No one knows what a gas utility will look like a quarter-century from now, as many states near deadlines for their 2050 climate goals. 

In Minnesota, though, state regulators will soon expect utilities to at least have a vision for the next decade.

The Minnesota Public Utilities Commission voted last month to require long-range resource planning from the state’s three largest gas utilities.

Similar to a process that’s long been used for electric utilities, gas utilities will need to periodically submit plans showing load forecasts under various scenarios and how they intend to meet that demand in a way that’s safe, reliable, and affordable — and in line with the state’s policies.

“An IRP (integrated resource plan), just like it happens on the electric side, informs the level and type of cost-effectiveness and a framework for utility investment,” Commission Chair Katie Sieben said. “The hope is that by having the state’s three largest natural gas utilities file IRPs, it will provide transparency and more intentional decision-making in the years to come.”

The decision stemmed from a yearlong investigation by the commission into fallout from a February 2021 cold snap that caused extreme gas price spikes across much of the country. 

Utilities in a handful of other states also file gas resource plans, including Oregon, which has had a similar process since 1989. In Minnesota, utilities typically submit annual plans for the upcoming winter season and offer data on changes in natural gas consumption. Investments in gas infrastructure are often discussed in rate cases.

After a six-hour meeting that featured more than 100 decision options, the PUC began drawing parameters for the data and information it will seek from Xcel Energy, CenterPoint Energy and Minnesota Energy Resources Corp. The plans will include projections for low, medium and high natural gas demand and pricing. They will also model energy efficiency initiatives as a potential resource. 

“I think that’s important in the long term for helping the gas sector meet our overall (state) decarbonization goals,” Sieben said.

Looking to a net-zero future

The Center for Energy and Environment worked with Xcel Energy, the Department of Commerce and the Laborers’ International Union of North America on an approach to natural gas planning that heavily influenced the commission.

The center’s director of policy, Audrey Partridge, said asking for natural gas utilities to look out to 2050 remains difficult “because the quality of the data falls apart.” A 10-year time frame “is significantly longer than any planning on the gas system we’ve done to date.”

Though the plans don’t go as far as some clean energy and consumer advocates wanted to see, they’re hopeful the process, along with recent state laws encouraging gas utilities to diversify and decarbonize their businesses, will help make progress on state climate goals and avoid stranding customers with the cost of infrastructure that may not be needed in the future. 

Annie Levenson-Falk, executive director of ratepayers’ advocacy group Citizens Utility Board, said the plans are “essential, given, particularly given all of the transition and uncertainty in the gas industry. It’s necessary, and we’re very happy to see this move forward.”

The natural gas market is in a state of flux, Levenson-Falk said. The growth of electric air source heat pumps is expected to cut into gas demand in the coming years. So will federal and state incentives encouraging geothermal and district heating systems.

Minnesota’s “future of heat” could eventually lead to natural gas being used only for the coldest days, Levenson-Falk said. As more customers switch to electric heating sources, there’s a risk that the cost of maintaining the natural gas system would “fall on households that could least afford it.”

The resource plans will help regulators see the “big picture” and how utilities are planning for it, she said. When gas utilities make investments, they often consider a 40-year timeline. But if gas sales decline, ratepayers will still have to pay for that infrastructure, Levenson-Falk said.

Clean energy and consumer organizations said natural gas utilities should consider a 2050 end-year because that’s Minnesota’s goal for carbon neutrality. 

“We want the commission to be able to consider if they’re (gas utilities) putting in a 40 year pipe today, what will the utilization look like in 15 to 20 years?” Levenson-Falk said. “But they didn’t go that far.”

‘Basically making it up’

The natural gas sector is much more volatile than the electricity marketplace, with “so many unknowns,” Sieben said. That led the commission not to require utilities to propose a “net zero” future advocated by clean energy organizations. Commissioners also expressed concerns that net zero may impact the system’s reliability.

The commission decided utilities will need to consider externalities such as the societal cost of carbon pollution in the planning process. 

“I think that is going to create a sea change in terms of opening up more opportunities for cleaner resources and reducing emissions on the gas side,” Partridge said.

Marketing Manager Kevin Pranis of the Laborers District Council of Minnesota & North Dakota said his union eventually supported the commission’s scope for gas planning. But he warned that no “magic” in planning would offer a perfect path toward reducing natural gas use. 

