The Energy Transition to Renewables

In 2022, a data center in Houston came to Gridmatic with an ambitious ask: they wanted to begin matching their energy consumption with zero-emission power sources on an hourly basis, in a fashion similar to the 24/7 clean energy goal announced in 2020 by Google.

And so over the course of the next year, the energy modeling company did just that. They used artificial intelligence to forecast the data center's energy needs and the availability of clean energy to identify ideal sources of energy and avoid the over-buying that is typically associated with time-matching energy strategies. By the end of the year-long pilot project, the data center was successfully matching 80% of its power consumption with zero-carbon energy sources on an hourly basis, said David Miller, vice president of business development for Gridmatic.

The pilot was even more successful than anyone the team had hoped: The initial goal was to match about 60% of the data center's hourly energy needs with clean energy resources, Miller said. But they did not ultimately find affordable resources to match all of the data center's energy needs.

Google — the pioneer of the 24/7 clean energy goal — has had a similar experience. As of its most recent environmental report, the tech giant was matching 64% of the energy consumed by its data centers and offices with carbon-free energy on an hourly basis.

Critics of the IRS's currently proposed guidance for the 45V hydrogen production tax credit, which would require hydrogen producers that want to use the credit to match their energy use with clean electricity production on an hourly basis, often argue the rule's expectations are impossible. And at least right now, Miller and other experts say, it probably is. A handful of exceptionally determined large energy buyers might be able to make it work, but it's not currently possible at scale.

Even so, they say, it should be possible in the future — potentially in the very near future. Miller, Google and others agree that the industry simply needs to overcome two not-insignificant hurdles: the lack of sufficiently granular emissions data, and the fact that sufficient round-the-clock clean energy that buyers want doesn't exist.

Generation gaps

There are a few energy buyers in the U.S. who currently get 100%, 24/7 clean energy. Constellation Energy has two customers — one utility and one data center — who receive 24/7 clean energy products from the company, according to Mason Emnett, senior vice president of public policy for Constellation. They're also talking with other companies looking for similar options — including customers looking for energy products to supply clean energy at times not covered by their existing PPAs and new customers looking for fully comprehensive 24/7 energy options, Emnett said.

But Emnett does not believe it would be possible, right now, for just any energy customer to buy 24/7 clean energy. Constellation is able to offer these products specifically because they are located within the PJM Interconnection, which has a registry that offers hourly emissions data, and because Constellation itself owns a large fleet of nuclear and hydropower assets that can provide clean power when wind or solar energy is not available.

“For the size of customer that we typically serve, we have the ability to provide hourly matched products for any of them,” Emnett said. But realistically, he said, “we wouldn't be able to do that for the entire grid.”

If hourly matching is to be a thing for broader swaths of the U.S. power grid, Miller believes there will need to be more localized, dispatchable carbon-free generation such as nuclear generation. There will be at least some increased flexibility in energy demand in the future, Miller said — EVs and electrolyzers for hydrogen production could shift power consumption to times when wind and solar energy are abundant. But neither he nor Emnett believe load flexibility will be sufficient to make 100% 24/7 clean energy possible for a majority of energy customers.

“If we are not making the effort now to look forward in time and ensure that the resources we have operating are meeting customer demand, we are not setting ourselves up for success in that future decarbonized world,” Emnett said.

Emnett argues that this is a reason to support enshrining 24/7 matching in regulatory policy. Right now, wind and solar energy is in demand because they appear to be the most economical options for carbon-free energy, and nuclear power is less popular because of the comparatively high cost, Emnett said. But if you need to buy power when the sun doesn't shine and the wind doesn't blow, that changes the calculus — the cost of overbuilding wind and solar and energy storage assets exceeds that of nuclear power, Emnett said.

“That is why we talk about hourly matching, because right now the market signals don't indicate where that firm carbon-free energy is needed,” Emnett said. “Hourly matching goes a long way to identifying the time periods in which we need more carbon-free energy to be operating. That will realign the value of firm carbon-free assets like nuclear, but it will also demonstrate the development needs that we have as a society, and as a country.”

But building more clean, dispatchable generation won't be enough to make hourly emissions matching more accessible, Emnett said. Getting there in the future will also require more transparent and standardized emissions data.

Collecting the data

Each of Constellation's existing 24/7 energy contracts required extensive one-on-one negotiations to ensure the power supplied to the customer was truly carbon-free, Emnett said. That means the process at present is not particularly scalable.

The trouble here is there simply aren't a great number of options for buying and trading renewable energy credits on an hourly level, Miller said. A handful of emerging and growing marketplaces do exist — but even on those platforms, it can be difficult to find credits outside the PJM territory that record hourly emissions data.

PJM Environmental Information Services, a registry serving the PJM Interconnection, began trading certificates with hourly time stamps last March, in response to customer inquires — especially inquiries related to nuclear and hydropower assets within the region, according to company officials. The company also believes hourly matching will change the game for these generation resources — and has expressed hope that being the first RTO to offer hourly emissions data might attract new customers.

LevelTen Energy, which runs a marketplace for power purchase agreements and other renewable energy assets, has also begun work on a marketplace for trading time- and location-specific renewable energy certificates, which they call granular certificates, as has startup company WattCarbon.

WattCarbon started out with the goal of creating an accounting system for energy buyers who worry that renewable energy credits may not result in real-world emissions impacts, CEO McGee Young said. In time they realized the best solution was assigning a serial number for every watt hour of energy generated, with attached attributes like location and carbon emissions.

On the WattCarbon marketplace, which is expected to offer energy products from approximately a million generation resources sometime this summer, data comes directly from the generators themselves. This means buyers could access hourly data for generation outside the PJM area through the WattCarbon marketplace, regardless of whether other RTOs follow PJM’s lead. WattCarbon also buys and reissues energy attribute certificates from the PJM area to avoid double-counting, Young said.

