The Energy Transition to Renewables

Global solar companies’ total corporate funding, including venture capital, public market and debt financing,  declined 41% year over year during the first quarter of 2025, while energy storage companies’ funding fell 81%, according to Mercom Capital Group, a consulting firm.

Uncertainty — primarily around the fate of the Inflation Reduction Act and renewable energy tax credits, but also around tariffs and supply chain concerns — has prevented many financing deals from moving forward because the negotiating parties can't reliably calculate potential returns, said Raj Prabhu, CEO and co-founder of Mercom Capital Group.

If Congress does not soon signal a consensus on the IRA's fate, the renewable energy industry could end up snared in something like a sector-specific recession “in the sense that activity is going to stall because of the uncertainty,” Prabhu said.

Funding for solar, energy storage and smart grid companies plummeted essentially across the board during the first quarter of 2025 — an outcome Prabhu described as expected following the election of President Donald Trump, but one that could be concerning should the trend continue long term.

Prabhu said investor interest in renewable energy had begun to cool even before the election in November in conjunction with Trump's then-growing popularity. But the slump isn't related as much to Trump's specific positions, Prabhu said, as it is to the overall lack of certainty about how key elements of U.S. energy policy will ultimately fare.

“Mergers and acquisitions can still happen, but financing is a whole other deal right now,” given that investors and developers don’t know what it will cost to import their equipment and how much they can expect to receive in tax credits, Prabhu said. “Yes, some venture capital deals can happen if you have a company with something really innovative. But beside the sure-fire deals ... the rest are wait and see.”

Global solar companies — except companies based in China — raised $4.8 billion during the first quarter, down from $8.2 billion in the first quarter of 2024, but up from the $4 billion raised in the final quarter of 2024, according to data Mercom compiled. A single $1 billion venture capital deal caused the quarterly results, particularly for venture investment, to skew higher than they would otherwise appear, it noted. Public market funding totaled just $20 million, a 99% decline compared with the first months 2024, the firm said.

The results for energy storage companies were similarly skewed by a single large deal, though in the opposite direction. Northvolt's $5 billion funding raise in Q1 2024 helped bring last year's total to $11.7 billion, compared with $2.2 billion raised by energy storage companies this year. Smart grid companies saw Q1 funding drop 23%, from $686 million last year to $530 million this year.

These figures do not include the impact of the last several rounds of tariffs announced, paused and announced again in April, Prabhu said, so he expects investor interest in renewable energy to decline even further in the second quarter.

Real-world demand for renewable energy remains strong, but financiers can't get the information they need to move ahead with new deals, Prabhu said. Tom Harper, the head of global consulting firm Baringa's North American energy advisory team, noted that many private equity and infrastructure investors remain quite interested in operational renewable energy and battery storage assets. The appetite for smaller projects and projects that that remain in developmental stages is waning, however, Harper said.

Harper said he has spoken to companies that planned to sell portfolios of early- to mid-stage projects that have been unable to do so, prompting them to reconsider how much they themselves are willing to continue to spend on these projects.

If the market does not receive greater clarity on the direction of U.S. policy within the next few months, the impact to renewable energy markets and to the energy transition could be significant, Prabhu said.

Clean energy manufacturers canceled, closed or downsized nearly $8 billion in projects in the first quarter of 2025, as the Trump administration's rollback of support for the sector sets in.

Clean energy advocacy nonprofit E2 announced the cancellations as part of its monthly tracking of clean energy project announcements in the U.S. It was the first time E2 has opted to include cancellations and downsizes as part of its tracking, as the number of abandoned projects grows across the U.S. 

Cancellations included lithium battery maker Kore Power's cancellation of its planned $1.2 billion factory in Arizona, as well as Freyr Battery's cancellation of its $2.6 billion Georgia battery factory. 

The cancellations, which spanned 16 projects in sectors such as wind, solar and electric vehicle manufacturing, are another sign of companies' hesitation to push ahead with clean energy projects in the era of the Trump administration. 

In the years following the passage of the Inflation Reduction Act in 2022, manufacturers poured hundreds of billions of dollars into clean energy projects in a bid to cash in on the law's lucrative tax credits for domestic manufacturing, as well as its direct funding and loan financing. 

Now, however, times have changed. On his first day in office, President Donald Trump froze IRA funding pending a federal review. Since then, a federal judge has ordered the funding temporarily reinstated while a lawsuit from six climate groups is under consideration. 

Trump has been critical of the climate law and what he calls former President Joe Biden's "electric vehicle mandate,” referring to Biden’s 2021 executive order that called for half of new vehicles sold in the U.S. to be electric by 2030. The president has also criticized EV tax credits provided under the IRA. 

Further compounding this issue are the Trump administration's tariffs, which could drive up supply costs for everything from solar panels to EV batteries. For example, the U.S. still largely relies on imports for solar cell components — in 2022, roughly 88% of solar shipments were imports, primarily from Asia, according to the U.S. Energy Information Administration.  

While cancellations and scaled down plans made up the bulk of clean energy announcements in the first quarter of the year, some companies are still opting to invest in the U.S. March brought $1.6 billion in project investments across six states, including an $850,000 solar cell factory from T1 Energy, the reiteration of the former battery maker Freyr Battery. After canceling its Georgia battery factory, the company rebranded and relaunched as T1 Energy, with a new focus on solar energy. 

"Clean energy companies still want to invest in America, but uncertainty over Trump administration policies and the future of critical clean energy tax credits are taking a clear toll," E2 Communications Director Michael Timberlake said in a statement. "If this self-inflicted and unnecessary market uncertainty continues, we’ll almost certainly see more projects paused, more construction halted, and more job opportunities disappear.

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By American Wire Group

As the world races toward a low-carbon future, the transformation of our energy systems hinges on one crucial factor: grid expansion. The integration of renewable energy sources like solar and wind into the power supply requires a modern, robust, and scalable electricity grid. Without it, even the most advanced solar panels or wind turbines will fall short of their potential. To fully realize the benefits of clean energy, we must prioritize expanding and upgrading our power grids.

Renewable demand is driving change

The global shift toward renewables is accelerating. Solar and wind energy installations are increasing rapidly, supported by declining technology costs and ambitious climate goals. At the same time, energy demand is projected to rise significantly—by 40% by 2030 and potentially doubling by 2050—due to economic growth, electrification of transportation, and digitalization.

To meet this demand sustainably, grids must evolve. Unlike fossil fuel power plants, which offer a consistent output, renewable sources are variable. Solar production peaks during the day and drops at night; wind patterns change hourly. These fluctuations require dynamic grid systems that can balance supply and demand seamlessly while integrating energy from diverse, distributed sources.

Outdated infrastructure is a bottleneck

Unfortunately, most of today’s grids were built in the mid-20th century and are ill-equipped to handle the complexity of renewable energy. These aging systems face increasing reliability issues, inefficiencies, and security vulnerabilities. More importantly, they were designed around centralized fossil fuel generation—not decentralized, intermittent renewables.

In North America, renewable energy projects—especially wind farms—are often delayed due to grid connection backlogs. Transmission lines are either insufficient or non-existent in the regions where solar and wind resources are most abundant. This mismatch between generation potential and infrastructure readiness is stalling the clean energy transition.

To overcome this, the grid must be expanded physically and modernized digitally. More transmission lines are needed to move renewable electricity from remote areas to population centers. At the same time, smart grid technologies must be implemented to enable real-time data analysis, predictive maintenance, and demand forecasting.

Strategic investment is essential

Reaching net-zero emissions is not feasible without massive grid investment. In the U.S., it's estimated that grid-related spending must nearly double by 2030—reaching over $600 billion annually—to meet climate objectives. Since 2016, investments have grown, and federal initiatives have committed billions toward grid modernization.

However, funding must be strategic. Priorities should include:

• Transmission and distribution cable, hardware and equipment
• Energy storage systems to manage intermittent renewables
• Digital tools for grid capacity estimation and scenario modeling
• Standardized interconnection procedures to streamline project integration
• Workforce development for skilled trade workers and grid engineers
• Resilient supply chains to ensure access to critical components

Wire and cable, often overlooked, are foundational to the success of the renewable energy transition. Wire and cable serve as the physical backbone of the power grid, enabling the safe and efficient transmission of electricity across vast distances. In the context of renewable energy, wire and cable infrastructure must be capable of handling variable loads and fluctuating voltages.

As renewable projects expand in scale and complexity, so too does the need for advanced cable technologies that offer improved conductivity, durability, and fire resistance. Innovations in materials, insulation, and shielding contribute to increased efficiency and lower maintenance costs, enhancing grid reliability and resilience.

The broader benefits of grid expansion

Beyond enabling clean energy, a stronger grid offers several benefits. It reduces regional electricity price disparities by sharing power across larger areas, enhances energy security, and supports economic growth through job creation in construction, engineering, and manufacturing. It also lays the groundwork for future technologies like electric vehicles and smart buildings, all of which depend on a dependable grid.

Most importantly, expanding the grid strengthens our climate resilience. As extreme weather events become more frequent, a modernized grid can help prevent blackouts, maintain service during disruptions, and enable faster recovery.