By planning more than ten years out, “you’re basically making it up,” Pranis said. Even the idea of reducing natural gas piping cannot occur unless peak energy demand changes. He believes the distribution system will continue to operate for years but carry less natural gas.

“You need a fully functioning gas system until the day you don’t need it,” Pranis said. 

Fresh Energy’s managing director of buildings, Joe Dammel, said utilities have long forecasted continued natural gas consumption increases despite contrary evidence. Nor have they had to include Minnesota’s 2050 carbon neutrality goals in their thinking.

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The growth of natural gas “is at odds with, I think, a lot of the emerging policy concerns about the energy transition, customer preference and changes to the marketplace,” he said.

The plans will allow regulators to determine whether natural gas investments will be sensible in an uncertain future, he said. “Gas resource planning is an attempt to provide the commission and other stakeholders with a picture of potential futures,” Dammel said. “Saving customer dollars and keeping rates low is something planning can facilitate.”

Dammel still believes the final rules missed opportunities to gather important data. For example, he said that utilities will have to disclose potential new infrastructure investments but not the costs of replacing existing gas distribution systems, representing a significant portion of their spending.

Still, the natural gas resource planning “is a positive first step,” Dammel said.

The commission, however, might someday ask for net-zero planning. 

“That’s the direction that we need to head,” Sieben said. “But are we ready to be there yet? No, but I wouldn’t be surprised if we, in the years to come, do get there and start to plan for a net-zero future in a more deliberate manner.”

The commission continues to take comments and has an August meeting set to further refine natural gas resource planning, including when the requirement will begin.

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What’s the future of gas? In Minnesota, utilities have to share 10-year visions 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.

Climate and clean energy advocates weighing in on CenterPoint Energy’s ideas to decarbonize its natural gas business in Minnesota applaud the effort but say it falls short of what’s needed to meet the moment.

The state’s largest gas utility submitted an “innovation plan” last summer to the Minnesota Public Utilities Commission, which is taking public comments on the plan through March 15. Over the course of hundreds of pages, the utility proposes 18 pilot projects — from tree planting and geothermal to carbon capture and hydrogen blending.

Altogether, the utility is asking to spend more than $105 million on 18 pilot projects that it estimates will reduce the equivalent of around 330,000 metric tons of carbon emissions over the five year plan, which would represent about a 4% reduction, according to calculations by clean energy organizations.

The plan “is going to move us, but it’s not going to move as fast enough,” said Melissa Partin, climate policy analyst with the Minnesota Center for Environmental Advocacy, one of several groups that have submitted comments on the plan.

The docket (M-23/215) stems from the Natural Gas Innovation Act, a 2021 state law that, among other things, authorizes gas utilities to collect money from ratepayers for projects aimed at reducing greenhouse gas emissions. Xcel Energy submitted a similar plan to state regulators late last year for its natural gas utility.

Gas utilities are expected to make up a growing share of the state’s climate pollution as the state’s electric utilities transition to 100% clean power by 2040. Two out of every three households heats their home with natural gas, and many industries rely on the fuel to operate medium and heavy machinery — a potentially daunting challenge as the state seeks net-zero climate emissions by 2050.

Not a ‘silver bullet’

The Minnesota Center for Environmental Advocacy and other advocates have asked the Public Utilities Commission to supplement the pilot project spending with emission-reduction targets for the utilities.

While many of CenterPoint’s ideas look promising and some could eventually scale up to make a bigger impact, Partin said the Natural Gas Innovation Act will not alone drive the state across the finish line for its climate goals.

Other strategies will be needed, such as updating commercial and residential building codes, improving energy efficiency standards for appliances, and considering a ban on allowing any natural gas in new buildings, which, Partin said, “will be difficult in Minnesota’s current political climate.”

Utilities are somewhat hamstrung by the act’s requirement that half the budget for the initial plans must go to alternative fuels, which “stacks the deck” in favor of renewable natural gas and hydrogen, Partin said.

CenterPoint is already blending hydrogen into its system from a downtown Minneapolis facility, and so proposing additional such projects does not seem to fit the definition of “innovation,” Partin said. Meanwhile, a recent study by the Institute for Energy and Environmental Research found little to no climate benefit from blending hydrogen in existing gas supply lines, in part because hydrogen is less energy dense and more prone to leaking.

