.

Minnesota solar developers frustrated with the process of connecting projects to the electric grid will soon have a new place to turn to answer questions and resolve disputes.

State lawmakers recently passed legislation calling on the state Public Utilities Commission to hire an interconnection ombudsperson to provide clean energy companies with information, guidance, and mediation on connecting projects of 10 megawatts and less to the grid.

The legislation follows years of complaints by solar companies about disputes with utilities, Xcel Energy in particular, that have contributed to years-long delays for some projects to connect.

“We hope that we can create a role dedicated to understanding the entire interconnection process and help manage those disagreements when they arise,” said Logan O’Grady, executive director of the Minnesota Solar Energy Industries Association.

The legislation says the ombudsperson will track disputes and serve as a mediator between customers and investor-owned utilities. They will be expected to review policies, convene stakeholder groups, and assess ways to reduce conflicts.

O’Grady said customers, installers, and developers could contact the ombudsperson for assistance on issues involving rooftop, commercial, or community solar projects. 

The ombudsperson would not eliminate the state’s existing dispute process for interconnection issues, which can take over a month and require mediation if unresolved issues remain.

O’Grady said he hopes having an interconnection ombudsperson will more efficiently resolve some disputes and provide a new option for developers that haven’t wanted to deal with the time and attention required to file a formal complaint.  

Solar developers’ complaints have varied, but some involve inaccurate information leading to “weeks of back and forth to get clarity on a simple misunderstanding,” O’Grady said. The hope is that an ombudsperson with experience in the industry could more efficiently answer those questions or know who to contact in utilities to provide guidance. 

State Rep. Patty Acomb, a suburban Democrat and chair of Climate and Energy Finance and Policy committee, said the ombudsperson’s work is less likely to draw skepticism because it comes from an independent source.

Solar company leaders support the new position. Bobby King, Minnesota program director for Solar United Neighbors, said the ombudsperson could “centralize” information, advocate for interconnection, create solutions to improve the process and avoid litigation. “I think it’s a positive step in the right direction,” King said.

Michael Allen, CEO of All Energy Solar, said the ombudsperson would provide “unbiased information” to the Commerce Department, the Public Utilities Commission, installers, and utilities. He also believes an ombudsperson could reduce the number of disputes that reach the Public Utilities Commission.

Marty Morud, CEO and owner of TruNorth Solar, said he’d had few issues with Xcel but sees an ombudsperson as a source for helping move utilities to respond if installer emails and phone calls go unanswered.

More than a dozen states already have positions similar to interconnection ombudspersons, including California, Massachusetts and New York. Sky Stanfield, a lawyer who works with the Interstate Renewable Energy Council, said states approach the ombudsperson differently, not all requiring them to have the technical skills Minnesota seeks.

She said that having someone see all the disputes and detect patterns could also help the Public Utilities Commission target rulemaking in problem areas. 

“I do think having a person whose job is to stay up to date on what is happening seems to me like a positive step,” Stanfield said.

To be effective, the ombudsperson must be “empowered” by the Public Utilities Commission and accepted as an objective mediator by utilities and clean energy developers, she said.    

The Legislature created an initial $150,000 budget. The ombudsperson position, which has not been posted, is expected to be filled later this year.

Minnesota lawmakers hope ombudsperson can help defuse solar interconnection disputes is an article from Energy News Network, a nonprofit news service covering the clean energy transition. If you would like to support us please make a donation.

Minnesota community solar developers are adjusting their business plans as the state’s program undergoes some of the biggest changes since its launch over a decade ago.

One of the oldest and largest in the country, Minnesota’s community solar program has spurred development of more than 800 megawatts worth of solar capacity since launching in 2013. Customers subscribe to shares of projects and receive monthly credits on their utility bills, typically lowering overall energy costs.

The concept has been hailed as a way to spread the benefits of solar to customers who lack rooftop space, sun exposure, or the financial means to install solar panels on their own. In practice, the biggest beneficiaries have been commercial customers, which subscribe to 82% of the program’s capacity, according to data tracked by the Institute for Local Self-Reliance. Commercial customers include private businesses as well as schools, churches, hospitals, and government entities.