Powering the transition

The global energy transition is not just about building more solar panels or wind turbines—it’s about ensuring the infrastructure exists to support them. Grid expansion and modernization are the linchpins of a clean energy future. With the right investments and planning, we can unlock the full potential of renewables, reduce emissions, and create a resilient, sustainable energy system for generations to come

Amid stiff headwinds for utility-scale renewables and gas, electricity system experts say utilities, industrial companies and other heavy power consumers may find some relief in a cheaper, faster and increasingly scalable solution: distributed generation and flexible loads, known as distributed energy resources, or DERs, that can be batched into virtual power plants or multi-megawatt demand response programs and deployed faster than utility-scale assets.

“There is an awareness that, oftentimes, distributed solar and distributed storage can come online much more quickly than larger resources … and a recognition of the role [they] can play in providing energy and in some cases capacity resources,” said Sean Gallagher, senior vice president of policy for the Solar Energy Industries Association.

Then again, nothing in the energy world is easy these days.

Earlier this month, President Donald Trump announced sweeping tariffs on imports from most U.S. trading partners. The targeted countries included major suppliers of solar panels, batteries and high-voltage electrical components, such as Vietnam (46%) and China (145% or more). Trump later announced a 90-day reduction to 10% for most countries other than China.

Distributed generation and storage assets may stand to benefit as developers look to sidestep bulk grid constraints, but they are not immune to supply chain challenges, particularly for larger projects, said Ravi Manghani, senior director of strategic sourcing at Anza Renewables, an energy data provider.

A perfect storm for utility-scale renewables?

Trump’s “Liberation Day” announcement was just the latest setback for the clean energy industry, which has been under siege since Jan. 20 despite providing 93% of new generating capacity in 2024. In a series of executive orders on his first day in office, Trump halted federal onshore and offshore wind permitting, withdrew all federal waters from offshore wind leasing, and declared an “energy emergency” that appeared to favor thermal and other high capacity-factor generating resources over wind, solar and batteries. A subsequent federal funding freeze, later partially rescinded, threw previously-authorized support for clean energy projects into limbo. Meanwhile, anti-renewables bills are proliferating in Texas, Oklahoma and other Republican-controlled states.

With the fate of Inflation Reduction Act tax credits up in the air as the U.S. Congress looks to offset an estimated $4.2 trillion in tax cuts this year, the clean energy sector could be in for more pain. Fully repealing the IRA’s technology-neutral Section 45Y investment and Section 48E production tax credits this year would reduce wind and solar deployments by about 50% over the next decade, The Brattle Group and ConservAmerica said in February.

That sort of pullback could jeopardize U.S. industrial growth, which is a driving factor in an expected 50% increase in electricity demand by 2035, ConservAmerica said. With new gas turbine costs rising fast and production capacity tied up until 2030, according to NextEra CEO John Ketchum, it may not be feasible to make up the shortfall with new fossil generation.

Because the U.S. already has tens of gigawatts of DERs that could be aggregated into VPPs within months, rather than years, some electricity system experts see smaller-scale resources as a potential stopgap should utility-scale renewables and storage development falter.

Enabling a more flexible grid

“DER” is a catch-all term for a broad range of generation resources, from residential solar arrays of a few kilowatts to grid-connected or behind-the-meter installations of 10 MW or more, and potentially flexible loads such as thermostats, water heaters and electric vehicles.

The U.S. has well over 100 GW of DERs that technically could be aggregated into VPPs and traditional demand response programs, but over 80% of that capacity is not, Wood Mackenzie said last year. Still, the firm identified 1,459 VPP deployments operating across 321 monetized market, utility and energy retailer programs.

Earlier this year, the Department of Energy pegged current U.S. VPP capacity at about 30 GW and said that figure could scale to 80 GW to 160 GW by 2030.

Utilities and state policymakers increasingly see the value in VPPs and DER aggregations, according to a February report from the NC Clean Energy Technology Center and the Smart Electric Power Alliance that catalogued more than 100 policy actions last year in 38 states and the District of Columbia. Many of those actions aim to harness the United States’ rapidly-growing distributed battery capacity or deploy sophisticated VPPs that use multiple categories of DERs, NCCETC Managing Director of Policy and Markets Autumn Proudlove said earlier this year.

In a flipbook released last year, RMI called out particularly innovative, multi-resource VPPs like those run by Puget Sound Energy in Washington (smart thermostats, behavioral load shaping, electric vehicles, water heaters and interruptible loads), Portland General Electric in Oregon (batteries, water heaters, behavioral load shaping and interruptible loads) and National Grid in New England (smart thermostats, batteries and technology-agnostic demand response).

Clean-energy groups are actively pushing supportive state policy and developing standardized templates for simpler, more efficient VPP programs, both key recommendations from last year’s Wood Mackenzie report.

“There’s a lot of enthusiasm around VPPs,” SEIA’s Gallagher said. “We are trying to templatize them so that they’re not as bespoke [and] are more straightforward to explain to utilities and customers.”

Though utility interest is “uneven” across the country, with some embracing DERs and others more resistant, eye-catching recent load growth forecasts help make the case, Gallagher said.

Speed and scale

In January, SEIA released a roadmap for 10 million distributed energy storage installations and 700 GWh of total deployed storage capacity by 2030. Utilities, too, are showing more ambition on DERs with plans for bigger, more sophisticated distributed resource aggregations.

In a February deal touted by Utah Gov. Spencer Cox, R, Rocky Mountain Power and distributed energy solutions provider Torus said they would collaborate on a commercial-and-industrial VPP that could provide up to 70 MW of flexible, behind-the-meter capacity by the middle of 2026.

“It’s no longer in question whether [this] is a path forward,” Torus CEO Nate Walkingshaw said in February. “[VPPs] can be seen at the same size, scale, quality and reliability as monolithic grid-tied architecture and are 100% viable today.”

In a regulatory filing in August, Xcel Energy’s Minnesota subsidiary proposed deploying and aggregating 440 MW of distributed solar and 400 MW of distributed storage to create what would likely be one of the United States’ largest VPPs.

“Xcel Energy believes distributed capacity can complement our existing plans for additional utility-scale renewable and firm dispatchable generation … [with] benefits including continued reliability, economic growth and providing our customers more options to adopt clean energy technologies,” Xcel spokesperson Josiah Mayo said in an email.

Meanwhile, utilities across the U.S. are working with developers to install larger-scale distributed energy resources with an eye to improving local and regional resilience.

In California, San Diego Gas & Electric partnered with EES and Mitsubishi Power Americas joint venture Prevalon to deploy multiple community microgrids totaling 180 MWh, and the company is now pursuing “half a dozen” similar opportunities right now, Prevalon President and CEO Tom Cornell said.

“We’ve seen a lot more utility inquiries in the past six to 12 months,” he said.

The value proposition for distributed batteries and firm generation is especially strong in regions where the grid is less reliable due to infrastructure challenges or weather-related risk, such as western North Carolina — hit hard by two hurricanes in 2024 — and other swaths of vertically-integrated utility territories across the Southeast, where developable land is abundant, Cornell said. 

In those territories, a typical 10-MW, 40- to 60-MWh system might take 12 months to site and permit, with equipment procurement happening in parallel and construction and commissioning taking a matter of months afterward, according to Cornell.

The Southeastern utilities “move especially fast … they understand that they can move quicker on these than any other resource,” he said.

Questions remain

Despite clear advantages over larger, less flexible, slower-to-deploy resources, DERs aren’t immune from the economic and policy uncertainty roiling the electricity sector, experts say.

California’s NEM 3.0 net metering tariff, effective for residential solar and storage systems that entered the state’s interconnection queue after April 14, 2023, dramatically reduced solar-only installations while boosting battery attachment rates. Until more independent system operators implement rules consistent with FERC Order 2222 and additional states enact policies that capture the full value of distributed generation and storage, the residential segment could see muted growth on a national level, Anza Renewables’ Manghani said.

State-level policy could also temper growth in the fast-growing community solar segment following a record-breaking 1.7-GW year in 2024, according to Wood Mackenzie data. Cumulative U.S. deployments reached 8.6 GW at the end of 2024, Wood Mackenzie said.

But a closer look at the numbers shows disproportionate contributions from a handful of pro-solar states — with Illinois, New York and Maine accounting for 83% of total capacity deployments last year — and policy uncertainty in emerging state markets as more mature markets saturate.

“Emerging markets have been slow to ramp up and program size caps limit the potential for growth in these states to make up for declines in larger markets,” Wood Mackenzie research analyst and lead report author Caitlin Connelly said in February. The upshot is an uncertainty band — as much as 40% to the downside and 37% to the upside — around Wood Mackenzie’s base case of 15 GW in cumulative deployments by 2029.

Cost is another concern for smaller-scale energy resources, Manghani said. For example, while the cost gap between distributed and utility-scale storage continues to close amid fierce supplier competition, “utility-scale projects still benefit from superior economies of scale, revenue generation market structures and financing advantages,” he said.

And Manghani emphasized that, like their bulk counterparts, distributed generation and storage systems and components are at least somewhat exposed to supply chain challenges.

“Ultimately, price trends will depend on policy shifts, manufacturing capacity expansion and how quickly suppliers adjust to demand,” he said.

Wind and solar together generated more electricity than coal in the U.S. for the first time in 2024, and coal’s share of the generation mix fell to an all-time low of under 15%, according to a report from the think tank Ember.