Joe Dammel, managing director of buildings for Fresh Energy, said CenterPoint’s plan “is definitely not a silver bullet; it’s not going to get us where we need to get.”  

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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.

While praising the utility for its yearlong stakeholder process and for proposing new resources and changes to its business model, the plan shows that CenterPoint will not contribute “their fair share of the emissions reductions needed based on this,” Dammel said.

CenterPoint’s pilots for weatherization and retrofitting homes look promising, he said, but ideas for purchasing carbon offsets, selling gas-powered heat pumps and injecting hydrogen into the existing gas system have little chance of success.

CenterPoint’s proposal to create green hydrogen, produced from renewable energy, and blending it into the gas distribution system is not “scalable” and has limitations. Commercial gas heat pumps “are not a very viable technology,” Dammel said. Instead, the utility should focus on applying hydrogen technology to decarbonize industrial end users.

Dammel added that to reach the state’s 2050 carbon neutrality goal CenterPoint’s first plan would have to increase its emissions reduction six-fold, from 4% to 27%.

The cost of learning 

Audrey Partridge, policy director for the Center for Energy and Environment, said the pilot programs will lead to better data and a greater understanding of the potential energy sources and their carbon emissions.

“I’ve heard people describe it as throwing spaghetti at the wall,” Partridge said. “But we need to come up with all the possible solutions and pursue them on a small scale to see which ones are going to stick. These aren’t necessarily mature ideas, as you would see in other areas of energy. They’re very, very new.”

The pilots that could yield important advances include using heat pumps for large loads and electrification of low and medium heat processes in the industrial sector, she said. Residential deep energy retrofits and geothermal technologies will likely reduce natural gas consumption.

“We do hope that CenterPoint and Xcel get approval to move forward on these plans so that we can start to learn from them,” Partridge said.

The docket could begin a new path for CenterPoint, which only sells gas. The Minneapolis Deputy Commissioner of Sustainability, Healthy Homes and Environment, Patrick Hanlon, said CenterPoint’s plan allows the utility to provide “heat as a service,” a crucial distinction that gives room for innovations the city supports, including ground source networked geothermal systems, district energy and other approaches.

“Heat as a service allows CenterPoint to move away from natural gas and move towards some alternative, more climate-friendly sources of heat,” Hanlon said. The city also wants to ensure that residents are “not burdened” with the cost of the innovative pilots or switching to a different level of service, he said.

The attorney general’s office, which represents ratepayers, suggested the cost for some pilots outweighed the carbon benefits while suggesting the commission modify or deny sections of the plan.

“Portions of CenterPoint’s plan are not yet ready for primetime: several of the proposals lack necessary partners, and many lack sufficient detail to establish their prudence,” the office wrote. “Other proposed projects are unlikely to achieve the greenhouse gas savings CenterPoint suggests and unlikely to justify the astronomical cost to ratepayers.”

The attorney general and clean energy groups also raised concerns about CenterPoint’s request to exceed pilot budgets by as much as 25% without statutory approval. Clean energy groups also seek modifications to CenterPoint’s plan to recover the cost of projects.

The Public Utilities Commission is expected to hold hearings later this year before deciding on the plans for both utilities.

Minnesota ‘innovation plans’ call on gas utilities to imagine their clean energy future  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 Midwest’s regional transmission grid operator this week announced another multi-billion dollar phase of transmission line projects as part of a four-part push to improve reliability and reduce curtailments.

The Midcontinent Independent System Operator (MISO) unveiled plans Monday for what’s known as its “Tranche 2” portfolio, which includes plans for several 765 kilovolt transmission “highways” spanning sections of Minnesota, Iowa, Wisconsin, Illinois, Indiana, Michigan, North Dakota and Missouri.

Many of the new lines would connect to projects being built as part of the $10.4 billion Tranche 1 portfolio, which MISO approved last year. Tranche 2 is projected to cost even more, at between $17 billion and $23 billion. A third batch of projects will focus on the grid operator’s southern territory, and the fourth will address north-south connections.

In its presentation to stakeholders, MISO officials said the investment will help manage challenges in three regions. In MISO West, which includes Minnesota, Iowa, North Dakota, Wisconsin and Michigan’s Upper Peninsula, 20% of its facilities are overloaded and annual curtailments exceed 15%.

In its Central region, composed of parts of Illinois, Indiana, and Missouri, facilities are 10% overloaded, and there’s a need for transmission to move power from west to east.

