Amid a surge in utility shutoffs, and in the face of a groundbreaking study finding racial disparities in those outcomes, Minnesota’s largest utility is taking a closer look at the issue.

In a November agreement with consumer groups and the state’s Public Utilities Commission, Xcel Energy has outlined a series of steps to provide more information to customers and make it easier for them to restore service.

Xcel also agreed to hire an outside consultant to conduct a one-year study of disparity issues related to disconnections and outages and, separately, do its own analysis of outages. The move came in response to a University of Minnesota study released earlier this year that found that people of color were more likely than White households to have their service disconnected for falling behind on bills, even when controlling for income and home ownership status. 

The agreement falls short of a demand from the Minnesota Attorney General’s Office for Xcel to institute a temporary moratorium on shutoffs until racial disparities are addressed, based on a recommendation from Fresh Energy and a coalition formed by Cooperative Energy Futures, Environmental Law & Policy Center, Sierra Club, and Vote Solar. 

Erica McConnell, staff attorney for the Environmental Law & Policy Center, represented the clean energy organizations advocating for grid equity. She supported the agreement but believes it will do little to help reduce disparities in shutoffs. 

“These are very important improvements that don’t really address — and the commission didn’t discuss — the disparate impacts and the racial disparity (of disconnections) and how to address that specifically,” she said.

A temporary moratorium on disconnections would have allowed for time to study disparities and find ways to address them.  

“The commission didn’t talk about that,” McConnell said. “They didn’t address it at all, so that was disappointing. I understand it’s uncomfortable and it’s a tough issue, but it’s disappointing they shied away taking it head on.”

Shutoffs soaring

Beyond the challenge of disparities, Xcel’s number of service disconnections has skyrocketed. More than 45,000 Xcel customers saw their power shut off this year, a number that has grown significantly over the last two decades. 

Xcel agreed to many proposals from the Citizens Utility Board of Minnesota, the Energy CENTS Coalition, clean energy organizations and the Public Utilities Commission to create more consumer protection against shutoffs.

Xcel Energy’s involuntary disconnection notices began rising significantly in 2023 before skyrocketing in 2024, when shutoffs doubled the prior year’s total for May through July. Despite Minnesota’s cold weather protection rules that limit disconnections during the winter through April 30, shutoffs even grew during the winter months.

Clean energy and consumer organizations point to Xcel’s ability to remotely disconnect customers who have smart meters as a major reason for the shutoffs, along with inflation, escalating rate increases and challenging repayment requirements. Xcel had demanded customers pay 50% of what they owe to reconnect, which may have violated Minnesota law, according to the Citizens Utility Board. 

Xcel’s pact with the Citizens Utility Board and Energy CENTS “is going to make payment agreements more affordable and hopefully help households that are behind on their bills avoid getting shut off and get caught back up,” said Annie Levenson-Falk, executive director of the Citizens Utility Board of Minnesota.

The utility board and Energy CENTS Coalition forged the agreement with Xcel under the purview of the Public Utilities Commission, which will issue a final order later. The agreement requires the following:

• Customers will pay 10% of what they owe to have the power turned back on, instead of 50%.
• The amount due will have to be at least $180 before Xcel can send a disconnect notice.
• Xcel cannot shut off power until a customer reaches a $300 past due balance. Xcel’s data from this year showed disconnected customers were $441 in arrears on average in October and much higher in other months.
• The utility must wait at least 10 days after a shutoff notice has been sent to disconnect, up from five days.
• Xcel must post clear disconnection and payment policies on its website, along with information about customers’ right to develop an affordable repayment plan. Any changes Xcel makes to shutoff policies and repayments have to be reported to the commission, and it must collect data on repayments and customer agreements.
• A variance allowing remote disconnections without field visits from Xcel remains, but the utility must contact customers via voicemail and use at least one other form of electronic communication.

Xcel spokesperson Kevin Coss said the utility believes “this agreement is a great step toward reducing disconnections for some of our customers who continue to struggle economically.”

Options for customers

George Shardlow, Energy CENTS executive director, said he thought a clearer explanation of the disconnection process on Xcel’s website brings a transparency that had been lacking.

“I don’t think the average person even knows that they have a right to negotiate when they’re struggling to pay their bills,” he said. “It’s all sort of opaque. We’re excited to see better documentation of people’s rights on Xcel’s website.”

Minnesota law says utility customers are “entitled” to a payment plan they can afford, Shardlow said. Customers who cannot afford the 10% down payment can still negotiate for a settlement that fits their budget, he added.

Shutoffs have been growing. This year Xcel sent disconnection notices to 51,000 customers in January and 71,000 in July. But not all notices result in shutoffs. The highest month for disconnections, May, saw more than 10,000 shutoffs. By August, slightly more than 8,400 customers had been disconnected.

Coss said Xcel works with customers to avoid disconnection by starting a nine-week process of contacting them through multiple channels to “point them to available options for energy assistance — both through the federal Low Income Home Energy Assistance Program and our own affordability programs — and offer flexible payment plans tailored to their circumstances.”

Minnesota also has cold weather protections that greatly reduce utilities’ ability to disconnect customers in winter months. But people who fail to pay their bills in winter see their balances grow, leading to higher disconnections in summer when they fail to catch up.

Xcel agreed to monitor progress and collect more data on racial disparities involving customers involuntarily shut off. The utility has already hired a third party evaluator, as the agreement requires, to study its shutoff policies and hold stakeholder engagement meetings during the year-long process.

Coss said disparities result in inequities throughout society and Xcel has been doing its part to address them. The utility has worked with the study’s authors and advocacy groups to identify actions to reduce disparities, he said.   

Earlier this year, the commission also approved a proposal by Xcel for a pilot program that will provide bill credits to select census tracts with high levels of disconnections. Coss said Xcel will provide $500 bill credits to customers in low-income census areas who have a greater than $2,000 past-due balance, using money available from a quality of service program.

Minnesota Public Utilities Commissioner Joe Sullivan said he believed the agreement negotiated among the nonprofits and utility would reduce the financial strain on households facing disconnections and assist Xcel in recovering debt.

“I thought that in that docket people came together and were constructive,” he said. “I feel like I’m hopeful that the order will make some progress.”

PUC Chair Katie Sieben said the commission is “always looking at affordability, and especially as it pertains to low-income customers, I think we have a great track record on working with stakeholders and with utilities to provide robust low-income assistance to customers.”

She mentioned the commission’s role in approving an Xcel pilot to decrease payments for low-income, low-usage customers and a September decision that used a penalty for the utility’s service quality underperformance to provide bill credits to around 1,000 customers with the oldest outstanding balances in low-income census tracts.

‘Still more work to do’

The agreement does not solve the problem of low-income customers struggling to pay utility bills. Shardlow said Energy CENTS and the Citizens Utility Board lobbied the state legislature to allow households to apply for energy assistance funding the entire year instead of the current policy of having a deadline of May 31. Only 20% of eligible Minnesota households participate in the program, he said.

Levenson-Falk wants Xcel to consider eliminating the 1.5% late fee it charges customers on their balance, or consider donating the money to affordability programs.

The Citizens Utility Board also wants Xcel to develop a plan to reconnect customers quickly on days of high heat or poor air quality. Coss said Xcel will evaluate reconnecting customers disconnected during days of air quality alerts.

Levenson-Falk said the agreement at least makes progress. “I think we resolved everything that we had discussed with Xcel but that’s not to say that we think this is going to solve the problem, because, of course, there are still going to be continuing shutoffs, and those are still very concerning,” she said. “There’s still more work to do.”

This story was updated to include a statement from Minnesota Public Utilities Commission Chair Katie Sieben.

Fresh Energy staff, board members and funders do not have access to or oversight of the Energy News Network’s editorial process. More about our relationship with Fresh Energy can be found in our code of ethics.

As utility shutoffs soar in Minnesota, Xcel Energy agrees to consumer protections and racial disparities study 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.

A top executive with Minnesota’s largest utility says data center growth will not prevent it from meeting the state’s 100% clean electricity law, but it may extend the life of natural gas power plants into the next decade.