“2024 saw the largest-ever increase in solar generation in the US (+64 TWh),” said Ember. Wind production grew by 32 TWh, while coal generation dropped by 22 TWh.

These solar additions marked “the second largest increase of any country, after China,” according to the report. “Significant capacity additions spurred by the Inflation Reduction Act have begun to feed through to generation increases. Wind generation rose as a result of improved wind conditions from 2023 as well as a moderate increase in wind capacity.”

The world also “reached a new milestone as low-carbon sources — renewables and nuclear — provided 40.9% of the world’s electricity generation in 2024, passing the 40% mark for the first time since the 1940s,” said Ember.

“Solar power surged by a record 474 TWh in 2024, the largest annual growth ever recorded in absolute terms and the fastest increase in six years (+29%),” the report said. “Solar power has maintained its extraordinarily high growth rates even as the technology has become the primary driver of new electricity generation.”

Ember found that solar, for the third consecutive year, “recorded the largest absolute increase of any electricity source,” and that “for the 20th year in a row, it remained the fastest-growing power source.”

U.S. gas generation also increased significantly in 2024, rising by 3.3% or 59 TWh, “the largest rise in gas generation seen in any country in 2024 and more than half (57%) of the global increase in gas generation,” said the report.

Natural gas consumption “set new winter and summer monthly records in January and July,” the Energy Information Administration said in a March 31 report. 

“Historic low natural gas prices in 2024 meant that natural gas was more competitive in the electric power sector, especially compared with coal, contributing to increased use of natural gas for electricity generation,” EIA said.

Ember found that overall electricity demand in the United States grew by 3%, or +128 TWh, in 2024, “caused partly by heatwaves over the summer months and partly as a rebound from a milder summer in 2023 when demand decreased by 1.3% (-55 TWh).”

“The summer of 2024 (June-August) ranked as the fourth-warmest on record in the U.S. Lower 48 states, leading to strong demand for air conditioning and resulting in new daily records for electricity generation in July and August,” EIA said. “As a result, natural gas consumption in the electric power sector rose in July and August to be the highest ever recorded for the summer.”

The roads in and out of Delta, Utah, are dotted with ghost towns. The oldest date back to the Pony Express. The majority saw their heyday during the gold rush; now they mostly consist of stone markers and the occasional remnants of an old cabin.

And like many of the towns that remain in Utah's West Desert, Delta has faced the very real possibility that it, too, could be relegated to the dustbin of history sooner rather than later. Town mayor John Niles recalls having conversations with his city council about the possibility that they could face an exodus of residents or even a foreclosure crisis when the Intermountain Power Agency announced in 2017 that it planned to close by 2025 the 1.9 GW coal-fired power plant that accounts for roughly half the town's total GDP.

In a town of just 3,800 residents, these weren't anonymous citizens who stood to lose their homes. Niles himself worried that his two sons, who both work at the IPP coal plant just as he did before he ran for city council, would be forced to move away to find work.

Instead, the town today is experiencing something of a housing shortage. Faced with the possibility of losing its largest customer — the Los Angeles Department of Water and Power — if it continued to burn coal, the Intermountain Power Agency decided to replace the coal plant with a pair of gas-fired turbines with a combined capacity of 840 MW designed to run on 100% green hydrogen by 2045.

Construction of the new plant and all the associated infrastructure reached peak employment last summer with some 1,200 workers on site. And finding room and board for all those workers in a town the size of Delta has proved a bit of a challenge.

If construction on the plant remains on track — it's slated to open this year — the Intermountain Power Project stands to become the world's first operational gas power plant designed and built to use 100% carbon-free hydrogen.

But there's more at stake than simply demonstrating hydrogen-powered energy generation at scale. The town of Delta could also represent a rare success story in the nation's quest to transition former coal-producing communities to renewable energy — but one that experts say could be difficult to replicate elsewhere, given the unusual confluence of circumstances that is giving rise to the IPP's new hydrogen-capable gas plant.

Commitment and community values

During the energy crisis of the 1970s, rural communities such as Delta wanted more baseload generation to ensure access to reliable electricity. But the small size of these cities and towns meant that they couldn't afford to build a large coal plant all by themselves — they'd never use enough of the power to justify the expense.

In Utah, 23 communities formed the Intermountain Power Agency with a goal of pooling their resources and sharing the power from the two-unit coal-fired power plant they ultimately built. Yet even this cooperative couldn't use all the power they planned to generate, so they struck a deal with a much larger municipality: Los Angeles. The Utah-based municipalities and public utilities retain the right to take as much power from the project as they need, and the remaining power is sold to LADWP, with the proceeds coming back to the municipalities that own the project. These municipalities can also choose to defer their entire interest in the project in favor of selling their portion of the power to LA, according to John Ward, an IPP spokesman.

“And it's worked out well for everybody,” Ward said. “California got 40 years of good, reliable baseload electricity. The Utahns have got jobs, tax revenue and this sweetheart deal that gives them a front row seat at a world-class project they only pay for when they use it. It's been a tremendous success.”

Construction of the original Intermountain Power Project completely transformed Delta, which was then a small farming community with little industrial experience. But the town largely welcomed the change. The project has, in the time since, generated more than $600 million in tax revenue for local communities in addition to creating jobs and attracting other energy and materials-related businesses to the area, Ward said.

That income means Delta — and the smaller surrounding communities — enjoy public services not often seen in towns of this size, according to Vicki Lyman, a technical analyst in the environmental group at IPP who also serves as a local county commissioner. The power plant helps pay for local schools, the hospital, a new jail, a library and a softball complex, among other things.

“The CEO out there ... has done more for our community than you can imagine,” Delta Mayor Niles said. “He donates to everything. He donates to our high school, to the football teams. Most companies won't do that.”

Although it's no longer the only game in town, the IPP remains the largest taxpayer in the county, Ward said. So when LADWP informed the IPP board that it could no longer purchase coal-fired electricity, Ward said their responsibility to the community meant they had to find a new way to serve their largest customer to avoid closing the plant. So that is what they did.

Because the original IPP plan called for the construction of two additional coal units that were never built, the cooperative had room on site for a new set of generators — two natural gas units totaling 840 MW. These will start running a 30% hydrogen blend as early as this summer, with a goal of using 100% carbon-free hydrogen by 2045.

Beside the cost and the potential stakes for the local community, the hydrogen industry writ large also has a lot riding on this particular project, Chevron New Energies' Vice President of Hydrogen Austin Knight said.

“To do something this large on this timeline makes it very unique — and something the entire system can learn from,” Knight said. And perhaps the most important factor making it all possible, he said, was the fact that the customer and the entire team behind the project has an unwavering commitment to clean, renewable energy.

Unique obstacles

While many coal-producing towns face similar challenges, the reality is that each community is unique. That means that a single approach is unlikely to fix all the issues that such areas face, according to Sean O'Leary, a senior researcher at the Ohio River Valley Institute, where he studies the economies of coal- and other energy-producing communities.

A community like Delta has limited options to prevent its economy from collapsing when its main revenue generator is threatened, O'Leary said. Most communities that have made successful transitions from fossil fuel production to other industries, such as Centralia, Washington, are significantly larger than Delta, with more diverse economies before the loss of fossil fuel jobs.

Yet Delta does have some unique circumstance that should work in its favor, O'Leary continued. The biggest factor, in his view, is that the IPP has already found a customer. Many hydrogen projects to date have been unable to get off the ground due to their inability to secure offtakers.

The second factor, O'Leary said, is that the IPP is owned by local municipalities, which means that the economic benefits associated with the project are more likely to stay within the surrounding communities. The limited number of jobs associated with projects like power plants relative to the high cost of capital means that the benefits of these projects more often accrue to investors who live outside the communities in which they are built.

What flummoxes O'Leary is the fact that Los Angeles is apparently willing to pay for all of this. Hydrogen, O'Leary noted, is still hugely expensive compared to nearly all forms of generation, and most forms of energy storage. When contacted last summer, LADWP declined to comment, referring any questions to IPP.

The politics of the situation also mystify O'Leary. In some other coal-producing communities that have looked to transition to hydrogen or other forms of renewable energy, opposition from local communities has threatened to derail projects.

“The cultural aspect of this is so bedeviling,” O'Leary said, noting that one in four counties in the Ohio River Valley, another area that has attempted to make this transition, has passed ordinances prohibiting the construction of wind and solar farms. “We are trying to understand the nature of the opposition because most of it isn't about cost and benefits. It's not about jobs. To a large degree the opposition is basically cultural, identity-based. That makes it very difficult to overcome.”

Policy and paygrades

The Intermountain Power transition project is itself no stranger to opposition. Last year, the Utah state legislature attempted to stop the planned 2025 retirement of the coal plant by passing a bill that required the IPA to give the state government a two-year window to buy the plant, despite objections from IPA leaders who said this would interfere with their plans for the project's transition. The fate of the coal plant closure remains uncertain, but the IPA no longer objects to the state’s intervention following changes to the original bill that put the onus of figuring out how to keep the coal plant running on state officials, according to Ward.

That disinclination to tangle with the broader, thornier questions of the energy transition may well account for the IPA's ability to bridge the gap between Utah's traditionally conservative politics, and the more liberal polices that govern their customers in California.