Getting the data directly from the generators also means the WattCarbon marketplace plays well with distributed energy resources and virtual power plants looking to aggregate these resources for sale into larger energy marketplaces. The ability to sell attributes like avoided emissions could help virtual power plants and distributed energy resources become more economical compared to their utility-scale counterparts by creating additional revenue for these generators.

But there is a catch associated with this generator-direct model. It's limited to sellers who sign up for the market. And right now, Young said, the marketplace does not have enough suitable sellers to offer any of their customers 24/7 clean energy 100% of the time.

“Matching is not the hard part,” Young said. “It's going out and procuring ... in terms of supply, we don't have the overnight supply that we'll want. Probably that is going to come from other types of distributed energy resources that a lot of the country doesn't have, so they will have to look elsewhere.”

A report from Columbia University’s Sabin Center for Climate Change Law analyzed local and state opposition to renewable energy projects and found it has significantly increased in the last year, with 55 new local restrictions since last May. 

The Sabin Center assessed local restrictions spanning back to 1995 and found a total of 395 restrictions severe enough to block projects across 41 states. The center’s last report on the issue, published May 2023, found 340 restrictions. Severe state-level restrictions are “far less numerous,” the report says, and it logs 19 of those.

“The volume and nature of the restrictions and controversies cataloged in this report demonstrate that local opposition to renewable energy facilities is widespread and growing and that it represents a potentially significant impediment to achievement of climate goals,” the report asserts.

The report authors define restrictions as “temporary moratoria; outright bans; regulations, such as extreme setback requirements or height limits, that are so restrictive that they can act as de facto bans; and zoning amendments that are designed to block a specific proposed project.” The authors say this report “updates and considerably expands” three Sabin Center reports that were published in September 2021, March 2022 and May 2023.

Alaska is the only state “where no severe restrictions or significant controversies were identified,” the report said. Alaska, Utah and Tennessee are the only states with no contested renewable energy projects, while Virginia, Michigan, New York and Ohio each have more than 18.

In New York, several solar projects have been contested, while offshore wind project Empire Wind 2 received what the report calls a “significant setback” from the state when Gov. Kathy Hochul, D, vetoed a bill authorizing Long Island to allow project developer Equinor to lay transmission cables underneath parkland.

In Hochul’s veto message, she wrote that “it is incumbent on renewable energy developers to cultivate and maintain strong ties to their host communities throughout the planning, siting and operation of all large-scale projects.” In an email, spokesperson Katy Zielinski pointed to recent state progress on other offshore wind projects, including Empire Wind 1 and Sunrise Wind.

Offshore wind in particular has seen “significant litigation,” said the Sabin Center’s report. The 800-MW Vineyard Wind project offshore Massachusetts is facing four federal lawsuits in the First Circuit Court of Appeals, while eight municipalities sued the New Jersey Department of Environmental Protection over its review and certification of the Atlantic Shores project.

Litigants opposing the Atlantic Shores project say it could be harmful to the ecology of New Jersey’s southern shoreline, while the lawsuits against the Vineyard Wind project allege potential harms to the North Atlantic right whale. 

“The messaging tends to be that there hasn't been an adequate environmental review of this offshore wind project that spent years in environmental review, and the whales are not adequately protected, and that's the basis for a lot of the legal concerns that have been raised,” Boston Globe reporter Sabrina Shankman said during a June 11 webinar on offshore wind hosted by Environment America. 

Shankman said that although she sees “coordination” between opposition groups based on their shared members and messaging, she thinks much of the support is grassroots. The opposition to offshore wind appeals to “a lot of very well-intentioned people” who are seeing claims that make them concerned about potential ecological impacts.

“It's stuff that gives you a visceral response, but it can have the impact of slowing things down,” she said.

As the Biden administration aims for a U.S. net-zero emissions economy by 2050 and works to deploy up to $1.6 trillion in climate and infrastructure funding, efforts to update the permitting process for renewables, transmission and other projects are catalyzing intense debates, sometimes between those typically allied on policy issues.

Clean energy groups generally support streamlining the permitting process to accelerate the deployment of renewables, storage and other resources and help mitigate the immediate effects of climate change. But many environmental groups oppose permitting reforms that could also benefit the fossil fuel industry, or weaken the National Environmental Policy Act.

“[NEPA] has been seen as a vanguard for environmental justice communities,” said Anthony Rogers-Wright, a racial and climate justice advocate who has worked for ICF International and the New York Lawyers for the Public Interest. “It doesn't even go far enough, but it's still seen as a first line of defense for cultural communities and indigenous communities as well. And to see that being tampered with now — it's like, for some, almost akin to tampering with Social Security.”

The high stakes of this conflict have “brought us to this phase where we're starting to see a lot of headbutting and a lot of lines being drawn, and philosophies and approaches that come with those respective lines,” he said.

From an environmental justice perspective, removing roadblocks to permitting and siting projects could endanger communities that are already burdened by pollution, advocates say.

“In some cases, we do want these analyses to be long. We don't want them to be rushed. We're talking about critical resources, and activities that require disturbing soil and disturbing landmasses,” said Rogers-Wright.

Costs, delays and uncertainty

Advocates for permitting reform, on the other hand, argue that the current demands placed on project developers can not only be burdensome but unhelpful to the communities they’re supposed to protect.

In a 2022 analysis, the Institute for Progress argued that NEPA in its current form “imposes massive costs on the federal government, drags clean energy projects out for years, and generates uncertainty that stops other projects from ever getting off the ground.”

Alec Stapp, a co-founder and co-CEO of IFP and one of the authors of that report, said he advocates for a “strong” permitting process that also offers certainty and efficiency. 

“I think you could describe a strong permitting process as one that provides a quick and informed answer on whether a project has government approval to be built — a very swift and certain ‘yes’ or ‘no’ on whether you can build this project,” he said.

Stapp said that an efficient permitting process with imposed time limits would be “strong,” but “antithetical to what the environmental activism groups want, which is a tool that they can use to stop projects that they don't like.”

Those groups want it to be “easy to leverage [the permitting process] to stop bad projects that they don't want built at all,” he said — projects like “pipelines, new natural gas facilities, and export terminals.”