“As we take all of that coal off the system — even if you didn’t add data centers into the mix — I think we may have been looking to extend some gas (contracts) on our system to get us through a portion of the 2030s,” said Ryan Long, president of Xcel Energy’s division serving Minnesota and the Dakotas. “Adding data centers could increase the likelihood of that, to be perfectly honest.”

Long made the comments at a Minnesota Public Utilities Commission conference this fall exploring the potential impact of data centers on the state’s 2040 clean electricity mandate.

The expansion of power-hungry data centers, driven by artificial intelligence, has caused anxiety across the country among utility planners and regulators. The trend is moving the goalposts for states’ clean electricity targets and raising questions about whether clean energy capacity can keep up with demand as society also tries to electrify transportation and building heat.

Minnesota PUC commissioner Joe Sullivan organized last month’s conference in response to multiple new data centers projects, including a $700 million facility by Facebook’s parent company Meta that’s under construction in suburban Rosemount. Microsoft and Amazon have each acquired property near a retiring Xcel coal plant in central Minnesota. 

“We need to ensure that our system is able to serve these companies if they come,” Sullivan said, “and that it can serve them with clean resources consistent with state law.” 

Alongside concerns about whether clean energy can keep up with new electricity demand, there’s also an emerging view that data centers — if properly regulated — could become grid assets that help accelerate the transition to carbon-free power. Several stakeholders at the Oct. 31 event shared that view, including Xcel’s regional president.

A 100-megawatt data center could generate as much as $64 million in annual revenue for Xcel, enough to help temper rate increases or cover the cost of other projects on the system, Long said. He said the company wants to attract 1.3 gigawatts worth of data centers to its territory by 2032, and it thinks it can absorb all of that demand without harming progress toward its 2040 clean energy requirement.

Long said data center expansion will not change the company’s plans to close all of its remaining coal-fired power plants by 2040, but it may cause them to try to keep gas plans operating longer. Ultimately, meeting the needs of data centers will require more renewable generation, battery storage, and grid-enhancing technology, but rising costs and supply chain issues have slowed deployment of those solutions.

Other utilities echoed that optimism. Julie Pierce, Minnesota Power’s vice president for strategy and planning said the company has experience serving large customers such as mines in northeastern Minnesota and would be ready to serve data centers. Great River Energy’s resource planning director Zachary Ruzycki said the generation and transmission cooperative “has a lot of arrows in its quiver” to accommodate data centers.

Ruzycki noted, too, that much of the interest it has received from data center developers is because of the state’s commitment to clean energy. Many large data center operators have made corporate commitments to power them on 100% carbon-free electricity, whether from renewables or nuclear power.

Pete Wyckoff, deputy commissioner for energy at the Minnesota Department of Commerce, expressed doubts about the ability to meet unchecked demand from data centers. Even with the state’s recent permitting reforms, utilities are unlikely to be able to deliver “power of any sort — much less clean power — in the size and timeframes that data centers are likely to request.”

He sees hydrogen, long-duration batteries, carbon capture, and advanced nuclear among the solutions that will eventually be needed, but in the short-term the grid could serve more data centers with investments in transmission upgrades, virtual power plants, and other demand response programs.

“These solutions can be deployed faster and cheaper than building all new transmission and large clean energy facilities, though we’ll need those, too,” Wyckoff said.

Aaron Tinjum, director of energy policy and regulatory affairs for the Data Center Coalition, said data centers provide the computing power for things like smart meters, demand response, and other grid technologies. The national trade group represents the country’s largest technology and data center companies.

“We can’t simply view data centers as a significant consumer of energy if they’re all helping us become more efficient, and helping us save on our utility bills,” Tinjum said. 

He also pointed to data centers’ role in driving clean energy development. A recent report from S&P Global Commodity Insights found that data centers account for half of all U.S. corporate clean energy procurement. 

The true impact of data centers on emissions and the grid is complicated, though. Meta, which participated in the recent Minnesota conference, says it matches all of its annual electricity use with renewable energy, but environmental groups say there is evidence that its data centers are increasing fossil fuel use and emissions in the local markets where they are built.

Amelia Vohs, climate program director with the Minnesota Center for Environmental Advocacy, raised concerns at the conference about whether data center growth will make it harder to electrify transportation and heating. She pointed to neighboring Wisconsin, where utilities are proposing to build new gas plants to power data centers.

“This commission and the stakeholders here today have all done a ton of work and made great progress in decarbonizing the electric sector in our state,” Vohs said. “I worry about possibly rolling that back if we all of a sudden have a large load that needs to be served with fossil fuels, or [require] a fossil fuel backup.” 

The Minnesota Attorney General’s Office argued that state regulators need to scrutinize data center deals to make sure developers are paying the total cost of their impact on the system, including additional regulatory, operational and maintenance work that might be required on the grid.

In an interview, Sullivan said he was impressed by tech companies’ interest in having data centers in Minnesota because of the 2040 net zero goal, not despite it. They want to buy electricity from Minnesota utilities rather than build their own power systems or locate in neighboring states, he added, and the October meeting left him confident that “we can deal with this.”

Xcel Energy says data center growth won’t get in the way of 2040 clean energy target in Minnesota 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.

A solar-powered microgrid project backed with funding from the Biden administration aims to reduce energy burdens and provide backup power to a tiny northern Minnesota tribal community.

The Pine Point Resilience Hub would serve an elementary school and community center in Pine Point, an Anishinaabe village of about 330 people on the White Earth Reservation.

In June, the project was selected to receive $1.75 million from the U.S. Department of Energy’s Energy Storage for Social Equity (ES4SE) Program, which helps underserved and frontline communities leverage energy storage to make electricity more affordable and reliable. It’s part of a slew of Biden administration funding related to grid resilience and energy equity that has spurred several tribal microgrid projects across the country.

The developers, locally owned 8th Fire Solar and San Francisco-based 10Power, hope to finish the project next year, and have also secured funding from Minnesota’s Solar for Schools program and foundation grants but said they still need to raise about $1 million. They’re also counting on receiving about $1.5 million in federal tax credits, which face an uncertain future with the incoming Trump administration. 

“The idea of the microgrid is to help with infrastructure,” said Gwe Gasco, a member of the White Earth Nation and the program coordinator with 8th Fire Solar, a thermal solar company based on the reservation.

Tribal communities were largely bypassed during the massive, federally funded push under the Rural Electrification Act of 1936 to bring electricity to remote rural areas of the country. As a result, grid infrastructure on many reservations remains insufficient to this day, with an estimated 1 in 7 Native American households on reservations lacking electricity connections, and many more contending with unreliable service.

On top of higher-than-average electric reliability issues, tribal communities also generally pay higher rates for electricity and face higher energy burdens due to poverty and substandard housing.

On the White Earth Reservation, these challenges are most pronounced in Pine Point, where one-third of residents live in poverty. Gasco said the area is among the first to suffer from outages, with eleven occurring over the last five years, according to the Itasca-Mantrap Electric Cooperative that serves the area.

The Pine Point Resilience Hub project will build on an existing 21-kilowatt solar array, adding another 500 kilowatts of solar capacity along with a 2.76 megawatt-hour battery storage system, enough to provide about 12 hours worth of backup power for residents to be able to charge cell phones, power medical equipment, or stay warm in the event of a power outage.

Gasco said the microgrid could be especially important in the winter, given the area’s “brutally cold” weather and reliance on electric heat. They also hope it will reduce utility costs, though they are still negotiating with the local electric co-op on rates for power the system sends and receives from the utility’s grid. Itasca-Mantrap President and CEO Christine Fox said it doesn’t set net metering rates, which are determined by its electricity supplier.

The project developers hope to qualify for additional federal tax credits by using equipment largely produced in the U.S., including Minnesota-built Heliene solar panels, inverters made in Massachusetts, and Ohio-produced solar racks.

The developers have partnered with the Pine Point School District, which plans to incorporate the microgrid into an Ojibwe-language curriculum on renewable energy. A monitoring interface will allow students to see real-time data in the classroom.

“It’s powerful to me that this (project) is at a school where we’re hoping to inspire the next generation of kids,” said Sandra Kwak, CEO and founder of 10Power, a for-profit company that specializes in developing renewable energy projects in tribal communities.