From the IPA's perspective, Ward said, switching fuels was a simple business decision based on customer demand. If California wanted to pay for clean power, then the IPP was going to make clean power. Broader questions about how society should transition to clean energy without harming coal-producing communities are “above our paygrade,” he said.

That pragmatism is also apparent in the IPA's dealings with other project partners, such as Siemens. Matt Neal, who is overseeing Siemens' end of the project as the company's vice president of grid solutions in North America, described IPA's managers as “some of the best customers we've ever had” thanks to their commitment to making level-headed, logical decisions about what was best for the project without getting emotions involved.

The scale of the project probably lends itself to some of that agreeableness. Michael Ducker, president and CEO of Mitsubishi subsidiary MHI Hydrogen Infrastructure, posited that the enormous investment going into the project and the commitment it represents gives locals a confidence that they can work at the plant and raise a family and that their kids will have a path toward a stable future. But Mayor Niles thinks it’s more than that — the people of Delta are just more open-minded than most, he said.

“I think everybody realizes that we have to keep moving forwards,” he said. Some residents have expressed skepticism about other new energy projects in the area, Niles said, but they usually come around once the project gets off the ground.

That prospect of working with cutting-edge technology also appeals to Lyman, who worked as a local high school science teacher before taking her first job at the power plant.

“When I taught chemistry, I would do demonstrations for the students and show them how we can split water into hydrogen and oxygen, and we'd burn the hydrogen .... I mean, I'm pretty excited about hydrogen. I think there's a huge future in hydrogen,” Lyman said, though she acknowledges that most of the community likely supports the hydrogen transition because they appreciate the tax base and the government services that come with the power plant.

How you replicate that mindset elsewhere and convince polarized political factions to get along is “a whole different issue,” Ward said. “But in terms of this project, this project has figured out a way for people to cooperate to the benefit of everybody, and we're trying to keep those values as we move into the next phase of the project's life.”

And while there's no current plans for an “IPP 3.0,” you can already see the potential for it when you look out from the coal plant's roof over Delta's expansive desert horizon, Ward said.

“There's land, there's water, there's existing transmission capacity,” he said. “We've got Mitsubishi and Chevron right across the highway investing major money from international conglomerates. There's a huge potential for this to be the starting point for additional development, and I think that decades-long history of cooperation is the thing that's going to make this project thrive for many more decades to come.”

The renewables industry begins 2025 with the Inflation Reduction Act continuing to spur record investment, and spiking load growth providing new opportunities for deployment. At the same time, interconnection queues across the country remain clogged, siting, permitting, financial and other challenges continue, and industry critic Donald Trump just began his second term as president.

“It’s an interesting moment, because there is this really rapid change, and yet we're stuck in some really key ways,” said Heather O'Neill, president and CEO of Advanced Energy United. “The interconnection queue is one really clear example where, yes, there's some progress — FERC’s putting out reform measures — and yet we're not unleashing the full promise and the economic opportunity and activity that we could.”

After decades of flat load growth, U.S. electricity demand could rise 128 GW over the next five years, according to a report last month from Grid Strategies. At the same time, the number of new transmission interconnection requests has risen by 300% to 500% over the last decade, with 2.5 TW of clean energy and storage capacity currently waiting to connect to the grid, said an October report from the Department of Energy.

However, O’Neill said, the “the macro trends are incredibly positive … We are in the middle of an energy transformation.” She attributed some of her optimism to the scale of investment and growth that the industry has been seeing. 

The energy storage sector is especially dynamic right now, O’Neill said: “A few years ago, [there was] very little in the way of storage capacity showing up, but with so much innovation in the technology, the cost curves are coming down. When we think about how to manage load, storage plays a key role in that.”

Global energy storage installations boomed 76% in 2024 and are projected to continue that streak in 2025, according to a November report from BloombergNEF, but BNEF noted that growth may be impacted by “uncertainties stemming from the new Trump administration.”

Trump has spoken out against electric vehicles and said he will "rescind all unspent funds under the misnamed Inflation Reduction Act.” Congress is expected to try to claw back EV tax credits from the IRA, which could impact the battery industry. Trump has also said he would end offshore wind “on day one” and embraced oil and gas generation, but vowed last month to expedite federal permits and environmental reviews for construction projects that represent an investment of $1 billion or more — a move that could benefit clean energy.

Felisa Sanchez, a partner with law firm K&L Gates’ maritime and finance practice groups, said that Trump’s goal to end offshore wind may come into conflict with his goal of boosting the U.S. economy and its domestic manufacturing. 

“It's hard to say ‘we're going to end offshore wind’ when you're also impacting a vast supply chain that has already been going for the last few years that has been implemented — when ports have been developed, and vessels have started to either be under construction or have come out of the yard ready to work in offshore wind,” she said.

John Northington, a government affairs advisor and a member of K&L Gates’ public policy and law practice group, said he anticipates that the offshore wind industry may adapt to the new administration by shifting away from “‘steel in water is good for the environment’ as the main message.”

“Maybe for the next four years, it's that steel in water is good for jobs, it's money, it's good for America,” he said. “Talking about the business benefits, rather than environmental benefits, could be a change in trend for some of these companies.”

When speaking to Utility Dive in December, Northington said he was also hopeful about the bipartisan Energy Permitting Reform Act of 2024, sponsored by Sen. Joe Manchin, I-W.Va., and Sen. John Barrasso, R-Wyo. — but the bill was not included in the continuing resolution passed later that month, “taking permitting off the table for this Congress,” said Manchin, who retired in early January.

New demands on the grid

Regardless of how Trump’s second term shapes the U.S. generation mix, his administration will be dealing with an anticipated 3% annual average load growth over the next five years — a level which hasn’t been seen since the 1980s, according to a December report from Grid Strategies. 

“The need to meet load growth on the electric side is not going away. And any administration — Republican, independent, Democratic — foremost in their mind is going to be a strong resilient economy,” said Paul DeCotis, a senior partner and head of East Coast energy and utilities at West Monroe. “That's going to be dependent upon a best-in-class electric distribution grid.”

Surging load growth is driven largely by data center demand, which a December report from Lawrence Berkeley National Laboratory found has tripled over the past decade and is projected to double or triple again by 2028. The increase in demand is also the result of industry electrification and growth in domestic manufacturing.

That growth “means continued capital investment in the [energy] industry, regardless of the administration,” DeCotis said. “I don't think any administration is going to want to come in and all of a sudden see brownouts and blackouts and not enough capacity to meet demand, or have to stall demand and the job growth that goes with it, because they can't meet energy needs.”

O’Neill said she believes that states will also continue to drive the clean energy transition forward, as they’re where “energy policies happen …. where the investments become real.”

State governors and commissioners “want manufacturing in their state,” she said. “They want data centers in their state. The siting reform conversation is one that I think is not a partisan conversation. It's: how do we help unlock some of this desired economic activity? For us, the siting and building issues will be something that we're going to work on in the states, regardless of the landscape in D.C.”

In addition to states and utilities, companies like Microsoft, Amazon and Meta are also helping to drive the demand for clean energy — investing billions in renewable energy deployment in addition to seeking nuclear and natural gas generation to handle load from their data centers.

Molly Jerrard, head of demand response at Enel North America, said she expects that in 2025, “significant load growth .... will challenge our grid’s flexibility and put the reliability of local systems to the test.”

“Combine this with aging infrastructure, congestion, and the uptick in climate-driven grid stress, utilities and grid operators will need to put a bigger focus on adoption of demand response programs and distributed energy resources to address these challenges and increase grid stability,” Jerrard said.

However, she said, “inconsistent data access standards” from utilities continue to limit the scalability of virtual power plants, a potent demand response solution.

O’Neill is excited about VPPs, she said, as she sees “a ton of innovation” flowing into the sector and expanding the ways that VPPs can offer grid flexibility.

“We're seeing virtual power plants across different regions of the country — whether it's coastal or Texas — where you've got utilities and commissions really putting virtual power plants to the test,” she said. “They're managing the load, they're shaving peak loads, and they don’t have to build as much [generation].”

Solar and offshore wind

In 2025, the American Clean Power Association forecasts that utility-scale U.S. solar installations will shrink 16% from 2024, due to the risk of new tariffs under a second Trump administration and concerns that he might work with Congress to repeal aspects of the IRA.

The industry’s residential segment “continued to decline” last year, driven by California, where residential solar cratered following the state’s switch from net metering to net billing in 2023, said a third quarter 2024 report from the Solar Energy Industries Association.

While solar projects in the state “definitely don't offer the same amount of savings that they used to,” said Dan Smith, vice president of markets at DSD Renewables, “we are continuing to see California be our largest market.”

This is due in part to utility rates “[continuing] to escalate at really extreme levels in California,” he said. “So while we're experiencing [NEM 3.0] adversely, as utility rates increase, that increases our customers’ savings. So that's making up a bit of that gap.”

Smith said that DSD Renewables is entering 2025 apprehensive about any potential repeal or reforms to the IRA’s solar tax credits, but hopeful that the Trump administration and Congress will see their value.

“The projects that are being facilitated through that are not isolated in blue states,” he said. “For example, we're doing projects all over the country and seeing projects work in states like Ohio and Pennsylvania that didn't used to work.” 