Stapp said he supports the use of categorical exclusions to the NEPA environmental review process — a category which the Environmental Protection Agency defines as “actions that a Federal agency has determined, after review by [the White House Council on Environmental Quality], do not individually or cumulatively have a significant effect on the human environment.”

In April, the CEQ finalized a rule to update the federal environmental review process under NEPA, including “new and more flexible methods for agencies to establish categorical exclusions to speed up low-impact projects” such as solar, electric vehicle charging infrastructure and transmission, the White House said in a release.

Earlier that week, the Department of Energy had issued a final rule establishing the Coordinated Interagency Transmission Authorization and Permits, or CITAP, program, which will make DOE the lead agency handling permits for new transmission projects. 

Congress is also tackling permitting reform, with 10 bills introduced in this session alone, but the bills have struggled to advance despite bipartisan calls for action. Sens. Joe Manchin, I-W.Va., and John Barrasso, R-Wyo., announced May 21 that they would soon share a new draft of bipartisan permitting reform legislation with colleagues.

Manchin remarked that the Federal Energy Regulatory Commission’s recently-issued transmission planning and cost allocation reform rule was, “as my friend Senator Hickenlooper said … ‘a Band-Aid on Congress’s inaction.’”

Stapp said he wants to see reform that ends “the litigation doom loop that all kinds of projects are trapped in right now.” He noted his concerns about the uncertainty faced by project developers and their financiers, as well as lingering questions about the fate of the massive investments represented by the CHIPS Act, the Infrastructure Investment and Jobs Act and the Inflation Reduction Act.

“Is that money turning into steel in the ground?” he asked. “Are projects actually being built in the real world? Or are these just large dollar contracts that have been spent, but are now stuck in permitting purgatory? .... We by no means have final answers here, but we are starting to see some warning signs.”

Stapp added that the president himself “has been reported to be concerned that there’s not enough groundbreakings for new projects that are funded by the infrastructure bill or the IRA.”

“I share those concerns — like, where are the real projects?” he asked. “There's lots of investment. But there seems to be quite a lag in terms of actual real world deployment.”

Rogers-Wright said he thinks there is a political element to permitting reform supporters “on the liberal side of environmentalism ... because many of these people have staked their reputations” on the IRA with “very, very little time to show that it is actually beneficial and efficacious, because there's an election coming up in November.”

Community input and environmental justice

Denae King, an associate director and researcher at Texas Southern University’s Bullard Center for Environmental and Climate Justice, said permitting reform is a priority and the center is “really grateful” for the White House and EPA’s recent moves on the issue. However, thorough environmental reviews remain “extremely important,” she added.

“Oftentimes, in environmental justice communities, there are already several sources of industrial pollution, or sources of contaminants in air or water,” she said. “So really understanding cumulative impacts is becoming more and more important, and this permitting reform does that. I think the other thing that it does is promote meaningful public input.”

The new rule from the White House removed NEPA provisions that it says “created litigation risks and jeopardized community input” by “removing detailed and onerous requirements on what public comments must contain to be considered by agencies” and “removing provisions that attempted to curtail judicial review.”

King said that the public comment period for projects in development is often “short and not well advertised. So by the time [communities] actually get to have some input, it's not necessarily valued at that point…. After the developer has drawn a full map and already decided how the facility is going to be placed and located, it's a little too late to ask the community.”

That disadvantages both developers and communities, she said, as the former may end up sinking costs into an ultimately untenable project.

“Community members are experts,” King said. “They really have a good grasp on what's happening in their community, both in terms of their routes of exposure, and what kinds of health impacts they're seeing in their school, in their neighbors.”

Renewable project opposition

When it comes to the permitting of wind and solar projects, visual and noise complaints often drive community opposition, according to a May 22 report from the The Hamilton Project. 

The report cites a 2023 paper from David Adelman, the Harry Reasoner Regents Chair at the University of Texas at Austin School of Law, which found that “litigation pressures against offshore wind [have] occurred in northeastern rural communities where residents place a high premium on protecting local landscape.”

“Other times, the renewable energy transition threatens existing local economies,” the report noted. “In Kentucky, coal is the most powerful political incumbent, in part because mining supports thousands of workers and their families each year.”

Chirag Lala, director of energy at the nonprofit Center for Public Enterprise, said he views the permitting reform issue as one of efficiency — making sure that community-level input flows upward in a way that lends itself to the best decision-making possible.

“The problem isn't stakeholder engagement,” Lala said. “And I do think there are some groups engaged in the permitting reform debate who either explicitly or border on suggesting that stakeholder engagement is the problem. It’s very much not.”

In an ideal world envisioned by CPE, Lala said there would be “a lot more” automatic permissions for projects, categorical exclusions, and “situations where public agencies are often in a privileged position to either gain the permitting and siting permissions that they need, or certainly to choose certain types of private projects that can get automatic or expedited permissions.”

“But, crucially, we don't see the fact that these communities need and want to raise certain concerns about how investment processes are going as itself the obstacle,” Lala said. He said existing permitting processes are what “is not servicing their needs in that respect.”

Lala suggested that issues such as environmental justice concerns, pollution cleanup and the employment of local workers can be addressed by policy mechanisms other than the permitting process itself. 

“But I think there is also just quite a bit of distrust out there over what the terms of permitting reform will be, and where they will head from here,” Lala added.

Both Lala and Stapp suggested that “veto power” legal mechanisms like injunctions have the potential to threaten community benefit agreements reached between communities and developers, even when the “veto power” is being exercised by a third party like an environmental group. 

In a process with no backstop authority, Lala said, “when different groups engage in that process, they do so knowing that just the very fact that they are filing a particular piece of paper, raising a particular objection, or attending a particular meeting could in and of itself create enough friction for a project not to go through.”

“Whereas if you have an entity that can intervene in the process at a certain point and just say, ‘Look, this is going through, everybody has said what they needed to say’, that changes certain actor incentives in that process,” he said.