Corey Orehek, senior business developer for Ziegler Energy Solutions, which has been hired to do the installation, said they plan to work with a local community college to train students for solar jobs. 

“One of the things that we want to drive in this is workforce development,” Orehek said. “We want to leave something that’s not only a project that’ll last 30 years but provide the training and experience for community members to either start their own energy companies or become contractors in the clean energy workforce.”

The resilience hub is the second such project announced by a Minnesota tribe in just recent months. The Red Lake Nation received $3.15 million from the U.S. Department of Energy’s Local Government Energy Program in late September for a behind-the-meter microgrid project at a secondary school.

The Shakopee Mdewakanton Sioux Community is also working with Minnesota Valley Electric Cooperative to build a $9 million microgrid with U.S. Department of Energy funding. The electric cooperative will install a 4 megawatt-hour energy storage system and add a 1 megawatt solar system at the reservation in suburban Minneapolis.

It’s unclear whether federal funding for such projects will continue in President-elect Trump’s second term, but for now tribal energy advocates see microgrids as a good solution to both lower energy burdens and improve reliability.   

“This is a great opportunity to create a success story in terms of leveraging cutting-edge technology, being able to help frontline communities, and for tribes and co-ops to work together,” Kwak said.

Minnesota tribe’s solar-powered resilience hub would provide cost savings, backup power to local community 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.

A year-old state law is helping to bring new voices before the Minnesota Public Utilities Commission, and advocates and officials hope its impact will grow as more organizations learn about its existence.

Since 2007, small nonprofits have been able to seek financial compensation to help pay for expert testimony they provide in utility rate cases. State lawmakers last year expanded the concept to cover a broader range of cases, including utility pilot programs, infrastructure projects, and performance measures.

“It’s really about getting voices to the table to present us with new arguments and new issues for us to consider,” said Commissioner Joe Sullivan.

Since the law took effect in May 2023, the commission has authorized $124,318 in payments to four organizations, including two groups — Community Power and Minnesota Interfaith Power & Light — that had never before requested or received compensation for expert testimony. The other recipients were the Citizens Utility Board of Minnesota and Energy CENTS Coalition, which advocates for low-income ratepayers.

Under the previous rules, some years, including 2019, 2021, and 2022, saw no payouts at all. In 2023, regulators approved $96,000 for testimony under the old program before state lawmakers expanded its scope.

“We’re glad to see broadening participation due to the change in this intervenor compensation law,” said state Sen. Nick Frentz, a Democrat from North Mankato who supported the legislation. “Our hope is that the more voices that contribute, the better the quality of the eventual PUC decisions.”   

Where the money goes

Anyone can comment on utility commission matters, but having a significant impact requires investing in staff time and experts — precious commodities unavailable to many smaller nonprofits.

The compensation process involves nonprofits submitting documentation and a sum for testimony related to a specific case. Rules require the nonprofits to have a payroll of no more than $600,000 for participation in commission proceedings and 30 full-time or fewer employees for the previous three years. The commission judges the merits of reimbursement based on six criteria that focus on whether the organization’s testimony materially impacted its decision.

Once nonprofits receive approval for compensation from the commission, the utility involved in that case pays them. The Legislature set a maximum limit on how much any utility will pay annually to intervenors, ranging from $1.25 million for Xcel Energy to $100,000 for Otter Tail Power and other smaller utilities.

Although the new law broadened the types of cases in which nonprofits could seek compensation, three of the six 2024 awards went to organizations testifying in the Xcel Energy rate case. However, the Citizens Utility Board received the largest amount for its recommendations in an integrated gas resource planning docket, an issue that would not have been eligible for compensation in the past.

Nonprofits typically use the money to offset the high costs of expert testimony or staff time related to cases where utilities usually spend millions to influence the commission’s decisions. Other intervenors often include larger nonprofits, industrial organizations, chambers of commerce, labor unions, national associations and, on occasion, cities and counties.

Frentz, who chairs the Senate’s Energy, Utilities, Environment and Climate Committee, said he thinks more organizations are out there that could provide testimony at the commission. But they must have the resources available before intervening, and believe their input will influence the Public Utilities Commission, he said.

Commissioner Sullivan said regulators have “seen a little bit more utilization” of the compensation law. The 2023 law specifically encouraged tribal participation, though no tribes have done so yet. Barriers may include a lack of familiarity with the commission or the need for a local budget to hire experts or allocate staff time to complex cases, Sullivan said.

‘A difficult needle to thread’

Solar entrepreneur and tribal clean energy advocate Robert Blake said he was not surprised to hear tribal nations had not participated in the expanded intervenor law. He said many are administratively stretched thin and focused on taking advantage of federal and state opportunities to fund clean energy projects on reservations.

Also, many of the issues that come before the commission involve large utilities that do not serve reservations, which often also get electricity from locally owned cooperatives, Blake said.

Community Power and Minnesota Interfaith Power & Light each received $17,984 after each requested nearly $26,000. Community Power employee Alice Madden said the money paid for expert witnesses who “cost hundreds of dollars per hour” but did not cover the staff time of either organization, which involved door-knocking and collecting more than 1,000 ratepayers’ comments.

“The intervenor compensation works for covering narrow costs but does not help people intervene and front the costs of that,” Madden said. “It accomplished allowing us to have extra witnesses, but it does not cover the full cost of intervening, nor of organizing to get community voices to the table.”

Minnesota Interfaith Power & Light Executive Director Julia Nerbonne was disappointed that the commission only partially reimbursed what it had requested, but she decided against appealing the decision. The organization has been involved in several dockets outside of rate cases and may someday ask for compensation for expert witnesses.

“I feel like the PUC has a difficult needle to thread, and I appreciate that they did that (provided compensation),” Nerbonne said. “I want to say thumbs up for expanding it.”

In its order, the commission granted compensation to the two organizations because they “made a unique contribution to the record, promoting public policies and representing interests of people of color and low-wealth households that would not otherwise have been adequately represented. The evidence and arguments they presented would not otherwise have been part of the record and were an important factor in producing a fair decision.”

Citizens Utility Board Executive Director Annie Levenson-Falk said the compensation received in 2024 was the amount it would have been for similar testimony in the past. The commission granted it compensation in two dockets, the largest of which was $41,385, for promoting a requirement that natural gas providers file periodic integrated resource plans that the commission has required from electric companies. The money paid for some of the expense of outside experts to research and testify on behalf of the organization.

In an order approving payment in the natural gas case, the commission said it had adopted the Citizens Utility Board’s recommendation that the state’s three natural gas utilities develop integrated resource plans. The commission determined how much each utility would pay the board, with Xcel providing nearly $30,000.

The prospect of compensation does not impact the Citizens Utility Board’s decisions on whether to intervene in commission matters. “It is something we keep in mind at the end if the PUC (Public Utilities Commission) has adopted a position we advocated,” Levenson-Falk said.

Levenson-Falk said she was unsurprised that organizations new to regulatory proceedings have yet to often participate in hearings or ask for reimbursements. “I think it is more difficult for a group that does not have utility regulatory professionals,” she said. “We have a team of folks who do this kind of work, but if it’s your first time coming to the PUC, it’s a challenging statute to take advantage of. It’s not easy.”

Energy CENTS Coalition received $36,785, the second largest disbursement under the new law, for testimony in the Xcel rate case that led the commission to adopt a “low-income, low-usage” discount. The organization provided “an important factor in producing a fair decision and would not otherwise have been part of the record,” the commission said in its order.

Executive Director George Shardlow wants to expand the organization’s involvement beyond rate cases to other issues. “It’s very helpful for a small consumer advocacy organization to have this added support to play in dockets over and above rate cases where consumer advocates need to show up,” he said.

The commission is required to issue a report on the intervenor law to the Legislature by July 2025.

Hiring experts to testify in utility cases is expensive, but a Minnesota law is helping more groups participate 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.

More Minnesota cities are turning to utility customers to fund climate and sustainability projects.

The Twin Cities suburb of Eagan is among the latest municipalities to begin collecting what’s known as a “franchise fee” from gas and electric companies in exchange for allowing pipelines, power lines and other infrastructure in public rights-of-way. The charges are typically passed on to customers in the form of a small monthly line item on their utility bills.