Smith said that if the domestic content adder in the IRA remains in place, and domestic solar supply continues to come online, he won’t be as concerned about potential tariffs. 

“But that's the question that I think the whole industry has right now — do those suppliers continue to make investments in their domestic factories?” he said. “There are many factories either under construction or planned, and the big question on many of our minds right now is, will any of that federal policy change in such a way that it causes those companies to pull back on those commitments?”

The offshore wind industry also contains a lot of people “holding their breath,” Sanchez said, “waiting to see what happens when [Trump] does come into power at the end of January.”

The stock prices for offshore wind companies like Ørsted and Vestas fell following the election and have yet to recover. Sanchez said she sees this as a “temporary signal” that will depend on what actions Trump takes on offshore wind.

“There's been a tremendous level of investment, and that has continued this year, even with the more cautious approach that the industry has taken,” Sanchez said. “And I do see that going forward. But again, I think everyone at this moment is in a pause waiting to see what happens over the next couple of months, to see whether it's worth continuing additional investment.”

On his first day in office, Trump issued an executive order pausing offshore wind lease sales in federal waters and the issuance of approvals, permits and loans for onshore and offshore wind projects. The pauses don’t have a set expiration date, according to the order, but will remain in effect until revoked.

Northington said he finds it promising that Trump’s pick to head the Department of the Interior, former North Dakota governor Doug Burgum, has overseen the development of onshore wind in his state.

“I think that the Trump energy policies are, yes, anti-wind, but when it comes to getting something done, it's more pro-oil and gas,” he said. “At the end of the day, to dismantle something requires effort and energy, and to ignore something takes much less energy.” 

However, Northington said he’s concerned that the high bureaucratic turnover of Trump’s first administration may continue in his second, and civil servants at agencies like the Bureau of Ocean Energy Management may decide to retire. People might say, “‘Okay. I stuck through round one — am I going to stick through round two?’” he said. “I think that can have a certain deleterious effect on things like getting permits through, or holding lease sales.”

Both solar and offshore wind continue to advance technologically, with promising innovations on the horizon. There are still “a lot of discussions going on about the future of offshore wind, about floating wind, about the development of the technology and the infrastructure needed on the West Coast to support floating wind,” Sanchez said.

The solar industry benefits each year from “continued improvements in efficiency of solar modules,” Smith said. “Now we're using almost exclusively bifacial solar modules, which increase the energy yield.”

Marlene Motyka, Deloitte’s U.S. renewable energy leader, said she’s hopeful that solar cell technology will continue to advance with further innovations in materials like silicon and perovskite, and she’s excited about a December report from SEIA and Wood Mackenzie that said U.S. solar module factories are now equipped to meet nearly all domestic demand.

Motyka said Deloitte expects “good momentum” for the industry in 2025: “We don't expect, and I think lots of people out there don't expect, the IRA to completely be blown up and be obliterated.”

“There are a lot of things that have been coming together over time, and that's not going to be stopped on a dime,” she said. “I've been involved in renewable energy for 17 years, and all of it is kind of coming together now. I think it's still an exciting time.”

The first time electrical engineer Johanna Mathieu heard about Ann Arbor, Michigan’s plan to create a “sustainable energy utility,” she thought it was crazy. 

Even though investor-owned utility DTE Energy already provides the city’s electricity, Ann Arbor wants to set up its own supplemental utility that will initially focus on installing rooftop solar and battery storage at homes, businesses and other institutions citywide. Eventually, the plan calls for constructing microgrids to allow those buildings to share renewable energy across property boundaries, adding to the power lines that already crisscross the city.

That idea of duplicating grid infrastructure goes against the most basic principles Mathieu teaches her students as an associate professor of electrical engineering and computer science at the University of Michigan, she said. 

“Power grid 101 is you don't build duplicate infrastructure because it doesn't scale,” Mathieu said. “That [infrastructure] should be owned and operated by a single company that's heavily regulated by a state or federal government.”

Voters in Ann Arbor, however, have decided the SEU makes sense: 79% of them voted on Nov. 5 to pass a ballot measure that authorizes the city to establish, construct, operate and own the new utility. The goal of the SEU, which officials hope to begin operating within the next two years, is to ramp up local clean energy generation and make the community’s electricity supply more resilient.

Here’s how the SEU will work when it first launches: It will pay the complete upfront cost of installing rooftop solar and battery storage systems at the homes, businesses and institutions of customers who choose to participate. The SEU will own and operate those systems forever and recover its investment over time by charging customers for the energy the rooftop solar panels generate, said Missy Stults, Ann Arbor’s director of sustainability and innovation. 

When enough neighboring customers sign up for the SEU, the city wants to construct microgrids that let them share their renewable energy. That infrastructure would also allow the SEU customers to retain power even when the main DTE grid has outages.

The SEU will also offer programs to help customers pay for energy efficiency improvements, weatherization and electrification. Plus, it could operate community solar programs with solar power generated in shared spaces of the city and construct networked geothermal systems to heat and cool neighborhoods without burning fossil fuels on-site.

What differentiates the SEU from a standard municipal utility — besides only investing in local clean energy generation and decarbonization — is that it doesn’t seek to fully replace the existing utility. It aims to complement it, giving Ann Arbor residents more choices for where they get their energy. SEU customers will get one bill from the SEU and another from DTE for the energy they use from each supplier. 

As the SEU adds more locally generated clean energy, the community will likely need less power from DTE. However, a 2023 report prepared for the city says it’s unlikely the SEU will fully replace DTE in the foreseeable future. Stults said in an email that modeling shows the SEU could one day provide more than 75% of the community’s total energy needs, but that outcome is unlikely to pan out “for a very, very long time as we’d need almost everyone in the City to sign up to meet that threshold.”

 

Mathieu, the electrical engineer, no longer thinks the SEU is a crazy idea. She now is collaborating with the city as a researcher on the project. Although the SEU may not be the most technically elegant model for energy infrastructure, it is the city’s best bet for quickly ramping up clean energy generation, she said. Other paths, like getting the existing utility to move faster toward clean energy or staging a municipal takeover of its infrastructure, aren’t realistic, she said.

“I've explained this to people like, ‘This is the fifth-best solution, but solutions one through four are not viable for a variety of different reasons,’” Mathieu said. “Five is feasible. So, let's do it.”

Seeking more control

The passage of the SEU ballot measure was a key moment in Ann Arbor’s years-long quest for more control over where its power comes from. The city’s climate goals include using 100% renewable energy citywide by 2030.

Some community members have pushed for the city to buy and take over the existing utility infrastructure through municipalization, but that could take years and cost Ann Arbor upwards of $1 billion. And municipalization efforts often face strong pushback from incumbent utilities, although they can give communities bargaining leverage to convince the utility to make concessions, like lower rates or clean energy commitments.

Others in Ann Arbor have advocated for Michigan to allow local governments to participate in community choice aggregation, which lets cities purchase renewable energy on behalf of residents while the existing utility continues to manage billing and distribution operations. State lawmakers have yet to pass such a law, which would likely face “strong opposition from incumbent utilities,” according to an FAQ document the city produced.

In 2021, “this idea emerged of, ‘Well, could we form a supplemental utility that doesn't focus on a takeover?’” Stults said. “Because, honestly … the goal wasn't to own the system. The goal was to generate clean, reliable, affordable power.”

Stults put together a small advisory task force of experts, who determined an SEU would be technically and economically feasible as well as legal under Michigan state law. 

In some ways, Ann Arbor is following in the footsteps of Delaware and Washington, D.C., which have had versions of an SEU in place for years, but those differ from what Ann Arbor is planning, Stults said. Delaware’s SEU, for example, is a nonprofit that offers numerous programs to help home, business, nonprofit and farm owners access renewable energy and make energy efficiency upgrades, but it does not operate microgrids, according to John Byrne, president of the Foundation for Renewable Energy and Environment and a researcher who created the model for Delaware’s SEU. 

How to start an SEU

Creating a new utility comes with startup costs, like hiring a director and setting up a billing system, Stults said. To avoid hoisting those costs onto a small number of initial customers, the city will wait to launch the SEU until its waitlist of potential subscribers hits 20 MW of demand annually. 

Meeting the 20 MW threshold could look something like one or two large institutional partners or a thousand individual residents, Stults said. The city has been in talks with the public school system and other institutions about joining the SEU, and Stults said she expects quite a few to do so.

The picture shifts, however, if Ann Arbor finds grant funding, rather than taking on debt to fully finance the SEU. With grants in the picture, the SEU would need less demand to guarantee initial subscribers would see low rates, Stults said. She is also speaking with venture capitalists about investing in the SEU, and the city is budgeting $250,000 to $300,000 in existing funds to hire a director for the new utility.

The waitlist for the SEU, which the city began publicizing in October, had just over 650 names on it as of Dec. 4, Stults said, but she doesn’t yet know the exact demand that represents or if those are individual households, businesses or institutions. That information collection will likely begin in 2025. 

The SEU’s final electricity rates will be “heavily influenced” by how many people sign up and what financing it gets, according to the city. Stults said the SEU will likely always be able to offer customers lower electricity rates than DTE can, in part because the SEU doesn’t have to generate profits for shareholders and can access capital with low interest rates, given the city’s AAA municipal credit rating. 

