Shortly after President Joe Biden took office and began to develop his Build Back Better plan, leading solar companies formed the Solar Energy Manufacturing for America Coalition, or SEMA, lobby for industry-wide domestic content standards. But they didn’t have to lobby for long. The Inflation Reduction Act, which included many of the provisions the coalition hoped to see become law, was something of a dream come true — and it happened far earlier than anyone had thought likely.

With the IRA now in force and awaiting some implementation clarifications from the IRS, SEMA’s work, it seems, is just beginning. There’s no shortage of demand for renewable energy, and leading solar companies have begun to roll out major manufacturing expansion plans in the U.S. However, crafting the domestic solar energy supply chains of the future will require ongoing, concerted effort by industry and policy leaders — potentially up to five years before factories are up and running at scale, according to some industry experts. 

But after that, domestic solar manufacturers will have an established platform from which they might pursue other goals, such as developing new solar technologies, according to SEMA Coalition Executive Director Mike Carr.

Kicking U.S. manufacturing into high gear

Creating incentives for domestic manufacturing, whether in the form of the IRA or something else, was a critical first step toward building more stable supply chains with less reliance on China, Carr said. Although solar companies had considered the benefits of investing in manufacturing, he said, nobody had any plans prior to the IRA to move forward with major expansions in the U.S.

“The consensus was nothing was to happen, nobody was going to build anything,” he said. As the IRA began to look more certain last year, some companies began to fill in the details of what their own manufacturing facilities might look like. Some had even worked on a bit of site selection and had conditional plans in place. “They were able to say, if this passes we can build X,” Carr said. “And when it finally passed, that’s when everything kicked into high gear and the scramble started.”

The early announcements triggered by companies that had conditional plans in the works prior to the IRA have already exceeded “even my optimistic take,” Carr said. But he indicated that SEMA, through its membership, has a line of sight on even more manufacturing announcements expected to take place throughout the first quarter of 2023.

“Now that the political back and forth is behind us, people can get down to business,” Carr said.

His assertions align with data from the Department of Energy’s Solar Energy Technologies Office, which so far has recorded 18 solar manufacturing announcements representing more than 85 GW of annual capacity in response to the IRA. If realized, that manufacturing capacity would exceed the 50 GW the office expects U.S. solar installers to deploy annually in the years to come, according to SETO director Becca Jones-Albertus. Much of that manufacturing capacity could come online within the next three to five years, she said.

“Today only about 20% of the solar panels installed in this country are made here,” Jones-Albertus said. “We could see that become the majority...within a few years.”

But some manufacturers and financiers are holding off on manufacturing commitments while they wait for the final implementation guidance from the IRS on questions such as just what percentage of domestic content will be required to qualify for the full tax credit, according to Carr. It’s not as though the IRS is dragging its feet — they have a significant job on their plate — but some companies are reticent to announce their plans before the final IRA ink dries, Carr said.

Missing supply chain components

SEMA, too, has taken a keen interest in the IRA implementation outcomes — Carr described it as their current top priority. The goal, he said, is to find a proper balance between encouraging the creation of a fully domestic supply chain, all the way down to the raw components, and acknowledging the reality that even if we assemble panels here in the U.S., we don’t make any of the parts that go into them — or even the equipment required to assemble any of it.

So far, companies that have announced plans to begin or expand manufacturing in the U.S. have focused on one end of the solar supply chain —  panel assembly. Some wafer, cell and inverter manufacturing plans in the U.S. have also been announced, according to Jones-Albertus. But there’s still a need for domestic production of upstream components and raw materials, including polysilicon and glass.

“There are parts of the supply chain that could still use some [policy] support — solar glass is one that jumps out at you,” Carr said. “Most of the glass being used in solar panels in the U.S. is imported from China, but it just didn’t quite make it into the legislation. So the question is being asked, what more can we do?”

Even those raw materials that will receive incentives under the IRA’s advanced manufacturing production tax credit — aluminum for example — face headwinds beyond the competitive barriers that previously discouraged investments in manufacturing, said Lesley Jantarasami, managing director of the energy program at the Bipartisan Policy Center. Relatively common but critical materials like aluminum and titanium are in short supply due to the ongoing conflict in Ukraine, and all the incentives in the world can’t increase production overnight.

And it’s not just manufacturing itself that has trailed off, Jantarasami said. The U.S. lacks the expertise and skilled workers needed to make key materials, especially steel.

“It’s going to be harder to find those folks to do that work here in the U.S.,” she said. Workforce training will be critical, she said, but takes time — automation may be needed to help fill some of the gaps. And then there’s sourcing the minerals themselves.

“Nobody has seriously talked about how do we ramp up mining in this country for a long time,” Jantarasami said.

If the IRS standards on domestic content are too strict, Carr said, these barriers could make qualifying for the tax credits too difficult, which would ultimately limit the number of companies willing to invest in manufacturing. But on the other hand, a higher domestic content requirement might accelerate domestic production of upstream components. Carr anticipates that companies and investors will wait until 2025-2030 to determine if the demand for, say, U.S.-made solar wafers is sufficient to justify a second tranche of manufacturing expansions. Tighter rules from the IRS could move that decision time forward.