As is the case with a growing number of cities, Eagan leaders last year decided to dedicate funds from its franchise fees toward its climate and sustainability efforts. It hired its first sustainability coordinator and is drafting a climate action plan that will be implemented in part with the expected $1.5 million in annual franchise fee revenue.

“It’s hard to launch a sustainability initiative without a way to sustain it,” said Gillian Catano, the city’s sustainability coordinator. “This helps us with long-term planning and allows us to work on projects supporting our operations and to support projects in the community.”

Use of franchise fees growing

Cities have collected franchise fees from public utilities for decades, but today the charges are emerging as a potentially important revenue source to help budget-strapped local governments make progress toward climate targets. In the Twin Cities, Minneapolis has long used the fees to fund sustainability work, and St. Paul is considering a plan to do the same. Other examples include the suburbs of Edina and Hopkins.

“We’ve seen a growing number of cities, across Minnesota and nationally, leveraging utility franchise fees as a tool to fund climate action and sustainability efforts,” said Julia Eagles, associate director of utility and regulatory strategy for the Institute for Market Transformation, a national nonprofit that promotes public policy to reduce building emissions. “It reflects a broader shift towards cities seeking stable, locally controlled funding sources for urgent climate priorities.”

A National Renewable Energy Laboratory research paper in 2021 found over 3,600 municipalities collect franchise fees from their utilities and 13% use part of that money for clean energy-related projects. The work being funded by franchise fees include energy efficiency programs, municipal fleet electrification, solar panel installations, and other clean energy-related investments. 

Abby Finis, a consultant who works with local governments on climate action, said in the past, many cities added the fees into the general fund to pay for various city services. What’s different now, she said, is that more communities are tying them to sustainability staff and projects.

“The franchise fee is something that’s already set up, and you can increase it a little bit without hurting people’s wallets too much,” Finis said.

However, Finis cautioned that the money doesn’t “get anywhere near the amount needed to reach our goals.”

Sometimes cities are maximizing those dollars by using them to leverage additional funds, such as through the federal Inflation Reduction Act or Minnesota’s ECO (Energy Conservation and Optimization) Act, she said.

How other cities are using funds

Minneapolis uses its franchise fees to fund a unique partnership between the city and utilities Xcel Energy and CenterPoint Energy. The National Renewable Energy Laboratory’s research highlighted the partnership, which was intended to accelerate progress toward the city’s climate goals but has faced questions about its effectiveness. The city increased its franchise fee in 2023, a per-household increase of about $12 per year, according to Patrick Hanlon, the city’s deputy coordinator for sustainability. 

“It was a pretty minimal increase for residential customers,” Hanlon said. Projects funded partly by franchise fees have saved city residents more than $150 million annually in energy costs and helped weatherize more than 5,000 low-income units, he added. 

Hanlon is also mayor of the nearby suburb of Hopkins, which recently started using its franchise fees to pay for solar, e-bike and electric vehicle charging initiatives.

St. Paul Mayor Melvin Carter recently proposed charging residential franchise fees to fund weatherization, tree planting, and pay the salary of a new climate action coordinator.

In the past, St. Paul’s climate action budget has come from general funds and grants. 

“This would be the first uniquely dedicated funding for the city’s broad portfolio of climate work,” said Russ Stark, the city’s chief resilience officer.

Edina began using franchise fees for clean energy projects in 2015. Today, according to sustainability manager Marisa Bayer, the suburb commits about $950,000 annually from franchise fees for its sustainability programs, most of which is invested in city operations to improve efficiency, add renewable energy, and electrify municipal buildings and transportation. The money also funds a sustainable building ordinance and other policy measures.

“The great thing is that because we have this dedicated funding source, we can move forward with projects, either identified in our capital improvement plans or supported by our community,” Bayer said. “We don’t have to go to council every year or rely solely on grants to help fund this work.”

Correction: Edina commits $950,000 annually from its franchise fees for sustainability programs. An earlier version of this story mischaracterized the number.

Minnesota cities tap utility fees to help fund local clean energy and climate action 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.

Correction: An earlier version of this story did not include that the advocacy groups’ modeling included one new natural gas plant. The story has been updated.

Xcel Energy’s latest long-range plan for meeting electricity demand in Minnesota includes six new natural gas peaker plants that critics warn could be obsolete before customers are done paying for them.

Comments filed last month by clean energy advocates and the state attorney general’s office push back on the utility’s plan to build a fleet of small fossil fuel plants as it otherwise ramps up clean energy investments. The facilities would operate sparingly, just a few hours at a time on days when the grid is strained and wind, solar and other clean power can’t keep up with demand.

More economical options exist, though, according to a coalition of clean energy groups that hired experts to model alternatives. The study commissioned by the groups concluded Xcel could save ratepayers as much as $3.5 billion by opting for a single new gas plant, and relying more on existing plants, energy storage, efficiency and demand response, and buying surplus power on the regional power grid.

The clean energy groups include Fresh Energy, which publishes the Energy News Network (Fresh Energy’s leadership and policy staff do not have access to ENN’s editorial process.)

The debate is over the utility’s latest integrated resource plan — the first submitted to state regulators since Minnesota Gov. Tim Walz signed legislation last year requiring electric utilities to use 100% clean energy by 2040. Xcel Energy supported the legislation and has proposed various scenarios for achieving the target, but disagreements remain among stakeholders about how to get there, particularly when it comes to cost and equity issues.

Different approaches to modeling

Allen Gleckner, executive lead for policy and programs at Fresh Energy, said Xcel’s gas plant proposal is similar to one in its last integrated resource plan that asked regulators to approve two new peaker plants that would provide as much as 800 megawatts of electricity. Xcel eventually agreed to an open, fuel-neutral bidding process allowing clean energy companies to propose alternatives. That process is still underway, with an administrative law judge expected to make recommendations.

The clean energy groups’ consultants used the same software program as Xcel to arrive at a plan to add a new 374 megawatt gas plant, 3,800-4,800 megawatts of wind, 400 megawatts of solar, and 800 to 1,200 megawatts of energy storage resources by 2030. Extending contracts at existing peaker plants could add 970 megawatts, and energy conservation initiatives could reduce use during high demand times. 

Gleckner said Xcel has taken an exceptionally conservative approach by mostly creating scenarios that did not consider electricity being available from neighboring systems or the MISO regional transmission grid. Gleckner said Xcel does not and has never operated as an island, with MISO delivering power to its customers through a shared resource pool.

“Xcel is using a sort of fiction of modeling because the reality is we’re part of a regional grid,” he said. 

The result is a plan to “build a bunch of new resources that we know are either not compatible with our state laws or are going to be costly and likely to retire early,” he said.

Amelia Vohs, climate program director for the Minnesota Center for Environmental Advocacy, praised Xcel for not asking regulators to extend the life of existing fossil plants, unlike its counterparts in other states. Unlike previous long-range plans, Xcel’s latest imagines a future in which large gas and coal power plants are not the backbone of the system. 

What that grid will look like remains challenging, Vohs said. Adding to the challenge is rising power demand from data centers, manufacturing, and the electrification of buildings and transportation. Even so, Vohs believes clean energy is ready for a leading role.

“It’s a much better solution that’s flexible in this time of uncertainty without making this big commitment to gas resources for the next 40 years,” Vohs said.

Patty O’Keefe, senior field strategist for the Minnesota Sierra Club, said proposed combustion turbine peaker plants pose “significant environmental and public health risks” because they potentially emit more carbon and nitrous oxide than larger, more common combined cycle gas plants. They also tend to be built in communities already suffering higher pollution levels.

The Sierra Club would like Xcel to focus more on energy efficiency than electricity generation in its planning. Efficiency reduces demand and makes “the transition to clean energy smoother and more cost-effective,” O’Keefe said.

Managing risk

Meanwhile, the office of Minnesota Attorney General Keith Ellison has also weighed in, warning that investments made now may become obsolete “stranded assets,” meaning the plants may become uneconomical or forced to retire before they have delivered projected benefits to customers. 

Xcel has acknowledged the risk of stranded assets generally in Securities and Exchange Commission filings, though not specifically in relation to its proposed gas peaker plants.