Rogers-Wright, however, said he fears a shift to a more unilateral decision-making process would disenfranchise those who are directly impacted by those decisions.

“When you don't have a voice, when you're not a part of the process, you tend to be sacrificed,” he said. “If you speed the process up, that means you're going to be reducing [input] vastly — and that's already problematic, right? It’s not like so-called public participation is at an optimal level.”

A last-minute change to the Inflation Reduction Act of 2022 expanded opportunities for for-profit businesses, partnerships and some nonprofits to sell clean energy tax credits to eligible buyers. 

The U.S. Department of the Treasury on March 5 released final rules governing these sales, also known as tax credit transfers. These final rules set the stage for the market to continue accelerating rapidly, according to Crux CEO Alfred Johnson.

A simpler way to monetize clean energy tax credits

Johnson, whose company connects tax credit buyers and sellers, elaborated on the opportunities created by the IRA’s tax credit transferability mechanism in an interview with Facilities Dive. 

The biggest change, he said, is that eligible taxpayers can now directly transfer or sell 11 different clean energy credits to eligible buyers, including the Section 45 renewable energy production tax credit, the Section 48 energy investment tax credit and the Section 30C alternative fuel refueling property credit. 

Previously, most tax credit buyers were investors in tax equity partnerships that took stakes in clean energy projects in exchange for tax benefits such as credits or depreciation, Johnson said. Since these types of tax equity transactions are complicated, time-consuming and costly, the pre-IRA pool of potential tax credit investors was effectively limited to “financial institutions or insurance companies with large, predictable tax liabilities,” he added.

The new, simpler IRA structure has broadened the market, attracting interest from a wider range of companies interested in buying IRA tax credits, Johnson said. He noted that participants now include not only some of the largest companies globally, but also smaller public companies, private businesses and family offices.

ITCs are generally worth 30% of the “qualified investment basis” if the project meets prevailing wage and apprenticeship requirements, according to the IRS. Certain bonus credits, covering projects that use domestic content, serve low-income communities or operate in energy communities historically dependent on the fossil fuel industry, can push the total credit value to 50% or beyond, the IRS says.

However, “[credit] sellers generally need to prove their qualification for the bonus credit amounts and this is often a key diligence item,” Johnson cautioned.

More credits, more buyers and sellers

The deal value of tax credit transactions was an estimated $7 billion to $9 billion in 2023, according to a market intelligence report Crux released in January. “Tax credit transfer volumes in 2024 may significantly exceed last year,” the company said in an April 3 update, noting that buyers placed over $1.5 billion in bids on its platform in the first quarter of 2024. In a subsequent white paper, Crux predicted that tax credit transaction volumes could reach about $85 billion in tax attributes per year by 2031. 

Tax credit sellers now able to take advantage of the transfer mechanism include renewable energy developers building projects too small for traditional tax equity, companies that “have built some kind of energy infrastructure to power a data center or facility [but lack] the internal need for credits” and companies selling credits “associated with merchant battery storage, EV charging infrastructure or another category that has not traditionally been financed via tax equity,” Johnson said.

The most common type of credit Crux saw last year was the 45X advanced manufacturing production credit, followed by the solar ITC, Johnson said. He noted that the solar ITC, which falls under the Section 48 framework, “is available for a wide range of solar projects, from large utility-scale installations to smaller portfolios of community solar or residential solar projects.” 

This year, Crux has been seeing “newly available tax credits … hit the market in volume, including the 45Q carbon capture credit and the 45V hydrogen production tax credit,” Johnson added.

Because the tax credit transfer mechanism is more straightforward than traditional tax equity financing, individual deals can be smaller, Johnson said in an April interview on the Volts podcast. Whereas the minimum deal size for tax equity financing is typically around $50 million in credit eligibility, “the majority of transactions that we tracked were below $50 million in size, suggesting that transferability is leveling the playing field,” Johnson told Volts host David Roberts.

Nevertheless, the tax credit transfer market will likely skew toward larger deals in the near term, said Paul Gordon, a tax financing specialist and partner at Morgan Lewis. 

“The market is developing in real time,” with most deals still directly negotiated between counterparties, Gordon said. Most buyers today are larger corporations that need at least $10 million to $20 million in tax credit eligibility to “move the needle,” he said.

But the transferability mechanism will “democratize” within three to five years as aggregators, or syndicators, create a more robust, standardized market for smaller deals that they can pool together, Gordon predicted.

While Crux doesn’t aggregate tax credit transfers itself, its website touts its benefits for banks, syndicators and advisors who can use its “purpose-built workflows” to connect buyers and sellers in their own client networks. 

For non-syndicated buyers and sellers, Crux has a “suite of standard documents [and] due diligence infrastructure” to streamline tax credit transactions, Johnson said. When a buyer and seller match up and agree to proceed with a deal, Crux acts as a facilitator, handling “structured data uploads” and offering an in-platform messaging tool to manage the “hundreds of emails” buyers and sellers typically exchange, Johnson noted on the podcast. 

Discounts, insurance and political risk

Tax credits typically trade below their face value, Gordon said. ITCs representing one-time investments in new energy projects or assets usually sell for 90 cents to 92 cents per dollar for standard-risk projects, for less than 90 cents per dollar for higher-risk projects and occasionally up to 95 cents per dollar for lower-risk projects, Gordon said. PTCs, which are based on production from existing projects and offset the holder’s tax liability for multiple years, often go for 95 cents or 96 cents on the dollar, he said. 

In both cases, larger deals tend to have smaller discounts, Gordon added.

ITCs’ steeper discount stems in part from the inherent risk involved in newly developed projects, Gordon said. One of the biggest issues is that the IRS can “claw back”, or recapture, the tax credit on a project if its ownership changes during its first five years of operation, S&P Global noted in an analysis last month. 

Another challenge with ITC transactions is the uncertain value of the credit before the project is completed, Johnson said in the Volts podcast. Cost calculations before a project goes into service tend to focus on “hard costs” and can’t account for “observable market data that your project is worth more” once it becomes active, he added.