Customers can join or leave the SEU at any time, although if they leave, the city will remove the infrastructure it owns from that building, Stults said. The cost of removing such infrastructure, along with the cost of equipment depreciation and replacement, will be built into the rates.

 

The SEU’s reliance on public buy-in is why the city put it on the Nov. 5 ballot, even though it could have gone ahead with the plan sans voter approval. “It’s a big deal to start your own utility, even a supplemental, opt-in utility,” Stults said. “This was the best way we could think of to confirm the public is seriously interested in this, even those who will never subscribe. Do they want more choice in the system?”

Stults says the SEU has not faced any organized opposition, although she has encountered misperceptions about what it is and is not. Residents in favor of fully replacing DTE with a municipal electric utility say the SEU is a step in the right direction but fails to meet the urgency needed to address climate change. “[The SEU] will not be enough to reach the city’s 2030 renewable energy goals, or to address our chronically unreliable power grid,” Greg Woodring, president of Ann Arbor for Public Power, said in a statement. 

Key to the long-term success of an SEU is that community members feel like they have a stake in its development, said Byrne, who worked on the Delaware SEU. “The problem is, if you're inside government, is it really the community that's governing, or is it really the bureaucracy, if you will?” he asked. He suggests that Ann Arbor “keep this entity close to communities.”

DTE Energy, the investor-owned utility that serves Ann Arbor, said in a statement to Smart Cities Dive that it is “dedicated to supporting the City of Ann Arbor's clean energy goals.” DTE likened the SEU to its MIGreenPower program, through which customers can pay to support clean energy. “When coupled with DTE's planned investments in clean energy, these voluntary, fee-based programs help accelerate economy-wide decarbonization while maintaining reliability and affordability,” DTE said.

A model for other cities?

Could Ann Arbor’s version of an SEU work in other U.S. cities? “From an engineering standpoint? From a social, economic standpoint? Absolutely,” Mathieu said. “From a legal and regulatory standpoint, I feel like it depends on the laws in that state or jurisdiction.” But, she adds, “we can do it in one city and learn a lot and then see if it makes sense in other places. I don't think we’ll have lost much by trying.”

One challenge is convincing the people who review federal funding applications that this is an idea worth betting on, Mathieu said. “When we get this reviewed by other engineers who haven't been brought along to thinking about it that way, they’re like ‘No, this is crazy,’” she said. “We could be moving a lot faster if we can get over this barrier of people thinking, ‘This is the way it's always been, [so] this is the way it always should be.’”

These existing “rules” for maintaining the power grid’s stability are entrenched in its traditional orientation around large central power plants, Byrne explained, but communities could reconsider those standards in favor of a new paradigm. 

“If you want to have renewable energy go faster, don't build it on the same model that got you in the dilemma that you now have, which is fossil fuel and nuclear power plants that are centralized and big grids that are very costly infrastructure,” he said. “Try and work on alternative infrastructures.”

Utility-scale renewables development has ground to a halt in at least 15% of U.S. counties due to a combination of bans, moratoriums, and overly strict zoning and land-use restrictions, according to a February analysis by USA Today.

Lawmakers in Michigan, New York, Illinois and other states with 100% carbon-free electricity goals are pushing back with policies that centralize renewables permitting at the state level, provide financial incentives for more permissive local ordinances, or both. Though initiatives like Michigan’s Renewables Ready Communities Award program are too new to have had an observable impact, the early success of two New York programs is heartening for advocates of community-oriented approaches that include tangible financial benefits for municipalities and utility customers.

“There is no question that these packages help [developers] gain public support,” said Dan Spitzer, who co-leads New York-based law firm Hodgson Russ’s cleantech and renewable energy practice.

Such efforts could accelerate onshore wind and solar development, keeping state and federal governments on track to reach their clean electricity goals in the short term. But experts worry that the backlash to state policies perceived as unfair by host communities could entrench local opposition to utility-scale renewables, spur litigation and ultimately slow the energy transition. The most effective state policies, they say, incentivize constructive local participation in siting and permitting processes and nudge developers to treat host communities fairly while limiting opportunities for opponents to delay or kill mutually beneficial projects.

“Ørsted favors working directly with local governments, but the local units often need or ask for a common framework to guide development in addition to incentives offered by states,” said Hayes Framme, head of new markets and growth for Ørsted, which has a 3-GW onshore wind portfolio and nearly 700 MW of utility-scale solar and energy storage under construction.

A carrot-and-stick model in Michigan

Several Michigan townships and counties have enacted moratoriums on utility-scale solar development — and, in at least one case, all large-scale renewables development — in the past two years, citing perceived negative impacts on rural vistas, property values, soil and water health, and the availability of prime farmland. 

Michigan’s Renewables Ready Communities Award, or RRCA, program — which was authorized last year as part of Michigan’s landmark clean energy legislative package and will remain in effect for at least two more years after a repeal effort failed to gather enough signatures to appear on the November ballot — follows that model, said Sarah Mills, director of the Center for EmPowering Communities at the University of Michigan’s Graham Sustainability Institute.

The $30 million pilot program awards $5,000/MW to communities that permit and physically host utility-scale renewable energy projects or $2,500/MW to communities that do one or the other. To qualify for the award, a community must approve a project through a local siting ordinance, according to a Michigan Department of Environment, Great Lakes and Energy, or EGLE, fact sheet. 

If the host community has no local siting ordinance that “is perceived as generally favorable enough for development,” the developer can use a state siting process that includes a less generous community benefit payment of $2,000/MW.  

Unlike the RRCA program’s higher local benefit, that $2,000/MW payment comes out of the developer’s pocket. So while potentially less restrictive than the local ordinance, the state process is costly for developers, EGLE says.

“The goal is to encourage developers and communities to work it out at the local level rather than go through the state-level process,” Mills said.

According to Mills, RRCA is unique among state clean energy development programs for disbursing some funds when construction begins, rather than waiting until a project is operational. 

RRCA is also notable for the high dollar value of its renewables-friendly community awards and the fact that the funds “can be used for basically any community benefit,” said Ian O’Leary, a departmental analyst at EGLE who co-manages and helped design the program. 

RRCA-eligible projects must have at least 50 MW of capacity, so the minimum grant per project is $125,000 at the $2,500/MW level or $250,000 at the $5,000/MW level. Though some projects span multiple local government units, the program still promises significant — and potentially decisive — funding for sparsely populated rural townships, O’Leary said. 

“The tax revenues brought in by projects are often not enough to convince local governments [to approve them],” said Zona Martin, another RRCA co-manager and co-designer. 

With support from EGLE, the Center for EmPowering Communities’ Renewable Energy Academy helps local governments proactively develop zoning ordinances compatible with Michigan’s clean energy legislation, Martin said. 

The RRCA program, state permitting backstop and Renewable Energy Academy are intended to work together to “make a watertight renewable energy system” in Michigan, O’Leary said. 

That effort got a boost on July 22 when the U.S. Environmental Protection Agency issued a $129.1 million grant to help Michigan expand RRCA and related emissions reduction programs. 

Though long permitting timelines mean projects enabled by RRCA and the state permitting backstop likely won’t begin construction until next year, they’ve moved the needle for at least one major renewables developer.

Thanks to the new policy, “Michigan [is now] one of Ørsted’s high-priority states,” said Framme. “In its absence, it was challenging to see a meaningful path forward for developing projects in Michigan.”

Bill credits and ‘bribes’ in New York

In New York, utility-scale wind proposals have for years drawn opposition in upstate communities concerned about views, impacts on farmland and the misconception that the projects only benefit downstate population centers, said Hodgson Russ’s Spitzer. More recently, wealthy coastal residents have opposed onshore infrastructure to serve the state’s nascent offshore wind industry, he said.

Like Michigan’s RRCA scheme, New York’s Host Community Benefit Program incentivizes local governments to support renewables development. A second, potentially more impactful New York program requires project developers to detail in project applications the public benefits they plan to provide to host communities, which has helped convince skeptics of the value of local energy generation, Spitzer said.

The Host Community Benefit Program requires project owners to make annual payments to the host utility of $500/MW for solar projects or $1,000/MW for wind projects larger than 25 MW for the first 10 years of operation, according to a Hodgson Russ summary. The fees fund utility bill credits for electric utility customers in the host community. 

With hundreds or thousands of residential customers in many host communities, “it’s a fair statement” that the bill credit benefit can be diluted, Spitzer said.

Under the second program, project developers have donated to local park and library systems or contributed funds for public building upgrades, Spitzer said. The 35-MW Steel Winds facility funded “a new community center, a commerce center … and a 110-acre greenway and bike trail,” on a former steel mill site in Lackawanna, New York, according to a 2020 handbook developed by the New York State Energy Research and Development Authority.

All of this — along with the potential for revenue from larger renewables facilities to “virtually wipe out town taxes” — “fits into the broader definition of host benefits,” Spitzer said. 

But it doesn’t always work. Under New York’s state licensing process, a host community can agree to waive local siting and permitting rules as part of its community benefits agreement, potentially speeding up preconstruction review and locking in developer-paid benefits. Communities where public opposition to renewables development runs deep may chafe at the loss of local control over the process, “see any offer [of benefits] as a bribe” and hire attorneys to fight the project, Spitzer said. 