Utilities are incentivized to build power generation because investors earn a return on capital investment. The attorney general argues that if plants become obsolete or transition to other forms of energy, such as hydrogen, Xcel ratepayers should not have to pay for retrofits and other investments it might have to make to reduce emissions.

In its filings to state regulators, Xcel said it is concerned about having enough firm dispatchable power to meet rising demand quickly during certain times of the day. By 2030, the company will have ended its use of coal for energy generation after closing four coal-burning facilities this decade. The proposal suggests Xcel may need to add even more peaker plants between 2030 and 2040.

Xcel spokesperson Kevin Coss said the company will be “adding a significant amount of wind and solar power to our energy mix” and complementing that generation “with always-available generation — power we can supply any time it’s needed — to reinforce the reliability of the grid.”

Coss said Xcel identifies generation sources in a technology-neutral way so it can decide not to use natural gas combustion plants in the future. The current integrated resource plan calls for fewer firm dispatchable resources than the 2019 version, he said.

The conservative modeling “avoids overreliance on the energy market, which could expose our customers to excessive risk,” Coss said.

Residents, businesses and organizations have until Oct. 4 to send comments on the integrated resource plan to the Public Utilities Commission. The commission is expected to make a decision on the plan in February 2025. 

Minnesota advocates say their alternative to Xcel’s plan for new gas plants could save customers up to $3.5 billion 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 clean energy and economic development officials say a Canadian solar manufacturer’s planned expansion in the state shows the impact of federal climate incentives for domestic production. 

Pete Wyckoff, assistant commissioner of federal and state initiatives for the Minnesota Department of Commerce, said Heliene’s announcement that it plans to onshore solar cell manufacturing in partnership with an Indian supplier shows the Inflation Reduction Act “is doing what it is designed to do, which is to provide incentives to encourage every step in the solar manufacturing process to occur domestically.” 

In late July, Heliene said it had reached a joint venture agreement with Premier Energies, India’s second-largest solar cell manufacturing company, to build a solar cell manufacturing facility somewhere in the Twin Cities. Heliene also has a plant in northern Minnesota, where it assembles solar panel modules using imported cells from Premier Energies.

Several U.S. factories assemble solar panel modules — think of the rectangular boxes you’d see installed on a rooftop. Almost all of these domestic manufacturers, though, depend on imported solar cells — the half-foot square slices of silicon that actually do the work of converting sunlight to electricity.  

The Inflation Reduction Act prompted a flurry of announcements related to domestic solar cell production, but its viability here remains unclear, Renewable Energy World recently reported. Multiple companies have already retracted plans for U.S. solar cell factories, citing market challenges.

Meeting installer demands

Heliene CEO Martin Pochtaruk said its planned solar cell plant is meant to meet clients’ demand for modules with higher levels of domestic content, which allow project developers to claim more lucrative incentives. After solar owners receive a standard 30% tax credit for projects, they can add another 10% by using modules with equipment made in the United States.

“Strong solar cell manufacturing offers solar developers a higher percentage of U.S.-made domestic content components for their projects, reduces reliance on imports, and releases stress on our supply chain,” Pochtaruk said.

He said working with Premier on establishing an American beachhead that could employ more than 200 workers makes sense because the Inflation Reduction Act rewards solar panels made primarily with parts made in the U.S. solar cells.

Solar developers must use panels with a domestic content of 40% or more for the bonus, and the threshold will increase to 55% in 2026. 

In August, Heliene agreed to a multi-year contract with NorSun to supply low-carbon wafers — one of the building blocks of solar cells — for all the company’s solar panels starting in 2026. 

Heliene has also announced a partnership with UGE, a community and commercial solar and battery storage developer, to provide panels that meet the requirements of the Domestic Content Investment Tax Credit (ITC) Bonus. 

Heliene said in a press release that it would manage construction, finances, supply chain logistics, regulatory oversight, and human resources. Premier will provide cell technology engineering, manufacturing expertise, supply-side agreements, and raw material vendor relationships.  

Pochtaruk said Heliene’s commitment to buy material from Premier Energies and NorSun was instrumental in their ability to finance the new factories. He asked both to try to open in 2026 when the content bonus requires more American-made content.

Jeremy Kalin, a Minneapolis attorney who works with several solar developers, said his clients are seeking panel suppliers with enough content to take the additional 10% tax credit. Manufacturers must provide a guarantee that the panels reach the threshold of having at least 55% of the panels’ components American-made. 

“Once they meet that requirement, they will see a flood of business,” Kalin said.  

Could Minnesota be a solar manufacturing center?

Minnesota Solar Energy Industries Association business development and communications director Abbi Morgan said the company’s presence “is huge and something we’re excited about because Minnesota is often overlooked when it comes to clean energy.”

So far, though, Heliene’s Minnesota operations have yet to attract other solar manufacturers. Morgan said one of the association’s members, a German firm, opened a factory in Arizona. At least among the association’s more than 170 members, plenty have expressed interest in buying panels from Heliene.

“There are a lot of members who ask about Heliene, but we’ve heard they have a long waiting list even though they expanded their factory in Mountain Iron,” Morgan said.

After securing a $3.5 million state loan package in 2018, Heliene began manufacturing and assembling panels in a once-shuttered solar module plant in Mountain Iron. The former plant, Silicon Energy, failed despite state investments of millions of dollars.

The plant is in a business park created to attract green energy companies across the street from a taconite mine. Two years ago, the company spent $21 million to triple the production space through an addition to the plant. Heliene spent $9.5 million to pay for the expansion and received most of the rest through state loans and a county grant.

Now, the company has shifted attention to adding capacity in central Minnesota, where it will begin developing two solar module manufacturing lines in an existing 227,000-square-foot warehouse in Rogers, a burgeoning exurb northwest of Minneapolis.

Before preparing the warehouse for solar production, Heliene is waiting to hear whether the project will receive money from the Minnesota Investment Fund (MIF) and Job Creation Fund (JCF). State officials were expected to make an announcement in September.

Rogers Community Development Director Brett Angell said Heliene will fit into the city’s growing reputation as a hub for sustainable enterprises. The company plans to employ at least 180 people and spend $16 million on building improvements and equipment.

“Additionally, (Heliene) would continue to add to the growing segment of sustainable manufacturers within the community as the city currently is home to multiple plastic recycling companies,” Angell said.

Heliene has not selected a site for the solar cell manufacturing plant or provided details on how much investment and employment it will create. Pochtaruk said the building will be significantly larger than the solar module plant.

Federal incentives spur solar panel company to try onshoring its supply chain in Minnesota 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 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.

Construction is underway in St. Paul, Minnesota, on a major affordable housing development that will combine solar, geothermal and all-electric appliances to create one of the region’s largest net-zero communities.

Twin Cities Habitat for Humanity broke ground in June on a four-block, 147-unit project on the site of a former golf course that’s being redeveloped by the city and its port authority, which made the decision to forgo gas hookups. 

Affordable housing and Habitat for Humanity builds in particular have become a front line in the fight over the future of gas. The organization has faced criticism in other communities for accepting fossil fuel industry money and partnering with utilities on “net-zero” homes that include gas appliances. It’s also built several all-electric projects using advanced sustainable construction methods and materials.

The scale of the Twin Cities project is what makes it exciting, according to St. Paul’s chief resilience officer Russ Stark. 

“We’ve had plenty of motivated folks build their own all-electric homes, but they’re one-offs,” he said. “There haven’t been many, if any, at scale.”

Stark added that the project, known as The Heights, was made possible by the federal Inflation Reduction Act. 

“I think it’s fair to say that those pieces couldn’t have all come together without either a much bigger public investment or the Inflation Reduction Act, which ended up being that big public investment,” he said.

A vision emerges

Port Authority President and CEO Todd Hurley said his organization bought the property in 2019 from the Steamfitters Pipefitters Local 455, which maintained it as a golf course until 2017. When no private buyers expressed interest in the property, the Port Authority bought it for $10 million.

Hurley said the Port Authority saw potential for light industrial development and had the experience necessary to deal with mercury pollution from a fungicide the golf course staff sprayed to kill weeds.