State lawmakers passed legislation last session aimed at increasing the share of power going to residential subscribers, especially low- and moderate-income customers, as well as attempting to address long-simmering complaints by solar companies about the program’s administration by utility Xcel Energy.

“I think there were thoughts that it could be handled in a more unbiased way outside of the utility,” said Rep. Patty Acomb, a Democrat whose district covers a suburban area west of Minneapolis.

The Minnesota Department of Commerce will now manage the program and has formally begun accepting applications. However, Xcel Energy will continue to handle interconnection applications, which have been a source of friction between the utility and developers. 

Community solar developers will be allowed to build larger projects with fewer geographic restrictions, up to 5 megawatts anywhere in Xcel’s service territory. Previously, projects were limited to 1 megawatt, and developers could only sign up subscribers who lived in the same or an adjacent county as the project’s location. 

The biggest changes come with the mix of subscribers developers must recruit for projects. At least 30% of a project’s subscribers must be low- or moderate-income residential customers. Another 25% must be allotted for schools, government agencies or other public interest organizations. Each project must have at least 25 participants.

“We were trying to address equity and economics and making sure that the benefits are going to a more underrepresented group,” Acomb said.

What happens next

With the new application process and subscriber requirements, as well as ongoing congestion in Xcel’s interconnection queue, developers expect a slow first year under the new rules but generally support the program’s new direction.  

Brendan Dillon, president of Minneapolis-based solar developer Nokomis Energy, said the new program “much better reflects what community solar should be, which is a tool that allows people who, for whatever reasons — whether it’s financial, or they don’t own their home or condo or they don’t have roof space — to be able to access clean energy and apply its financial benefits.”

Nokomis Energy plans to work through existing community groups and those associated with local governments to reach the designated income-qualified subscriber pool. Dillon said solar developers will do more community outreach and engagement to reach potential low-and-moderate subscribers. 

Rob Appelhof, CEO and president of Cedar Creek Energy, said he works with another company to market subscriptions, and they already have a strong representation of low and moderate-income participants, so recruiting “should not be a problem.”

Developers said removing the geographic restrictions will help them build more projects and allow more farmers to benefit from leasing land to solar companies.

“It opens up more opportunities for urban residents to subscribe to community solar,” said Eric Pasi, CEO of Enterprise Energy.

US Solar Corporation President Reed Richerson said that “there are plenty of farmer landowners who want to host community solar on a portion of their land, and they’ve been unable to because they live in areas where, despite there being achievable permitting and achievable interconnection, there was a constraint with accessing subscribers.”

The dual application process splits the interconnection approval, Xcel’s responsibility, with the project approval from Commerce. 

“In these early days, it is becoming a bit stickier than I think we might have imagined, mainly because I think Xcel isn’t necessarily on the same page as the Department of Commerce or the way the law is written,” Richerson said.

Richerson said he does not expect projects under the new rules to win approvals from Xcel and Commerce “until, at earliest, March,” he said. “And then, upon the award, you can go build your projects. But with timelines of these things, having anything online by the end of the year will be challenging.”

A race against time

Unlike before, the program will now have annual caps, starting at 100 MW from 2024 to 2026, 80 MW through 2030 and 60 MW from 2031 on. That will create new pressure and uncertainty for developers, who could spend thousands of dollars to secure a site and an interconnection agreement only to have Commerce turn the project down. 

“I guess the biggest uncertainty is getting your projects approved when there’s only a limited amount of them,” Appelhof said.

Cooperative Energy Futures has served low-income subscribers through community and rooftop solar for years. Policy and Regulatory Director Pouya Najmaie said developers will leverage income-qualified participation necessary for the state program to take advantage of incentives in the federal Inflation Reduction Act.

With enough low-income subscribers, a developer can add as much as 20% to 30% tax credit available for community solar, reducing the cost of a project by half, he said. “We’re doubling down more on low-income (customers) because of the IRA,” Najmaie said.