A related issue is basis risk, which occurs if the IRS decides that a project has “overstated its cost basis” and determines that the associated credit value is lower, Johnson said. 

Production credits are also more flexible than ITCs, allowing the holder to transfer “some or all of the credit each year” as long as payments for future tax years aren’t made in advance, said Don Lonczak, a partner and tax transaction specialist at Pillsbury Winthrop Shaw Pittman. 

Despite the flexibility and lower upfront risk of production credits, most tax credit transfers he has seen so far have been ITCs, Lonczak said. “There’s more certainty around what you’re getting there” due to the one-time nature of the credit, though “I don’t think I can say that’s indicative of a trend” in future transaction volumes, he said. 

PTC deals may feature discount rates that increase over time as a hedge against the uncertainty of calculating production years in advance, Lonczak added. 

That future uncertainty has a political dimension, Gordon said. While “retroactive changes” affecting existing projects are unlikely in the event of full Republican control of the federal government in 2025, lawmakers could amend the IRA to phase out its tax credits faster or “de-sweeten” its benefits in other ways, Gordon said.

“You have to have a political crystal ball” to look beyond the November election, he added.

While most credit transactions see the seller indemnifying the buyer against potential losses, buyers can purchase insurance to reduce their risk further, Lonczak said. 

“Buyers typically do not have any input or control over project operations, and so insurance plays an important role [in] protecting the buyer from risks they couldn’t otherwise mitigate,” Johnson said.

Insurance has been available on traditional tax credit transactions for many years, but there is now “a huge gold rush for the insurers” as the transferability market scales up, Gordon said. He added that a “full-wrap” policy, which protects the buyer from virtually any risk not caused by their own error, costs roughly 1.5% to 2% of the credit amount.

Sellers “are generally responsible” for taking out the policy and paying the premium, Johnson said.

Clean energy developers’ demand for skilled construction labor is outstripping the supply amid an onslaught of new projects and competition with other industries, according to panelists at a May 9 session of the American Clean Power Association’s Cleanpower conference in Minneapolis.

The Inflation Reduction Act’s support for apprenticeships and longer-term renewable energy tax incentives has boosted worker and employer confidence, but persistent training deficits, diversity challenges and negative perceptions of the construction industry hinder efforts to expand the talent pipeline, panelists said.

“It’s no longer enough for us just to create the jobs,” said Martha Ontiveros, senior vice president for human resources at Pattern Energy. Growing a durable clean energy workforce “will require a multi-stakeholder process,” she added.

The Inflation Reduction Act, CHIPS and Science Act and Infrastructure Investment and Jobs Act are fueling demand for construction and skilled trades workers, according to a February study by the Political Economy Research Institute at the University of Massachusetts Amherst.

Meeting the demand will require developers and engineering, procurement and construction firms to improve internal training programs, expand partnerships with unions and community colleges and try “out of the box” recruiting tactics, said panelist Matthew Tetrault, senior vice president for operations at MasTec Renewables.

The construction sector has the highest concentration of occupations likely to face shortfalls as funding authorized by the IRA, IIJA and CHIPs acts works through the U.S. economy, PERI found. Among occupations with significant representation in construction, the institute projected a shortfall of 91,500 first-line construction supervisors, 60,850 first-line supervisors of mechanics, installers and repairers, 31,250 power line installers and repairers and 173,600 heavy truck drivers.

The clean energy industry is competing for these workers “against every other industry that seems to be booming” today, said panelist Jesse Canzler, vice president and general manager for wind energy at Mortenson, which he said employs between 3,000 and 5,000 craftspeople in clean energy construction.

“People aren't raising their kids these days with ambitions to go into construction,” he said.

Among workers who do see their future in construction, clean energy developers and construction firms must compete against industries that require less travel and offer better work-life balance, like residential construction, Tetrault said.

Developers and construction firms can use that impulse to their advantage on jobs closer to towns and cities, Canzler said. Hiring more workers “who can go home at night” cuts down on per-diem and travel expenses, he added, noting that population centers may have fertile recruiting grounds — like bouldering gyms filled with people who “want to climb wind turbines all day.”

For more remote sites with limited local labor pools, employers can leverage network effects in traveling workers’ home communities. Those workers can be effective recruiters simply by showing their friends and neighbors that “you can make [life on the road] work at home,” Canzler said.

Developers that also own renewable generation resources can attract construction talent by providing pathways into operational roles, Ontiveros said. That’s a selling point for some 1,500 contract workers on Pattern Energy’s SunZia wind and transmission project, which will require 150 permanent operations jobs after construction, she added.

To retain construction talent in occupations with apprenticeship programs stretching three years or longer, employers need to keep employees engaged and challenged, Tetrault said. A typical MasTec apprenticeship, he said, is about 75% on-site cross-training — switching workers between mechanical and civil roles on the same project, for example — and 25% off-site training at its job centers in Dallas and Amarillo, Texas. Yet keeping apprentices in the program is challenging because they can flourish in other roles without such a “long runway,” he said.

Four-year universities, community colleges and technical schools are strong partners for companies that need operating talent, but less- so on the construction side, panelists said.

“That doesn’t appear where [educational institutions are] focusing,” and may not even be aware of the need, Canzler said. The construction industry as a whole has “done a bad job of PR,” he noted.

“It’s not that they’re saying ‘no’ to us,” Tetrault said. “It’s more like, ‘Tell us what you need.’”

Before the session closed, panelists addressed diversity in the clean energy workforce. “We’re not great at it … we know we need to do better,” Tetrault admitted. 

MasTec’s partnership with UnidosUS has helped it attract Hispanic employees, Tetrault said. But the company’s workforce is only about 10% women, largely on the solar side, he added.

Mortenson’s higher-skilled craft workforce is “40% diverse,” but only 5% to 7% women, Canzler said. “We are missing half the population because nobody wants to be the only one.”

But attracting women, workers of color and other historically underrepresented groups is only the first step, Ontiveros said. Clean energy employers need to be ready for these recruits with internal affinity groups and other forms of support “or we will lose them as soon as we hire them,” she said.