“We are a land developer, a brownfield land developer, and one of our missions is to add jobs and tax base around the creation of light industrial jobs,” Hurley said.

The Port Authority worked with the city’s planning department on a master plan that included housing, and it solicited developers to build a mix of market-rate, affordable and low-income units. The housing parcels were eventually sold for $20 million to a private developer, Sherman Associates, which partnered with Habitat and JO Companies, a Black-owned affordable and multi-family housing developer.

“Early on, we identified a very high goal of (becoming) a net zero community,” Hurley said. “Everything we have been working on has been steering towards getting to net zero.”

Twin Cities Habitat President and former St. Paul mayor Chris Coleman said the project met his organization’s strategic plan, which calls for building bigger developments instead of its traditional practice of infilling smaller lots with single-family homes and duplexes. The project will be the largest the organization has ever built in the Twin Cities.

Coleman said the Heights offered an opportunity to fill a need in one of St. Paul’s most diverse and economically challenged neighborhoods and “be part of the biggest investment in the East Side in over 100 years.”

The requirement for all-electric homes merged with Habitat’s goal of constructing more efficient and sustainable homes to drive down utility costs for homeowners, he said. Habitat built solar-ready homes and sees the solar shingles on its homes in The Heights as a potential avenue to producing onsite clean energy.

Zeroing in on net zero

Mike Robertson, a Habitat program manager working on the project, said the organization worked with teams from the Minneapolis-based Center for Energy and Environment on energy modeling.

“The Heights is the first time that we’ve dived into doing an all-electric at scale,” Roberston said. “We have confidence that these houses will perform how they were modeled.”

Habitat plans to build the development to meet the Zero Energy Ready Home Program standards developed by the U.S. Department of Energy. Habitat will use Xcel Energy’s utility rebate and efficiency programs to achieve the highest efficiency and go above and beyond Habitat’s typical home standards.

The improved construction only adds a few thousand dollars to the overall costs and unlocks federal government incentives to help pay for upgrades, he said.

The nonprofit will receive free or reduced-cost products from Andersen Windows & Doors and other manufacturers. GAF Energy LLC, a solar roofing company, will donate solar shingles for over 40 homes and roofing materials. On-site solar will help bring down energy bills for homeowners, he said.

Chad Dipman, Habitat land development director, said the solar shingles should cover between half and 60% of the electricity the homes need. Habitat plans to use Xcel Energy incentive programs to help pay for additional solar shingles needed beyond those donated. 

Habitat will install electric resistance heating technology into air handlers to serve as backup heat for extremely cold days. Dipman said that the air source heat pumps will also provide air conditioning, a feature not available in most Habitat properties in Minnesota.  

Phil Anderson, new homes manager at the Center for Energy and Environment, has worked with Habitat on the project. He said the key to reducing the cost of heating and cooling electric homes is a well-insulated, tight envelope and high-performance windows. Habitat will build on its experience with constructing tight homes over the past decade, he said.

“Overall, the houses that we’ve been part of over the last almost ten years have been very tight homes,” Anderson said. “There’s just not a lot of air escaping.”

Habitat’s national office selected The Heights as this year’s Jimmy & Rosalynn Carter Work Project, named after the former president and his wife, two of Habitat’s most famous supporters. The work project begins September 29^th and will receive as visitors Garth Brooks and Trisha Yearwood, who now host the Carters’ program.

Robertson said thousands of volunteers from around the country and the world will help put up the homes. The Heights project “raises a lot of awareness for Habitat and specifically for this development and the decarbonization efforts that we’re putting into it,” he said.

The Heights’s two other housing developers continue raising capital for their projects and hope to break ground by next summer. Habitat believes the project will meet its 2030 completion deadline.

A St. Paul, Minnesota Habitat for Humanity project will offer affordable housing without fossil fuels 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.

The small southeastern Minnesota city of La Crescent receives just a handful of permit applications each year to install solar panels on homes.

Despite the small volume, it’s still important to city sustainability coordinator Jason Ludwigson that it’s a smooth process for homeowners and installers.

That’s why the city of 5,000 recently became one of the first in the state to start using a software program designed to streamline local solar permitting.

Solar Automated Permitting Plus, or SolarAPP+, was developed by the National Renewable Energy Laboratory (NREL) in collaboration with the solar industry, code organizations, local governments, and the building safety community. Since its release in 2018, SolarAPP+ has been used by more than 160 cities and counties to automate much of the permitting process for smaller solar installations.

In La Crescent, an application that might have taken a few days for a city employee to review can now be approved online in minutes for projects that meet criteria. That “will save (time) for both the contractor and the city,” Ludwigson said. “It makes it faster for our building and zoning department.”  

Minnesota lawmakers want to encourage more communities to join La Crescent in adopting the software. This year, the Legislature budgeted $2 million for the Commerce Department to deliver programs and training to local agencies, contractors, inspectors and others involved in solar permitting.

The state’s solar industry association supports use of the software, in part for its potential to standardize a process that can right now vary significantly from city to city. Making it easier to permit installations could save companies time, potentially lowering costs and helping to expand rooftop solar in the state, which will need many megawatts more clean energy to reach its climate goals.

Getting permits for solar projects in Minnesota can take days or weeks and cost as much as $1,000. Typically, solar installers in the state apply electronically or in person for separate building, local electrical and utility interconnection permits. After receiving approvals for all three applications — and any other that are required — they start building projects that, once completed, are reviewed onsite by building and electrical inspectors.

Installers using the software receive automated approvals if they accurately complete forms for their building and electrical permits and, if required, fire and structural permits. Any errors are flagged and sent back to the installer for corrections. The app integrates with existing permitting software programs used by government agencies, according to NREL.

California cities have been the biggest adopters so far, but the app is beginning to catch on in Minnesota, Wisconsin and Iowa. By the end of 2023, the NREL reported that the free software had been used nationally on 32,800 projects, saving 33,000 hours of permitting staff time. Installers pay a $25 administrative fee and the community’s permitting fee.

State Rep. Patty Acomb, who chairs the Climate and Energy Finance and Policy committee, said she and other lawmakers want to provide state grants so cities can learn how to use the software and eventually create a consistent permitting process across the state. “The intention is to make (permitting) easy and predictable,” she said.

Lissa Pawlisch, director of the Energy Development Section at the state Department of Commerce, said the department is developing a program to reach out to communities interested in SolarAPP+ and assist them in incorporating it into existing permitting software. She also believes the app could play a role in helping move installations through the new federally funded Solar for All program that will serve low income households. 

Great Plains Institute’s Brian Ross said that Solar for All requires a consistent approach to permitting, and that one way to achieve that is with the SolarApp+ software. The app would give a “jurisdictional consistency” to applications from low income solar customers and “to make sure there are not barriers in the way.” 

Despite its promise the app will not work in every situation. It only incorporates local versions of electrical permits and not the state permit, which many communities use. “If the local government relies on the state permitting process (for instance, Minneapolis), then I don’t think there is any advantage to using SolarAPP because the state electric permitting process is already effectively an ‘automatic issue,'” he said.

Donna Pickard of TruNorth Solar has spent decades filing solar permits with dozens of municipalities. She said installers need building, electrical and interconnection permits and approvals before projects begin, often taking over a month.

Pickard wonders if SolarAPP+ will interest Minnesota communities because many already have established permitting systems to manage solar projects. However, having dealt with many different permitting structures, Pickard said she “likes the idea of standardization because it would make things easier.”

Another challenge is that the software can’t evaluate permits for projects on flat or metal roofs in the Midwest. Jeff Cook, solar analysis subprogram manager at the NREL Strategic Energy Analysis Center in Colorado, said the software covers about 80% of eligible solar installations but the number declines in the Midwest due to “high snow load and metal roof penetration.”

Pawlisch said outreach and grants for SolarApp+ would likely start next year. The start date is also unclear for Solar for All as she continues to meet with federal and state officials to work out the details.

Software aims to help local governments standardize, streamline solar permitting  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.

The “solar-coaster” is about to get a little smoother for Minnesota solar installers.

State lawmakers this spring extended funding for a rooftop solar rebate program through 2035, bucking a trend of two-year renewals that caused uncertainty for installers every couple of years.