“Frankly, a lot of what you’re fighting as a developer is flat-out NIMBYism,” he said. “States [like New York] that have greater home rule authority are slower to achieve their clean energy goals because host communities look for ways not to cooperate.”

Corn Belt contrast

In 2021, Illinois became the first Midwestern state to commit to 100% carbon-free electricity generation. There was just one issue: The mandate included no significant siting or permitting reform, leaving the fate of its 2050 deadline in the hands of largely rural local governments with very different politics from the Democratic-dominated Illinois state legislature. 

An Illinois law passed last year reset the dynamic in favor of developers by setting state standards for utility-scale wind and solar projects that preempt stricter local ordinances and require local governments to approve state-compliant proposals. 

The new law is a "release valve," providing state policy guidelines that can remove some of the pressure that local decision-makers may feel as they consider wind and solar projects, Apex Clean Energy Senior Director of Government Affairs Chris Kunkle said.

The law creates a “stable, predictable permitting environment [that helps Apex decide] where we want to invest our time and resources, which are finite,” he said.

The new law also opens up wind-rich Illinois counties that were effectively off-limits due to restrictive ordinances. Apex never stopped prospecting in the state, but the company “doubled down” after the 2023 law, Kunkle said. 

“We feel great about Illinois, to say the least,” he said.

But utility-scale renewables remain contentious in some parts of rural Illinois. Officials in Piatt County in March 2023 denied Apex’s application for the 300-MW Prosperity Wind project, voiding a $10 million revenue-sharing agreement with Apex. Before approving a resubmitted application in October, several county board members said the new law forced them to vote yes on the project despite personally opposing it. One said voting down the project meant “gambling with 8 to 10 percent of our yearly budget.”

The state’s decision to strip authority from local governments “created a tremendous amount of bad blood,” and it’s not yet clear that the Illinois law has spurred new renewables development, said Brian Ross, vice president of renewable energy at the Great Plains Institute. Illinois’ development queue is about the same size as neighboring Indiana’s despite Indiana’s far gentler — and, thus far, unfunded — incentives for permissive local permitting, Ross said.

Under a new state law, the Indiana Commercial Solar and Wind Energy Ready Communities Development Center provides general information about renewables development and offers a certification program for communities that implement wind- and solar-friendly ordinances. Certified communities are eligible to receive incentive payments for operational projects from the Indiana Office of Energy Development, or OED, at $1/MWh for 10 years, according to the development center’s website.

But the program “is entirely voluntary and does not bypass any of the local permitting processes, or mandate local units of government doing anything that they don’t want to do,” said Greg Cook, OED communications manager.

Despite the lack of funding, the Indiana program may help demystify renewables siting, permitting and development for rural communities, said Tamara Ogle, community development regional educator for Purdue Extension. 

Negotiations between communities and developers can drag on for years, creating space for misinformation to flourish and hardening local opposition to proposed projects, Ogle said. Even without OED funding in the near term, certified communities may feel empowered to better negotiate with developers around financial compensation, local hiring and procurement, and other benefits, she said. 

Those conversations can be mutually beneficial, Framme said.

“Every single one of our projects looks different at the end of the community engagement process than it did at the beginning,” he said. “We work to modify project parameters [based on concerns about] viewshed, construction schedules, traffic, soil condition and other issues.”

Whether they see homegrown renewable energy as a precursor to deep decarbonization or primarily as an economic development engine, local, regional and state governments should apply some of that creativity toward new community-benefit models, Hodgson Russ’ Spitzer said. 

Those could include programs that support agrivoltaics so that “[solar] facilities can stay farms,” the creation of public utilities with aggressive clean energy goals, or the development of “energy districts” that can leverage tax-exempt bonding, Spitzer said.

“You can create a water district — why not an energy district?” he said

Virtual power plants can realize their full potential with improved control technologies, streamlined communications and customer-engaging compensation, utilities, providers and analysts agree. 

VPPs are aggregations of distributed energy resources managed by sophisticated software to meet power system needs, including load reductions and system stability. By mid-2023, North America had more than 500 of them with up to 60 GW of total capacity, according to one estimate. By 2030, VPP flexible capacity could scale up to 160 GW and serve almost 20% of the projected 802 GW U.S. peak load, the Department of Energy says.

“Scaling up DER integration” into VPPs will face challenges, wrote DOE Loan Programs Office Director Jigar Shah in September 2022. But the obstacles are “far from intractable, and well-worth the cascade of benefits,” he added.

Even analysts whose research shows VPPs can be a key power system solution agree the challenges to scaling are real and are only beginning to be addressed.

To grow, VPPs can and must be “fully compensated for the value they can provide” and “customers need to trust that participating won’t inconvenience them,” said Brattle Group Principal Ryan Hledik, whose research has identified signifjcant VPP values. And vital VPP system stability services may require technology investments to “connect directly into utility control systems,” he added.

Scaling VPPs will likely impose new costs for operations technologies, VPP providers, utilities and analysts said. It will also require new planning processes that recognize the multiple new values of VPPs’ flexible DER elements, and confronting regulators with the need for system standardizations, many also agree.

Operational challenges

VPPs vary significantly by jurisdiction and provider, and there are no recognized communications standards to streamline their response to indicators that show a need for load reductions or system stability services.

Pacific Gas and Electric has “approximately 412 MW” of VPPs and is “actively looking to integrate more,” said company spokesperson Paul Doherty. Its VPPs are part of state, aggregator-led and utility-led programs with partners including Tesla, Sunrun and BMW, he added.

PG&E is implementing a new system-wide Advanced Distribution Management System coupled with a Distributed Energy Resource Management System, Doherty said. It is also investing in communications systems which “will enable incremental VPP use cases,” he added.

Rocky Mountain Power has standardized its Utah Wattsmart solar and battery VPP operations by establishing criteria battery manufacturers must meet to participate, said the utility’s Vice President of Customer Experience and Innovation William Comeau. It therefore “has no need for DERMS,” he added.

To qualify for Rocky Mountain Power’s load reduction and stability services programs, batteries must meet capacity, cycle life and daily charge-discharge capability criteria, Comeau said. With the Institute of Electrical and Electronics Engineers’ 2030.5 protocol for DER interconnection and 30 second interval data available to the utility, Rocky Mountain Power has full dispatch control of the VPP’s full value, he added.

“The IEEE 2030.5 DER interconnection standard could be a solution” for national interoperability between all DER and all system operators, agreed Scott Harden, chief technology officer for global innovation with power system technologies provider Schneider Electric. The American National Standards Institute or another national standards agency “could take the lead” to develop another standard to serve the same purpose, he said.

“The control room and communications technologies to scale VPPs have been available for a decade and are proven,” Harden continued. But scaling VPPs will require “development of a standardized open communications protocol and open DER registry to allow all DER to compete in retail market-like scenarios,” he said.

Duke Energy’s just approved 60 MW PowerPair pilot offers a $9,000 upfront incentive to customers who buy batteries and allow limited utility control of them, added Duke Energy Senior Vice President, Pricing and Customer Solutions, Lon Huber. But automated interoperable communications and dispatch “will be critical” to reaching “meaningful scale,” he agreed.

To scale VPPs, Hawaiian Electric will require “smarter, faster” control room and communications technologies for visibility, control and dynamic optimization, agreed company spokesperson Darren Pai.

VPPs are a growing part of National Grid's resource mix, National Grid Director, Future of Electric for Customers, Joshua Tom added. Additional control room and data management technologies are all "really important" to further scale them, he said.

But Chris Rauscher, head of grid services and VPPs for Sunrun, said, “both PG&E’s sophisticated control room operations and Puerto Rico’s LUMA’s fairly rudimentary operations allow partnering in Sunrun VPPs” and “there are no technical, metering or software challenges.”

According to Rauscher, the claim that more sophisticated control room technologies are necessary is “an excuse” for delaying expansion of VPP programs. Sunrun, however, “dispatches its own fleet of DER” without integrating into utility operations, he acknowledged. 

Brattle’s Hledik added that for “real-time grid balancing services at scale, VPPs may need to connect directly” with utility operations.

To provide system stability services, the Sunverge-Delmarva Power-PJM Interconnection 500 kW Elk Neck, Maryland, VPP had to meet PJM’s “real-time operational requirements,” said Sunverge Energy CEO Martin Milani. It had to provide two-second telemetry, two-second meter scans, and under ten-second aggregator responses, he added.

“Scaling VPPs and providing the full range of system services will require state regulator-approved investments in much faster telemetry and metering and communication systems,” Milani said.

Nevertheless, “any utility considering resource procurements should compare VPP peak generation costs with near term costs for alternatives,” Sunrun’s Rauscher said.

But attracting consumer participation in virtual power plants at the scale projected by DOE and Brattle raises other questions, utilities, VPP providers and analysts widely agree.

Compensation to attract participation

The VPP DER elements are typically owned by customers and therefore are bargains for utilities and system operators compared to traditional infrastructure investments, but customer-owners must see the value proposition in participating, many stakeholders said.

“The biggest issue now is developing market drivers,” said Ed Smeloff, independent consultant to the Center for Energy Efficiency and Renewable Technologies.

California’s Demand Side Grid Support program is “a driver toward full market participation” for customer-owned DER because it compensates VPP aggregators for using them to reduce loads at periods of very high demand, Smeloff said. “More market integrated compensation programs will evolve as interconnection codes and communications standards are developed for bigger-scale VPPs offering more system services,” he added.