U.S. offshore wind is at an “inflection point” and poised for “liftoff” but has not yet achieved it, the Department of Energy said April 24 in a report on the industry’s progress toward full-scale commercialization.

“U.S. offshore wind will achieve ‘liftoff’ when the sector is actively contributing to decarbonization targets, with a sustained project pipeline and regular deployment,” DOE said in its one-page summary of the report. “There is a clear path to scale, with [around] 50 GW-worth of U.S. seabed already leased to developers (more planned), and early project deployment advancing rapidly.”

Full-scale commercialization by DOE’s standards involves three overlapping phases: a committed demand pipeline for long-term offshore wind offtake agreements, followed by the deployment of the first 10 to 15 GW of U.S. projects, then steady deployment and continued supply chain expansion.

“In the fixed-bottom wind market, phase 1 is on track for liftoff, phase 2 is underway, and phase 3 will follow soon,” DOE said.

The report adds that the market for floating offshore wind — a technology that will be required in the deep waters off the West Coast — is at an “earlier stage,” as the path to deploying it still requires more infrastructure planning.

“Enabling infrastructure will be key to liftoff, across both fixed-bottom and floating wind markets,” DOE said. “This includes critical supply chain links: the availability of ports and vessels will set the annual deployment potential of the U.S. market, and widespread expansion across component supply chains will be required to support growing demand both in the U.S. and abroad.”

The report addresses recent market turbulence in the sector, which resulted in the cancellation and delay of several projects in 2023. Last week, New York cancelled provisional awards for three offshore wind projects, citing GE Vernova’s decision to pivot away from a planned 18-MW turbine model as a contributing factor.

“Early mover projects faced a “perfect storm” of challenges and have provided valuable lessons on how to sequence and structure investments for a sustainable offshore wind industry,” DOE said. 

Projects that aimed to reach final investment decision from 2023 through 2026 “have seen the greatest risk exposure, while the longer-term pipeline has less risk of cancellation due to (1) 2020s project and infrastructure buildout (2) stabilizing macroeconomic headwinds, and (3) risk mitigations by states and developers,” the report said.

“Lessons learned from the challenges of the past few years will shape the market moving forward,” DOE said. “These include ongoing efforts by states and industry to refine project and supplier procurement, fostering regional collaboration for supply chain and transmission planning, and government investments to support necessary enabling infrastructure.”

The report is the ninth in a series of ‘liftoff’ reports from DOE that are examining “how and when various technologies could reach full-scale commercial adoption.” DOE has also released reports on advanced nuclear, clean hydrogen, long-duration energy storage and virtual power plants, among other topics.

Along with the liftoff report, DOE’s Wind Energy Technologies Office announced plans to spend $48 million to fund projects that “address several major areas of need” for offshore wind.

These areas include “advancing U.S. academic leadership in floating offshore wind”; research and development into offshore wind platforms; expanding the reach of the domestic supply chain; and new monitoring technologies for the protection of offshore wildlife.

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.

The market volatility of the past few years may be behind us, but prompted renewable energy developers to take a more targeted approach in the second half of 2023, said Patrick Worrall, vice president of M&A solutions at LevelTen Energy.

Renewable energy asset acquisitions slowed significantly in late August and early September of 2023, according to LevelTen Energy, which declined to release specific pricing figures on the belief that historical data no longer provide a relevant comparison in today's markets. The pace of transactions is beginning to pick up again, Worrall said, but renewable markets seem unlikely to return to their previous norms.

Renewable energy developers have historically focused on the numbers game, trying to grow large project pipelines to increase their odds of success, Worrall said. But given the increased cost of capital, developers are now taking a more strategic approach to project acquisitions.

Supply chains and capital markets seem likely to stabilize in the coming year, but the volatility of the past few years has left a permanent mark on renewable energy markets, Worrall said.

Historically, renewable energy developers large and small have tried to build and acquire as many renewable energy projects as they can, Worrall said, creating what he described as a “land-grab” mentality among renewable energy companies. While that's typical of a young industry, he said, the interest rate hikes of the past year prompted developers to take a hard look at this business strategy.

For most of the past decade, developing renewable energy was relatively cheap, Worrall said. Particularly in recent years, renewable energy developers have also had to contend with the low odds of success in interconnections queues. The Lawrence Berkeley National Laboratory estimates that only 20% of projects that enter queues around the nation are ultimately built.

In that kind of environment, Worrall said, it made sense for renewable energy developers to hedge their bets and tee up as many projects as possible, knowing that perhaps one in five will actually see construction.

But last year, interest rates rose 2% in a period of just two months, Worrall said. Developers also face rising interconnection deposits and other costs, which has made maintaining a large pipeline of pre-construction projects much more expensive. And that has renewable energy companies reconsidering the wisdom of large development pipelines, Worrall said.

“All of the sudden both large and small players looked at their pipeline and said wait a second, what are we doing? Should we be more disciplined in where we are focusing our energy?” he said. “You have big developers talking about 30 GW in their pipeline.... Is that a good use of time and capital to be trying to manage a pipeline of that size?”

Although this shift caused developers to pause asset acquisitions last fall, Worrall said there is still demand in the market for certain kinds of projects. Many of the projects that were slated for construction in 2024-2026 were delayed by the volatility of the past few years to 2027 and beyond. This has created a glut of projects with post-2027 construction dates, but a shortage of those that could be completed in the next two to three years. Developers remain interested in these quicker-turn projects, triggering a bidding war that has driven up prices.

For projects that won't begin construction until 2027 or beyond, prices continue to fall, Worrall said.

Although PV module prices have begun to stabilize over the past few years, the going price for power purchase agreements, or PPAs, remains unsettled, according to data from LevelTen Energy and other industry analysts.

Solar PPA prices rose on average 3% in the final quarter of 2023, and wind PPAs rose 5%. But price trends vary widely across different regions of the U.S. — the California Independent System Operator saw solar PPAs jump 15% while PPA prices fell in the Electric Reliability Council of Texas, the Midcontinent Independent System Operator and the Southwest Power Pool markets.