Solar industry leaders say the additional financial certainty will help companies invest in longer-term marketing and outreach, particularly for reaching lower-income customers.

Since 2014, Solar Rewards has helped more than 8,000 residential and small business customers pay for solar installations in Xcel Energy’s territory. The program is managed by the utility, but the legislature controls its budget, which has ranged between $5 million and $15 million annually. The money comes from yearly fees the state collects from Xcel in return for allowing it to store nuclear waste at two power plants.  

Logan O’Grady, executive director of the Minnesota Solar Energy Industries Association, said the extension represents a compromise — and a victory — after failed attempts to convince lawmakers to increase the program’s funding. Funding has rarely stayed the same two years in a row. Installers have struggled with planning because they did not know if the rebates would be renewed. 

“It creates the inability to plan for what you’ll be getting year to year,” O’Grady said. “You get through a two-year cycle, and then there might be nothing.”

Uncertainty about the rebate’s future has been challenging to communicate to customers. O’Grady said installers could not make promises in some years because they did not know if the program would continue. Now, even if funding runs out for the year, companies will be able to confidently tell customers that it will be available next year.

He said the extension also will help installers work with low- and moderate-income Solar Rewards customers. In 2023, the Legislature significantly modified Solar Rewards by allocating half the money for low-income participants while increasing subsidies for those projects.

Bobby King, Minnesota director of Solar United Neighbors, said connecting to organizations working with low-income households has taken a few years. The extension gives him the confidence to continue the work.

“You need the program to be consistent if you’re going to continue to grow a program to help folks get low-income solar,” he said. “We can be confident about bringing more resources to staff a (low-income) program.”

All Energy Solar CEO Michael Allen said the Solar Rewards extension “provides you a little bit more confidence” but “still doesn’t take away the real costs of having to market and to sell, design and build projects for this market segment.” He estimated that it can cost as much as 10 times more to recruit and sell to income-qualified customers because of the relationship building, education, financing and sometimes structural issues that need to be addressed.

The Solar Rewards budget over the 10-year extension will be a bit more than half of what the program received from 2014 to 2025. He worries the subsidies will slow rooftop solar, which needs to expand to meet the state’s climate goal of net zero emissions by 2050.

Martin Morud, CEO and owner of TruNorth Solar, said he prefers stable funding that allows his business time to develop relationships with community organizations that work with income-qualified customers. He said TruNorth Solar has worked on income-qualified projects involving food shelves and transitional and low-income housing through Solar Rewards and other programs. 

Cooperative Energy Futures had begun using Solar Rewards for residential projects over the past two years after primarily building community solar projects with many low- and moderate-income subscribers.

Pouya Najmaie, its policy and regulatory director, said the nonprofit recently hired an employee to focus on income-qualified projects. The Solar Rewards extension will help the nonprofit maintain that position and potentially add another if demand grows.

The Solar Rewards bill was part of a 1,430-page omnibus bill that Gov. Tim Walz signed into law in late May. Rep. Patty Acomb, House of Representatives Climate and Energy Finance and Policy Committee Chair, said lawmakers supporting Solar Rewards worried that the program could have ended in 2025 if the Democratic-dominated Legislature changed hands.

“Fifty million dollars, or $5 million a year, is better than zero,” she said. “I think that having programs like this is a signal to the industry that there is support from the state.”

Minnesota solar rebate extension gives installers longer runway to reach lower-income 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.

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.

The operators of the decades-old energy systems that heat and cool buildings in downtown Minneapolis and St. Paul have ambitious plans underway to reduce emissions.

The mostly hidden networks of insulated pipes connected to centralized heating and cooling equipment are known as district energy systems. They’ve long been championed as an energy efficient way to heat and cool campuses or downtowns, especially in cooler climates.

Many, though, are connected to fossil fuel facilities, and the systems’ high efficiency alone won’t be enough to help schools, cities, and companies meet their goals of eliminating greenhouse gas emissions by midcentury or sooner. Climate pledges by these institutional customers are now driving efforts to repower district energy systems with clean energy.

University district energy systems began initiatives to reduce emissions years ago and “now in the last five years we’re seeing a lot of emphasis on this from cities and towns,” said Rob Thornton, president and CEO of the International District Energy Association. 

In Minneapolis, Cordia Energy, the private company that operates the largest downtown district energy system, is replacing natural gas boilers with electric models. And in downtown St. Paul, officials are seeking federal funding for a project to recover heat from a wastewater treatment plant and reduce energy use for a system currently powered by electricity and biomass.

“We’re doing decarbonization at the rate that our customer base is asking for and we can economically withstand,” said Jacob Graff, Cordia Energy’s north region president. Customers connected to its downtown Minneapolis system range from stadiums and high rises to apartments and medical facilities.

From ancient Rome to skyscrapers

The concept of district heating has been around for centuries, with its roots in the networks of hot water pipes built in ancient Rome. Some of the first modern steam-based systems were built in New York in the 1880s. Today, the United States has more than 700 district energy systems heating and cooling buildings in downtowns, universities, medical campuses, towns and communities.

Cordia Energy’s Minneapolis system opened in 1972 to serve the 57-story IDS Center, still the tallest building in Minneapolis. Today, the steam and chilled water system manages seven plants that heat and cool the IDS and more than 100 other buildings, including U.S. Bank Stadium, Target Center, and the convention center.

Hennepin County owns and operates a much smaller district energy system, connected to a downtown trash incinerator, that primarily serves county buildings and Minneapolis City Hall.

District Energy St. Paul began in the early 1980s after then-Mayor George Latimer hired Swedish engineer Hans Nyman to replace the aging steam system with a hot-water central heating system. Latimer wanted to create a national model of district energy and he largely succeeded. District Energy St. Paul has the largest hot water system in the country, with more than 200 buildings.

Together, the two systems serve some of the state’s biggest buildings, which have emerged as the largest source of greenhouse gas emissions in both cities. In Minneapolis, 65% of the emissions are from commercial, multifamily and industrial buildings. St. Paul’s data is similar.

Tapping clean electricity in Minneapolis

Cordia plans to reduce emissions from its Minneapolis system by 30% by 2030 before reaching net zero by 2050. Xcel Energy’s green tariff program will offset around half the electricity Cordia uses this year, and it wants to buy more credits if they become available.  

The company is replacing older engine-driven chillers with electric models at the former Dayton’s department store, where it has operations. Chillers modulate the temperature inside buildings and can be powered by electricity or natural gas. Geothermal is another potential solution being studied.

A potential geothermal project “hasn’t cleared the economic hurdles yet,” Graff said. “I think we’ll eventually get there.”

Minneapolis customers are not alone in seeking to reduce emissions from district energy systems, Graff said. San Francisco will be Cordia’s first system to decarbonize using hydropower from a dam the company owns in Yosemite National Park.

St. Paul looks to waste heat recovery

Downtown St. Paul’s district heating system is owned and operated by a company called District Energy, which recently worked with the city and the regional planning agency on a $152 million U.S. EPA grant application to tap heat from a regional wastewater plant for the city’s system. It would include a project with Xcel Energy to pay for an electric boiler and hot water storage. 

District Energy president and CEO Ken Smith said half the system already has been decarbonized through biomass, solar thermal and renewable energy credits. An analysis showed that recovering heat from the Metro Wastewater Treatment Plant, which manages 170 million gallons of water daily, could produce 60 megawatts of thermal energy, and heat pumps could lift the temperature up to the system average.

If District Energy receives the Climate Pollution Reduction Grant, the system would go live in 2028 and allow District Energy to provide 92% of energy from carbon-free or carbon-neutral sources, far ahead of its goal of net zero by 2050.

“This certainly would be able to accelerate that by 30 years,” Smith said. “From everything we’ve seen, there’s nothing like this, certainly not in the United States, and I don’t believe there’s anything like it at this scale in Canada, either.”

St. Paul Resilience Officer Russ Stark said District Energy’s emissions represent a small portion of the total greenhouse gases in the city. Still, around 50,000 tons of carbon would be eliminated annually, and that’s “very impactful,” he said.