“Customers also need to learn to trust that limited third party control of their DER will not compromise the value of their investments and will lower bills,” Smeloff said. “That will require utilities and aggregators to recognize customers have different values and intentions about DER,” he added.

The Delmarva Power-PJM-Sunverge pilot faces that exact challenge, said Pearl Donohoo-Vallett, director of regulatory strategy and services for Delmarva parent Pepco Holdings. Delmarva “gave batteries to customers at no charge in return for allowing utility control when demand drives prices high, but customers wanted the batteries for their own backup power,” she added.

Delmarva is now working to recognize both “customer needs and evolving system needs,” Donohoo-Vallett said. The more system services the DER meet, “the more value they have, and the higher the compensation to the customer,” she added.

“A scalable program’s economics must attract participation, but it has to be cost-effective” for all utility customers, Duke’s Huber noted.

But some pricing to VPP aggregators and DER customer-owners “does not provide a compelling price signal to participate,” responded Benjamin Hertz-Shargel, global head of grid edge for Wood Mackenzie.

New York and New England grid operators compensate VPPs for wholesale market capacity, Hertz-Shargel said. But compensation for distribution system value, like National Grid’s ConnectedSolutions program and Consolidated Edison’s Distribution Load Relief program, would “make the value proposition to customers more compelling,” he added.

ConnectedSolutions and California’s Demand Side Grid Support program were also endorsed by Mathew Sachs, senior vice president, strategic planning and business development for leading virtual power plant provider CPower, Sunnova Manager, Grid Services Policy, Jamie Charles, Sunrun’s Rauscher and National Grid’s Tom.

VPPs can also benefit customers “through time-varying rates,” Tom added. And “flexibility markets could identify the timing and magnitude of a need created by local constraints and compensate aggregators for meeting that need while avoiding the cost of a traditional infrastructure solution,” he said.

State regulators will be central to resolving compensation issues, in approving cost recovery for technology investments and in setting compensation for customers that encourage participation, stakeholders agreed.

What regulators can do

Federal Energy Regulatory Commission Order 2222 “opened the door for VPPs to compete” in organized markets, but work remains, DOE’s Shah acknowledged.

Order 2222 “started a good conversation,” said Sunrun’s Raucher. It could open wholesale markets “in the next decade,” and “be a lever for scaling VPPs,” but current regulatory efforts to further enable VPPs have “moved back to state regulators and utilities,” Rauscher added.

State regulators could streamline efforts to scale VPPs by proactively doing “jurisdiction-specific VPP market potential studies” and using them “to establish VPP procurement targets,” Brattle’s Hledik said. They could also make VPP pilots more viable with “innovative utility financial incentive mechanisms” and “updated existing policies,” he added.

Utilities can also help regulators understand “the need for foundational investments” to upgrade control rooms and communications with high-speed systems needed to scale VPPs, said Pepco Holdings’ Donohoo-Vallett. “Those expenditures will allow using the benefits of DER and VPPs for a more affordable energy transition,” he added.

Longer-term planning that identifies future market needs for load reductions or stability services enables VPP providers to build proactively to meet them and can also reduce costs, said CPower’s Sachs. Providers could then initiate expensive investments in technologies and customer acquisition and education where planners anticipate those needs and be ready to more quickly and cost-effectively offer system benefits to meet them, he added.

If the full VPP value stack at both the transmission and distribution system levels is recognized by planners, it is likely to show costs avoided by VPPs at scale make them “more cost effective than conventional resources,” Hertz-Shargel added.

Many tax-exempt organizations are now eligible for a wide array of the Inflation Reduction Act’s tax credits through the U.S. Internal Revenue Service’s direct pay framework. 

Also known as elective pay, the framework allows private nonprofits and government entities to receive clean and alternative energy tax credits through direct cash payments. The Environmental and Energy Study Institute notes that most entities would qualify for tax incentives of between 30% and 50% of a project’s total cost, depending on the project’s location and the extent to which domestically produced hardware is used. Previously, the credits were limited to organizations with federal tax liabilities, which could only claim credits to offset the taxes they owed. 

The U.S. Treasury Department released its long-awaited final rule for the program on March 5, clearing the way for nonprofits and government entities to begin claiming IRA credits.

Direct pay covers 13 tax credit programs authorized or extended by the IRA. The most popular program is the Commercial Clean Vehicle Credit, which aligns with many entities’ existing vehicle fleet electrification goals and is “relatively less complex than … other applicable credits,” Mark Ritacco, chief government affairs officer for the National Association of Counties, or NACo, told Facilities Dive. But county governments are also interested in solar, EV charging, and biogas credit programs, Ritacco said.

Direct pay covers investments placed in service after Dec. 31, 2022, and “early adopters” are now beginning to claim credits for the 2023 tax year, said Todd Guerrero, partner and chair of the energy group at law firm Kutak Rock. Guerrero expects claim volume to increase next year as more entities learn about the opportunity and as early adopters’ claims show that direct pay works as intended. 

Which entities are eligible for direct pay?

Direct pay is available to state and local government agencies, school districts and other entities with taxing authority as well as tribal governments, corporations, rural energy cooperatives, religious organizations and nonprofits exempt from taxes under federal tax code sections 501(c)3 or 501(a).

To qualify for direct pay, eligible entities must register with the IRS, submit information about the qualifying investment and file a tax return for the year the investment became operational. 

Though the process is straightforward for entities accustomed to dealing with the IRS, it may be unfamiliar for tax-exempt organizations, according to Carolyn Berndt, legislative director of sustainability at the National League of Cities, or NLC.

Claiming federal tax credits involves “a whole new set of learning curves” for the smaller, resource-constrained and risk-averse municipalities that account for much of NLC’s membership, Berndt said in an interview. 

Given many eligible entities’ limited experience with tax financing, the most likely early adopters are entities that “are more familiar with the energy industry,” like public utilities and rural electric cooperatives, Guerrero said. 

Many utilities already benefit indirectly from tax financing through power purchase agreements with for-profit companies, “so they know that if you’re not utilizing tax credit programs, you’re leaving money on the table,” he said.

Allyssa Wall, a Kutak Rock attorney whose practice covers renewable energy tax credits, has seen interest from a broader set of tax-exempt entities that own property suitable for solar arrays, which are expensive to install but can significantly reduce energy costs over time. That includes larger, “more sophisticated” entities like airport authorities, which have high energy needs and ample land available for solar production as well as smaller organizations with modest operating budgets, Wall said.

“Direct pay makes [going solar] more financially feasible when money is tight,” Wall noted. 

Eligible investments: Solar, HVAC, EV fleets and more

Solar arrays aren’t the only clean energy investments that qualify for direct pay. Eligible tax-exempt organizations can also claim credits on small wind turbines, biogas generators, fuel cells and geothermal heat pumps through the Investment Tax Credit for Energy Property. Other forms of eligible energy infrastructure include battery storage systems, microgrid controllers and combined heat and power systems. 

The base credit for these energy investments is 6% of the total project cost, according to an IRS fact sheet. The fact sheet shows the credit increasing to 30% for larger projects that meet IRS’ prevailing wage and apprenticeship requirements and climbing further — 10% for production tax credits or 10 percentage points for investment tax credits — for projects located in energy communities that rely on fossil fuels or other heavy industries.

Overcoming direct pay learning curves

Despite being “a huge opportunity” for cities and other tax-exempt organizations, the direct pay framework has some potential pitfalls, Berndt said.

The timing of direct pay reimbursement, which comes only after a qualifying investment enters service, is one such challenge. Many qualifying investments’ upfront costs are too large to cover out of operating budgets, meaning grant funding, bond issues and other funding sources remain vital to project underwriting, Berndt said. Some clean energy projects, such as solar arrays and ground-source heat pumps, can take longer than a year to complete, Berndt added.

Organizations must also meet the IRA’s domestic content requirements, which begin phasing in this year. Unless they meet the domestic content requirements, some projects that begin construction in 2026 or later may not qualify for any production or investment tax credits, according to an analysis by the World Resources Institute. Exceptions exist for projects with generating capacity of under 1 MW and in situations where the domestic content requirements would be financially burdensome. But “domestic content is the problem child right now,” Kutak Rock’s Wall said, pointing to widespread concern that many otherwise worthy investments will not qualify.

Although the Treasury Department’s final regulations do not directly address domestic content issues, it will issue additional clarifications regarding domestic content in forthcoming regulations, JD Supra reported. 

In late February, just before the final rule was published, NLC, NACo and several other associations filed a “very granular” public comment with the U.S. Treasury Department, requesting changes to the current requirements, said Michael Gleeson, legislative director for finance, administration and intergovernmental relations at NLC. 

With months to years of planning and environmental reviews required for larger clean-energy projects, some projects in the planning stages today might not start construction until 2026, Gleeson said.

Gleeson said the Treasury Department is expected to issue a final rule on the domestic content element and other aspects of the IRA, later this year. 

Meanwhile, groups like NLC and NACo are working to build awareness of direct pay and set eligible entities up for success.

“Our message is [that] this is a great opportunity, but it’s complicated, so take the time to plan ahead and get it right,’” Berndt said.