Even within California, PPA prices have begun to diverge depending on the anticipated completion of the project to which they are tied, according to Anthony Boukarim, director of resource planning and valuation for Ascend Analytics. Demand from corporations with time-sensitive decarbonization goals may be driving the trend, he said.

Overall PPA prices likely remain on a long-term, downward trend, according to Ascend Analytics. But for the time being, data from the LevelTen Energy marketplace suggest the market remains somewhat turbulent.

Solar supply chains have recovered over the past year, and solar PPA prices eased in most of the U.S. as a result, according to LevelTen. Yet solar PPA prices in California spiked 15% in the fourth quarter, leading to an increase in the national average. Wind PPAs saw a similar phenomenon — prices rose 8% in ERCOT and 18% in SPP, but fell 6% in CAISO and 1% in MISO, according to LevelTen.

On the solar side, much of the increase can be attributed to intense demand for clean energy in California, where various load serving entities and corporations are competing for a limited number of contracts in order to meet various decarbonization deadlines, Boukarim said.

Wind prices showed even greater variability in the final months of 2023, with differences between individual projects driving regional averages.

“A lot of this variability comes down to project-by-project dynamics and differences in developer-specific pricing strategies and costs, rather than an overall industry trend,” said Samuel Mumford, an energy modeling analyst at LevelTen Energy.

Demand for clean energy remains steady even in regions posting significant price increases, which could mean that buyers believe energy prices could increase even further in the future, Mumford said.

But Robert LaFaso, director of valuation and forecasting at Ascend Analytics, said there might be another explanation: today's relatively limited supply of clean energy projects has created a seller's market in a world where many states and corporations aim to cut emissions on relatively short deadlines.

“If I start developing a project today, the earliest I could get COD is 2028, so there is a lag in asking for supply and that supply showing up to the market,” LaFaso said. “Sellers have a decent amount of power right now from a contracting perspective for renewable energy. As more supply comes on, there should be substantially less sale power.”

Indeed, even in California, contracts for projects that don't expect to be completed until 2028 or later are commanding much lower prices, Boukarim said.

Boukarim said Ascend Analytics believes PPA prices will continue to fall modestly for the next few years, driven by the potential for decreased interest rates and incentives from the Inflation Reduction Act. Then by the mid-2030s, prices may begin to rise again on the expected phase-out of IRA-related tax credits.

However, LaFaso said it is unlikely that PPA prices will return to their pre-2020 lows.

“We don't see a way to get back there,” he said. “The IRA just undoes a lot of the inflationary issues we've had over the past few years.”

Engineers are readying the U.S. power system for a 2024 boom in clean energy integration propelled by Biden administration goals and funding, utilities and industry analysts report.

As penetrations of variable wind and solar generation rise, sudden and periodic demand spikes and technical fluctuations in current become more of a threat to reliability, researchers and utility sources agree. New ways of managing bulk system clean energy with control room and communications technologies that integrate customer-owned resources to balance supply and demand can alleviate those threats, the sources said.

“Antiquated market-based laws and rules don’t recognize the value” of integrating new technologies and resources, said Association of Edison Illuminating Companies, or AEIC, Vice President, Technical Strategy, Elizabeth Cook. “Unlocking the real capabilities of today’s system requires seeing it as a whole from bulk system resources to customer load and customer-owned resources.”

Some utilities are exploring new technologies and strategies to integrate system-wide operations and dispatch.

“We are actively considering not only which technologies to use, but where and when to deploy them” to optimize “not only the distribution system but ultimately the bulk system as well,” said Xcel Energy Spokesperson Kevin Coss.

Potent new tools and practices, like system enhancing power flow tools, advanced communications, and data analytics on customer behavior, are not yet widely deployed, Cook, Coss and others acknowledged. But Department of Energy research simulations and power provider pilots are beginning to verify a much higher potential to integrate and benefit from bulk and distribution system clean energy, they added.

The emerging system

Despite ongoing supply chain disruptions, clean energy investment in the U.S. reached a record $64 billion in the third quarter of 2023, up 42% over Q3 2022, according to a Dec. 7 Rhodium Group report.

And that investment spike is just the beginning, projections show. Achieving the Biden administration goal of a zero-carbon power sector by 2035 could require a quadrupling of the projected annual growth rates of solar and wind, according to a recent National Renewable Energy Laboratory, or NREL, report. That growth will change the U.S. power system, analysts said.

“There has been more change in the past five years than in the 50 years before and it is accelerating,” said Kevin Schneider, laboratory fellow and manager of a subsector of the Pacific Northwest National Laboratory Office of Electricity. “The emerging system will be more automated and operate under a wider range of conditions with higher customer expectations than ever before,” he added

That means increasing challenges to reliability from variable utility-scale renewables and uncertain customer-owned generation and load, utilities and industry analysts agree.

Smoothing variability

The importance of geographic resource diversity and the need for resource sharing to manage higher clean energy penetrations are well understood, researchers at NREL and the Pacific Northwest National Laboratory, or PNNL, reported. And resource and load forecasting and bulk system ramping capabilities are improving, according to the labs.

Entering 2024, a new emphasis on inter-regional transmission to increase access to lower cost clean energy could reduce the use of more expensive fossil fuel generation, saving customers tens of billions of dollars in generation and transmission costs, according to a November Grid Strategies study.

But new transmission is not being built because of interconnection, permitting, and other regulatory and economic obstacles, Grid Strategies President Rob Gramlich told the Volts podcast Nov. 17. Grid-enhancing technologies that optimize power flows and new high-performance conductors that carry more current can, however, be deployed immediately to “get more throughput from existing transmission,” Gramlich said.

Increasing the efficiency of existing infrastructure to deliver utility-scale clean energy also avoids the need for “new rights of way on undisturbed land,” Gramlich continued. Regulators could consider rewards for deploying the new technologies and penalties for not considering them, he said.