Cooperative Energy Futures will not initially seek to build larger, remote projects but instead focus first on smaller ones built nearer to subscribers’ homes. 

“We’re going to be concentrating a lot on the city and looking for warehouses and large building rooftops for hosting,” he said. “The capacity is much better there, and you’re closer to load, so it’s generally more efficient.”

Xcel Energy is still studying the cost impact of the legislation and “won’t know more until we understand what the customer makeup of the new gardens will be, because the legislation creates several different bill credit rates based on customer groups,” said spokesperson Theo Keith.

The utility supports the focus on residential, income-qualified and public interest subscribers because it will “expand options for income-qualified customers to participate directly in the clean energy transition,” he said.

Xcel has also asked regulators for more time to solve a persistent and confusing issue for community solar. Customers currently receive two bills, one from the community solar developer and another from Xcel that includes credit for the electricity their subscription produces. The legislation requires Xcel to develop a combined bill for those customers.

Minnesota reboots community solar program with new focus on lower-income residents  is an article from Energy News Network, a nonprofit news service covering the clean energy transition. If you would like to support us please make a donation.

Xcel Energy customers in Minnesota will likely soon have good reason to hold off on running dishwashers or charging vehicles until bedtime.

The state’s largest utility is asking regulators to approve a major change to how residential customers have paid for their electricity for decades.

In December, the company proposed moving away from the standard, flat hourly rate that almost all its customers currently pay and replacing it with a variable “time-of-use” rate design that charges more for power during periods of high demand.

Rates between 3 p.m. and 8 p.m. weekdays would be twice the rate customers currently pay, and seven times higher than the proposed overnight “off peak” rate between 12 a.m. to 6 a.m. Other hours of the day would be charged a “base” rate. 

Winter electricity would be, on average, more than 30% cheaper for base and peak rates than Xcel’s summer rates. Xcel told regulators that typical customers will pay 17.8% more for electricity in summer and 10.6% less in winter, assuming no behavioral changes in consumption. Xcel customers use roughly 20% less electricity in winter as most currently heat their homes with natural gas.

Xcel wants time-of-use to be the default billing system for all residential customers, though customers could opt-out.

The proposal follows a two-year pilot project Xcel operated in neighborhoods in suburban Eden Prairie and the Longfellow area of South Minneapolis. The company found a modest shift in customers reducing energy in peak periods, enough to support broader adoption across its Minnesota territory, according to Xcel spokesperson Theo Keith.

“This new proposal will make our successful pilot available to more customers,” he said. “During the pilot, we saw that participants saved a modest amount on their energy bills even with a modest increase in overall energy usage. Customers responded to the pilot rate design by shifting some usage away from peak times with the highest energy prices.”

The new pricing structure is possible because of Xcel’s installation of more than 500,000 smart meters that will allow customers to better track their energy use through an online portal, Keith said. The proposal also fulfills a Public Utilities Commission requirement that Xcel move to time-of-use rates, he said.

The concept has parallels with the growth of dynamic pricing by hotels, airlines, ride-hailing services and sports and entertainment tickets. California has been the leader in time-of-use utility pricing, with power companies there using it as the default for billing customers. Several other utilities nationwide have similar rate programs or are studying its potential to help prepare the grid for more electrification and renewable energy. And Xcel’s Colorado subsidiary has begun rolling out time-of-use rates there.

The utility believes that by shifting consumption to later and overnight hours, it can take advantage of the abundant wind energy typically available during those periods, Keith said. Shifting to non-peak times also helps Xcel avoid building more power plants, especially peaker plants that operate only a handful of hours annually but often create high emissions.

Xcel is part of the Midcontinent Independent System Operator (MISO) regional energy market, one of two in the country forecasted to have a “capacity crunch” over the next five years, said Gabe Chan, an associate professor and energy policy expert at the University of Minnesota. He said that trying innovative approaches such as time-of-use to reduce consumption at high demand times will help balance the electric grid.