MISO’s East Region, defined as Michigan’s lower peninsula, suffers annual curtailment of over 15% and 10% of facilities are overloaded. MISO said in a presentation that transmission would help mitigate “import and export power swings between day and night.”

Beth Soholt, executive director of the nonprofit Clean Grid Alliance, said the Tranche 2 plan is  “bold” and “the direction we need to go.” The question is: does it go far enough?

The regional grid is expected to see significant growth from industries, electrification, data centers and other sources, Soholt said. 

“If load growth ramps up faster than the grid can handle, then we’re behind the eight ball again,” she said. “Now is the time to ask: Have we right-sized this portfolio?”

Mike Schowalter, senior manager of wholesale electric grid transition for Fresh Energy, said he was surprised by the lack of a High Voltage Direct Current (HVDC) line.

“If we’re looking at the long-term, we’re going to need the attributes that HVDC brings,” Schowalter said.

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A 765 kV transmission line needs taller towers and a much wider corridor than HVDC or other alternatives, Schowalter said. 

“I’m a little concerned about some of the siting issues that the different states will have to deal with,” he said, noting that the map shows a 765 kV Minnesota River crossing.

Utilities have told Schowalter that the plan misses future pockets of generation that may need additional transmission. He said the reason may be because the draft report centers on reliability, not interconnection constraints.

The plan also does not venture much into North Dakota, which has plenty of wind generation, Schowalter said. The draft plan “will help with some congestion, but will it help enough?” he said. “Probably not. In terms of relative to what we need, we need a lot more than this.”

Some utilities also think deploying HVDC lines would better solve grid instability issues, especially between wind-rich Southwest Minnesota and the more populated regions to the east, Soholt said. HVDC transmits electricity more efficiently than alternate current lines, which have higher rates of power loss. 

Utilities have often had to curtail wind power from southwest Minnesota because of transmission capacity issues. Clean energy advocates and others will be closely listening to the business case MISO will make later for the choice of the transmission locations and the size of the lines, she said.

Soholt said comments are being taken now on the plan and some stakeholders will offer modifications and alternatives. Some clean energy developers and members of the Clean Grid Alliance plan to suggest alternatives. Some organizations are expected to argue that MISO does not need this much transmission and others will tender a different vision, she said.

So far, MISO has released only a rough map of where the lines would run, without much detail. A stakeholder process will refine precisely where the lines will operate, Soholt said. 

Stakeholder input and alternatives to the Tranche 2 plan will be accepted through April 5. MISO will make a final decision later this year.

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The Midwest’s grid operator is planning a massive new transmission buildout. Will it be enough? 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 coalition of labor and environmental groups is putting its support behind perennial Minnesota legislation meant to lift a barrier to building power lines in the rights-of-way of federal highways in the state.

NextGen Highways is a national collaboration that promotes co-location of utility infrastructure in existing highway corridors as a way to accelerate expansion of the electric grid. 

The concept has widespread public support, according to the group’s polling, but it also faces various legal, financial, and technical obstacles across the country. 

“What we’re trying to do in Minnesota — and in states across the country — is to identify barriers and work with our coalition partners to develop strategies to overcome those barriers,” said Randy Satterfield, executive director of NextGen Highways.

One example in Minnesota is a state law requiring the Minnesota Department of Transportation to pay utilities if they are forced to move any assets, such as poles or towers, in federal highway rights-of-way. A pair of bills (House Bill 3900, Senate Bill 3949) would shift those costs to utilities instead, making it consistent with existing rules for state highway corridors.

Without that change, the state won’t allow transmission projects to be built in its portion of federal highway rights-of-way. State transportation officials have proposed such legislation multiple times since 2012, but the bills have never succeeded amid opposition from utilities.

Many transmission projects already follow highway corridors, Satterfield said. They include several announced last year by MISO, the Midcontinent Independent System Operator, Inc. Three of those projects cover portions of Minnesota and follow highways for parts of their routes.

Not all transmission lines that share routes with highways are located within the public right-of-way. Some are built on adjacent private property instead, which still requires negotiations with hundreds of individual owners. When developers have the option of placing towers or burying lines within the public right-of-way, it can significantly streamline a project.  

With clean energy’s escalating growth trajectory, more solar and wind developers will request permission to build projects and power lines in rural communities, Satterfield predicted. 