The wastewater project would allow District Energy St. Paul to expand to more buildings, decarbonizing them in the process, Stark said. Adding clients “is not a simple process but we’ve been talking a lot about that being an exciting part of the project,” he said. “I don’t know how many major city downtowns there are where there’s an opportunity to largely decarbonize most of the downtown in the way that we can.”

Systems face unique, local challenges

A one-size-fits-all solution for decarbonizing district energy systems doesn’t exist, as most are unique based on customers and geography. Not all can be inexpensively retrofitted for electricity, and the ongoing office and commercial real estate fallout from the Covid-19 pandemic adds risk to financing projects.

Thornton, of the district energy association, said electricity pricing can escalate quickly, especially in summer, creating uncertainty in the market. New technology may require more space, different controls and significant staff training. Federal policy remains unclear about what parts of a district energy system would qualify for tax incentives, he said.

Graff ticks off many challenges in decarbonizing Cordia’s Minneapolis operations. Geothermal works well on campuses and in low-slung neighborhoods where the problem of sending steam to the 50th floor of a skyscraper does not exist, Graff said.

There’s not a simple clean power source like natural gas that has the energy density to create and push steam through a network, he said. To illustrate the point during a tour of Cordia’s downtown plant, he pointed to a pipe with a modest circumference and said the natural gas flowing through it provided the heating for much of the system.

Electrification may be a goal of heating and cooling, but offsetting it with clean power is daunting. Cordia would have to install heat pumps capable of drawing more than 400 megawatts from a clean energy source, which would be no small feat, Graff said.

Hydrogen sounds promising but has no track record yet for supplying an entire downtown district energy system, Graff said. Biomass has potential, too, but sourcing enough it to service a sprawling district energy system reliably remains difficult.

Battery storage, microgrids and other technologies could all play a role, but each brings issues ranging from cost to a lack of testing in a district energy environment, at least at the size of the downtown Minneapolis system.

“We have the economy of Minneapolis in our hands, and regional economics depend on downtown Minneapolis,” Graff said “We need a reliable infrastructure that people can count on that can be delivered economically, and it’s our responsibility to do that.”

In Twin Cities and beyond, district energy systems see pressure to cut carbon emissions 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.

The recent expansion of a groundbreaking transportation law in Minnesota means all major highway projects in the state will soon be scrutinized for their impact on climate emissions.

A year ago, the state legislature made headlines with a new law requiring the state transportation department and the Twin Cities’ regional planning agency to begin assessing whether highway expansion projects are consistent with state climate goals, including Minnesota’s aim for 20% reduction in driving by 2050.

A follow-up bill passed this spring expands the 2023 law to include all major highway projects statewide that exceed a $15 million budget in the Twin Cities or $5 million outside the metro, regardless of whether or not they would add new driving lanes. The updated legislation also established a technical advisory committee and a state fund to recommend and help pay for mitigation projects.

“It allows for some evolution of the law,” said Sam Rockwell, executive director of Move Minnesota, a nonprofit advocacy group that supported the legislation. “There’s more flexibility.”

The law requires transportation project planners to offset projected increases in greenhouse gas emissions and vehicle miles traveled to qualify for state or federal highway dollars. Those mitigation efforts might include incorporating funding for transit, bicycle or pedestrian programs or environmental restoration projects.

‘A waterfall effect’

Altogether, the law will now cover more than 12,000 miles of state trunk highways that account for more than 60% of all miles driven in the state. One high-profile project that may not have been covered under the initial law is the upcoming reconstruction of Interstate 94 between Minneapolis and St. Paul, which will now need to account for climate impacts.

The changes come as advocates and officials seek solutions to reverse the continued growth of transportation emissions, which surpassed electricity generation almost a decade ago as the state’s largest source of greenhouse gas emissions and are a major reason why Minnesota is not on track to meet its climate goals. 

A disconnect has long existed between even progressive states’ climate goals and the status quo of highway construction, which has long focused on maximizing efficiency for drivers. The new Minnesota law is an attempt to integrate climate action into state and local transportation planning, and to recognize that electric vehicles alone won’t be enough to achieve climate targets. 

Under the law, the Twin Cities’ regional planning agency, the Metropolitan Council, must include strategies for reducing greenhouse gas emissions and vehicle miles driven in its next 25-year regional plan in 2026. All metro area communities will then use that plan as the basis for their local comprehensive plans, which are due to the regional council in 2028. 

“It’s a waterfall effect here,” Rockwell said.

The Met Council’s last planning document, Thrive 2040, already outlined a focus on multimodal travel options, encouraging walking and biking options while setting a goal of decreasing vehicle miles traveled per capita by 20% by 2050, in line with the state’s official goal.

Conversations already underway

Many metro area communities are already having conversations about how to reduce dependency on driving. Abby Finis, a consultant who has helped several communities draft climate action plans, said reducing driving can bring broader benefits than simply focusing on electric vehicles.

“It offers more active lifestyles, more opportunities to incorporate nature, and has less impact on natural resources needed for electric vehicles,” she said.

Most communities focus on increasing the ability of residents to walk and bicycle for short trips by adding bike lanes, pedestrian islands and safer crosswalks, she said. Some cities see telecommuting and co-working spaces as options for reducing commutes.

But transforming the suburbs will be challenging, Finis said. Sustaining transit service often requires denser development, which continues to be politically controversial in many communities. 

“I have yet to see any community push hard on those strategies in a way that meets what is necessary to reduce [vehicle miles traveled] and adapt to climate change,” Finis said.

For example, Minnetonka, a western suburb of Minneapolis with more than 52,000 residents, boasts a considerable bicycling community. But transit ridership is low except for a modest ridership at the regional mall, one commercial development area, and park-and-ride lots, said Minnetonka’s Community Development Director Julie Wischnack.

Developed in the 1950s and 1960s, Minnetonka’s current land use is a barrier to fixed route transit. But the city is among a collection of suburbs along Interstate 494 that has been pushing for transit and other commuting options, including telework.

Another member of that commission, Bloomington, faces many of the same challenges. The city has a few dense neighborhoods near transit stops and the Mall of America, but much of the community remains single-family homes and small apartments. A recent report Bloomington commissioned on transportation found that 75% of trips by residents were more than 10 miles. 

Transit, biking, and other modes could replace trips that are less than 10 miles, said Bloomington Sustainability Coordinator Emma Struss. A recent city transportation study suggested several strategies to decrease driving, including transit-oriented development, free bus and rail passes, bike parking, subsidized e-bikes and more transit. Removing barriers to walking and biking were highlighted.

“We’re hearing more and more from residents that they want safe ways to get around the community without needing to take a car,” Struss said.

Similar challenges in larger cities

St. Paul has made changes to create denser neighborhoods, including removing parking minimums for new development and letting up-to-four-unit complexes be built in single-family neighborhoods. The biggest challenge continues to be the spread-out nature of the region, which forces people to drive to suburban jobs and big-box merchants. 

“The fundamental nature of those trips is hard to serve with anything but driving in the car,” said Russ Stark, St. Paul’s chief resilience officer.

Minneapolis has focused less on vehicle miles and more on “mode shift,” or decreasing trips, said the city’s Public Works Director Tim Sexton. The goal is to replace three of five trips by car with walking, biking, or other modes. A city transportation action plan features more than 100 strategies, including creating around 60 mobility hubs where residents can rent e-bikes, scooters or electric vehicles, or take transit.

Patrick Hanlon, the city’s deputy commissioner of sustainability, healthy homes and the environment, pointed out that Minneapolis has one of the country’s best-developed bike networks, which continues to grow. The city’s comprehensive plan drew national attention for removing barriers preventing denser development, which typically leads to fewer transportation emissions. Several transportation corridors now feature bus rapid transit lines.

What Finis described as a “patchwork” of conversations around developments like these are expected to become more comprehensive as the state law’s planning requirements take effect in the coming years.

The legislation has also made Minnesota a national inspiration for other states looking to make progressive changes to highway planning, Rockwell said.

“We know of a number of other states that are looking at trying to replicate parts of this (law), which is great,” he said. “We’ve been on the phone with folks from New York, Michigan, Illinois and Maryland who are trying to bring some pieces of this into their legislative sessions and their legal framework. That’s exciting.”

Minnesota highway projects will need to consider climate impacts in planning 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.