Arguments for and against time-of-use

Citizens Utility Board of Minnesota executive director Annie Levenson-Falk said time-of-use rates could be more fair than the current rate because, under a flat rate, customers pay more than it costs to produce electricity in low-demand periods and less than the cost during high-demand times.

The consumer advocacy nonprofit’s Illinois affiliate found in a study “that time-of-use rates are more equitable” because lower-income households didn’t use much energy in peak periods than higher-income households, Levenson-Falk said.

Using 2016 data from Commonwealth Edison, Illinois’s largest utility company, the report showed that 97% of its customers would save money under a time-of-use plan without making any behavioral changes. They would reduce their bill by an average of 13.2%, with low-income households seeing an additional 1% savings.

Shifting electricity use to base and non-peak hours tends to reduce emissions, too, Levenson-Falk said. Wind energy is widely available at night, while solar energy tops out in the middle of the day. She said that as solar power grows in Minnesota, Xcel could adjust the peak to take advantage of the sun.

But there are drawbacks. Levenson-Falk said customers using power during peak hours will see substantial bill increases. Some low-income households may not have the ability to change consumption patterns. And customers may find it hard not to use electric stoves, heat pumps or water heaters during peaks.

“Are we going to be disincentivizing beneficial electrification?” she asked.

There’s also the problem of reducing peaks during some hours only to create them in other hours. A University of Texas study of 100 Austin homeowners using time-of-use rates found most shifted use of appliances such as heating, ventilation, and air conditioning equipment to non-peak times — so much so that they created a higher residential peak in lower-cost hours.

The pilot

Xcel’s two-year “Flex Pricing” pilot study that ended in 2022 involved nearly 17,000 ratepayers in Eden Prairie and Minneapolis, with 10,000 in the time-of-use program and the rest in the control group. Working with consulting firm Guidehouse, Xcel discovered in the pilot that electricity demand during peak periods was “modest” in Eden Prairie. In Minneapolis, the same was true in the pilot’s first year before trailing off in year two.

The pilot found a small subsector of participants drove much of the reduction in energy use during peak times. Representing around 10% of the participants, these “highly engaged” customers understood time-of-use rates and made proactive decisions to decrease their electricity use.

Xcel concluded in its regulatory filing that “the demand impact was close to achieving the goal of incentivizing less energy consumption during peak times in a revenue-neutral manner.” The study saw customers increase their energy consumption slightly, shifting electricity use rather than reducing it.

Customer bills in Eden Prairie grew slightly and declined marginally in Minneapolis. Participants paid more than they would at the standard rate in summer and less in winter, but Eden Prairie did not see enough decline to make up the difference. The highly engaged participants made the most progress in seeing their bills decline yet averaged just a $4 monthly decrease.

The pilot’s income-qualified customers, mostly living in Minneapolis, saw bills reduced by 3%. Those customers were “statistically significantly more satisfied with the pilot than the general population was,” Xcel said. “This was like the response from participants who were seniors, renters, or those who use a smart thermostat.”

Matthew Grimley, a University of Minnesota researcher at the Chan Lab, said Xcel likely did not achieve more demand response because not all customers had the technology to control demand and reduce consumption, such as smart thermostats, controllable and electrified water heaters, and electric vehicles.

Xcel reported that fewer than 50% of pilot participants knew about energy efficiency kits the company made available to help them reduce energy use. Just 20% went through the process of receiving a kit. Grimley said Xcel will have to do a better job of sharing time-of-use kits for the rates to work.

Chan added that the variable rates should be only the start of a new way of thinking about how the electric grid operates. He believes giving rebates during critical peaks and using text messaging to ask customers to reduce their electricity might be “a more direct way that achieves the same goals at potentially much more effective scaling.”

Organizations and individuals can now forward comments to Xcel’s time-of-use docket. The Public Utilities Commission has not scheduled any hearings yet, but the utility hopes to begin dynamic pricing in 2025.

Xcel Energy proposes time-of-use rates as the default option for Minnesota customers is an article from Energy News Network, a nonprofit news service covering the clean energy transition. If you would like to support us please make a donation.