“I think we owe it to (communities) to at least consider utilizing existing linear infrastructure, like highways and interstates, for the transmission infrastructure,” he said.

‘This is a kind of low-hanging fruit’

Still, transmission developers wanting to take these routes often run into obstacles. Many state departments of transportation still recall a federal restriction, since rescinded, that did not allow transmission in federal highway rights-of-way, he said. Other states have no culture of allowing highway rights-of-way to co-locate with transmission.

NextGen Highways formed to advocate for transmission in highway corridors and to encourage states to remove any barriers to that goal. Minnesota is the first state where it has launched a state coalition to advance the concept. 

“Transmission congestion is the biggest hurdle that we have to overcome to reach our 100% energy goals and to get more renewables and other forms of energy on the grid,” said George Damian, government affairs director for Clean Energy Economy Minnesota, a nonprofit that is part of the coalition. “This is a kind of a low-hanging fruit. These rights-of-way owned by the state can be utilized for transmission.”

Utilities, lawmakers and stakeholders continue to discuss the legislation. Theo Keith, Xcel Energy’s spokesperson, said the utility has been “encouraged by the early conversations we’ve had with lawmakers and other stakeholders.” Xcel has proposed hundreds of miles of transmission lines in road corridors and often shares easements with the transportation department, he said.

Keith cited the CapX2020 project as an example of Xcel and other utilities building a major transmission corridor adjacent to the Interstate 94 right-of-way.

“Building new transmission lines is critical to meeting our clean energy goals and those of the states in which we operate, including Minnesota’s 2040 benchmark,” he said.

Overcoming barriers

Minnesota can look to its neighbor in Wisconsin for an example of how highway corridors could be used for transmission. That state passed a law 20 years ago to make federal and state highway rights-of-way a priority for siting transmission. Satterfield, who once worked for a transmission company in Wisconsin, said the state’s utilities built more than 200 miles of transmission projects on federal highways.

Wisconsin did not ask utilities to move poles or other assets on any of the projects, he said. Wisconsin’s Department of Transportation coordinates and plans projects with utilities to avoid potential problems, such as highway lane expansion that could encroach on transmission lines.

In addition to changing the Minnesota statute on utility colocation on federal roads, the NexGen Highway Coalition wants the Legislature to consider a siting priorities law. The law requires utilities to consider existing transportation corridors, such as highways and railways, before opting for greenfield development.

Minnesota Department of Transportation Strategic Partnerships Director Jessica Oh said the agency had put forth five to six legislative proposals since 2012 to repeal the language in the statute regarding utility infrastructure near federal highways and will support continued efforts. Utilities opposed the measure because of the additional expense they might incur in projects, she said. 

A change to the state law was also suggested in a report to the legislature based on permitting reform discussions held by the Public Utilities Commission, she said.

In studying Wisconsin’s experience, the department learned the importance of early coordination with clean energy developers and utilities “is key to the success of the whole process.” Minnesota transportation staff have conducted early planning sessions involving aerial encroachments on state highways with utility partners.

Oh said the department’s “highest concern” around utility infrastructure has always been safety. Should the legislation pass, the transportation department will continue to work  closely with utilities, especially since power lines will become instrumental in moving electric vehicles on highways.

Oh added Minnesota is among 11 states selected by the American Association of State Highway and Transportation Officials and the Transportation Research Board’s National Cooperative Highway Research Program for a “moonshots” program for state departments of transportation. Oh leads the initiative in Minnesota to co-locate more transmission and broadband in highway corridors.

“We have a stake in this because of the electrification of transportation,” Oh said. “I tend to think our fates are intertwined in energy and transportation.”

Great Plains Institute convenes NextGen Highways, which partners with the Center for Rural Affairs, Clean Energy Economy Minnesota, Conservative Energy Forum, Fresh Energy, Laborers’ International Union of North America-Minnesota and North Dakota, Mechanical Contractors Association, Minnesota Center for Environmental Advocacy and the National Audubon Society. 

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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.

Minnesota coalition seeks to remove barriers to building power lines along highways  is an article from Energy News Network, a nonprofit news service covering the clean energy transition. If you would like to support us please make a donation.

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

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

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

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

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

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

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

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

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

What happens next

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

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

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

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

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

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

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

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

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

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

A race against time

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

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

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

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

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

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

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

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

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

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