But technologies that integrate more variable and distributed renewables increase the threat of steeper or unexpected demand spikes due to daily resource availability changes or extreme weather conditions, engineers said. Energy management and communications systems and strategies that assimilate and respond to the growing mass of supply-demand data coming to control rooms could be the solution, they said.

Managing demand spikes

Increasingly steep or unexpected customer demand spikes are the immediate challenge from renewables integration because resource availability can be compromised by the setting sun, fading wind, or extreme customer demand from extreme weather, researchers, system operators and utilities agree.

DER Management Systems, or DERMS, technologies available to utilities are not yet capable of optimizing the needed integration of bulk and distribution system resources, Xcel Energy Senior Vice President, System Strategy and Chief Planning Officer, Alice Jackson told Utility Dive last year.

But Xcel continues to invest in and investigate DERMS and other energy management systems, Xcel’s Coss added. The goal is technology that will “benefit not only the distribution system but ultimately the bulk system,” he said. 

Eversource Energy is deploying DERMS in its Massachusetts territory to integrate the more than 1 GW of installed distributed energy resources, or DER, and the 1 GW of DER in its interconnection queue, reported Jennifer Schilling, the utility’s vice president of grid modernization. But using DERMs as part of utility operating systems is “emergent” and “dispatching customer-owned DER as a grid asset will require compensation frameworks” approved by regulators, she said. 

In 2024, “DERMS is a marketing term” for tools that “provide the ability to dispatch DER,” added PNNL’s Schneider. Utilities may eventually meet 30% or more of their load from distribution-level resources, which means “integrating variable renewables has to be addressed within the entire system to optimize for reliability and resilience and avoid unintended consequences,” he said.

A system “operationally flexible enough” to integrate current and future bulk and distributed system resources may require an independent Distribution System Operator, Schneider continued. But in 2024, “it is not yet clear how that entity would operate, who would operate it, what the extent of its responsibilities would be, or how it would monetize the services it would provide,” he added.

Without a specifc comprehensive tool to manage distribution system flexibility, utilities can enhance multiple capabilities to build system visibility and control, utility engineers agree.

“Advanced technologies, greater computational power, new communication systems, and power flow solutions turned the transmission system into the world’s biggest machine,” said AEIC’s Cook. The failure to evolve new approaches for variable and distribution system resources “is stunting the power industry’s ability to integrate them,” she said.

“A framework for the system as a whole can optimize all the resources on the system, based on their physical capabilities and technical feasibility,” Cook continued.  “But dispatch today is being optimized by models based on energy market prices instead of the granular, real-time data that shows the capabilities and values of new assets,” she said.

One key technology solution, already being deployed by some utilities, is private 900 MHz spectrum LTE broadband networks, Cook said. That would increase the control room’s system awareness and speed its responses as conditions change due to renewables variability.

San Diego Gas and Electric is deploying wider-area, lower latency communications and analytics to similarly enhance its network’s capabilities, Humberto Gurmilan, the utility’s communications manager, sustainability projects and initiatives, said.

Duke Energy’s integrated supply and demand planning includes “future deployment of predictive analytics, sensors, and communication with machine learning,” Duke’s Vice President of Integrated Grid Strategy Emily Henson said.

“Advanced communications will be essential for some utilities soon, and some utilities may not need them for a decade or more,” said PNNL’s Schneider. Deployment will depend on decisions made by regulators about the value and high capital cost of networks, but eventually “a secure, reliable, and resilient communication infrastructure will be needed” to manage higher levels of variable renewables, he added.

Advanced communications can also allow utilities to understand “customer impacts at the transformer that could overload or protect that transformer,” Cook noted.

And to protect against overload-induced outages, there is renewed interest in inverters that will allow variable renewables to replace traditional generation in stabilizing the power system, Cook added.

Stabilizing the system

Inverters convert renewables-generated energy into the transmission system’s alternating current, and grid-forming inverters have power electronics that can stabilize frequency fluctuations and voltage changes, engineers with the North American Electric Reliability Corp. and Energy Systems Integration Group, or ESIG, recently told Utility Dive.

Historically, traditional power plants have stabilized frequency and voltage but they are being retired and replaced by utility-scale renewables that, without grid-forming inverters, do not provide stability, a November 2020 NREL paper reported. As the transition to renewables has accelerated, reliability threats have increased, according to NERC.

The recently released NERC three-year plan for developing reliability standards is a response to a Federal Energy Regulatory Commission October decision to address incidences of renewables tripping offline when system conditions caused frequency fluctuations.

System operators can reliably integrate no more than an estimated 75% penetration of variable renewables without grid-forming capabilities, according to ESIG Chief Engineer Julia Matevosyan. But with grid-forming capabilities, the “stability services” can avoid abnormal operating conditions that threaten outages if voltage drops destabilize system frequency, she added.

Deploying utility-scale batteries with grid-forming capabilities “is a low-hanging fruit solution,” to bringing more stability to high renewables systems, Matevosyan said in a March 2023 ESIG paper. A requirement that the over 400 GW of battery capacity in U.S. interconnection queues have grid-forming capabilities could enable variable renewables growth “cheaper and faster than adding new transmission to mitigate stability issues,” she said.

If the state of charge of batteries with grid-forming capabilities can be verified, they are “ideal” for stability and other system services, Xcel’s Coss said. The Electric Reliability Council of Texas will finalize performance requirements for grid-forming capable batteries in 2024, according to Matevosyan.

But “if a system’s grid-forming inverters are not properly coordinated, they could add to the instability,” cautioned PNNL’s Schneider. “The next few years will be about how to evolve the proper integration and control of all the new resources and eliminate resistance to new technologies that will improve the system for all its stakeholders,” he said.

“The system is going through a transformational change,” said AIEC’s Cook. But tools like grid enhancing technologies, high speed communications systems, and grid-forming inverters will alllow utilities to improve reliability and resiliency, and “they will grow in importance as economy-wide electrification increases peak demand and climate-driven extreme weather impacts become more frequent,” she said.