“You size a cell plant more or less according to what you expect to consume with module assembly,” he said. “If it looks like you will have to eventually secure a domestic supply of wafers, that would result in a bigger scale of those investments as well. Left to their own devices, investors will approach with a wait-and-see. If government shows full-bore commitment to filling out the supply chain and shows they’re going to turn all the knobs they can, that may be enough to make some of these investors think about moving a little faster on their phase two plans.”

Envisioning the domestic solar manufacturing of the future

For solar developers whose projects have hit supply chain snags, an expansion of U.S. manufacturing could not come soon enough. But parties looking to buy U.S. solar panels will have to wait a couple of years, according to John Smirnow, general counsel and senior vice president of supply chain and sustainability at the Solar Energy Industries Association.

Although some companies were able to get a jump start on the planning process, the reality is many still have to sort through a number of details before they can start manufacturing panels, Smirnow said. Site selection itself can be a two- to three-year process. But companies looking to break into solar manufacturing must also contend with rising energy prices, a shortage of suitable buildings, a labor shortage and, yes, supply chain constraints.

“We still think it will be three to five years before we see a critical mass of factories operating at scale,” Smirnow said. “We don’t make any of the machine tools in the U.S., so all those have to be imported.... There’s currently no cell manufacturing in the U.S., and what has been announced looks like it will be for internal consumption [by the solar companies that own the factories]. You have to think about supply chain issues and are you going to be subject to [penalties] under the Uyghur [Forced Labor Prevention] Act.”

For Carr, this suggests an ongoing role for SEMA in helping to stand up a domestic solar supply chain and continuing to lobby for supportive policies. The coalition’s members, which include companies like QCells and First Solar and represent more than 6,100 manufacturing workers, have found value in having a forum to discuss their challenges and opportunities with one another, and with policy members, he said.

And once the basics of a supply chain are in place, Carr said, SEMA may take on additional roles. The U.S. has already made significant investments in the research and development of new solar and renewable energy technologies — from manufacturing innovations that could cut production costs to new formats for energy generation. Who, Carr asks, will bridge the divide between an existing R&D complex that has never had an outlet, and the budding manufacturing industry?

With the coalition still buoyed by their unexpectedly early success with the IRA, Carr said, the members’ expectations for future collaborations are riding high.

“This is really the first time that manufacturing in these industries, which have been hollowed out for a while, has had the opportunity to speak with one voice and paint a picture of the opportunity here,” Carr said. “Not only did they come together, but Congress really listened and actually came through on a policy that a lot of people not that long ago thought would be impossible. That’s something to watch. If you can have people propose a policy and you get the outcome that you want, it can spark a lot of momentum.”

The first offshore wind lease sale conducted by the Bureau of Ocean Energy Management in the Pacific Ocean drew lower bid prices than similar sales on the East Coast, and experts say the outcome reflects the uncertainties faced by the offshore wind industry in California, but it could benefit ratepayers in the long run. 

“[This] definitely was not the super competitive auction that I was expecting,” given the excitement over setting up a California offshore wind industry, ambitious offshore wind planning goals adopted by the state, as well as the drive to get a floating offshore wind sector set up in the United States, said Samantha Woodworth, senior research analyst with Wood Mackenzie.

The lease sale drew winning bids from five companies that amounted to $757.1 million, for five lease areas that cover more than 370,000 acres off the coasts of central and northern California. BOEM estimates the areas could generate some 4.6 GW of offshore wind energy. The winning bids, however, came in at an average of $2,028 per acre — lower than the $2,861 per acre average from the auction held in the Carolinas in May, and the $8,951 average that resulted from leases in New York and New Jersey in February.

Many project developers realize that global supply chain issues and high inflation trends aren’t easing soon, making some wary of committing to massive investments, she said.

“Lower bid prices are a way of penny-pinching where developers can. And also, I think a lot of developers are [thinking] it’s kind of a weird time right now — let’s proceed with caution, let’s take it easy,” Woodworth said. 

But those lower bid prices could have an advantage — they translate to lower upfront costs for developers, which, in turn, could translate to lower power purchase prices for offshore wind that ultimately flow through to the electricity rates of consumers, as well as allow leaseholders to make investments in building an offshore wind supply chain in California. 

“So not only does it behoove the industry to keep those bid prices low, because it keeps their overall project costs down — but it also increases their probability of getting [the projects] approved by the powers that be, by the utility commissions [and] the state,” Woodworth said. 

Now, industry advocates say, California needs to work on creating a plan for permitting offshore wind projects, developing ports that can bolster the new industry and figuring out what transmission it needs to bring offshore wind energy on shore. 

Lease sale results: some surprises, some encouraging trends

BOEM’s California lease sale reflects “a significant milestone” toward the Biden administration’s goal of installing 30 GW of offshore wind capacity in the U.S. by 2030, and 15 GW of floating offshore wind specifically by 2035, the bureau said in a statement announcing the results of the lease sale. Five companies were named provisional winners of the auction: RWE Offshore Wind Holdings, California North Floating, Equinor Wind US, Central California Offshore Wind and Invenergy California Offshore.

The U.S. West Coast is “one of the most attractive growth regions for floating offshore wind in the world due to its favorable wind conditions and proximity to markets that need reliable, clean energy,” Equinor Wind US President Molly Morris said in a statement. Equinor secured a roughly 2 GW lease in the Morro Bay area, off the central California coast, that spans more than 80 acres. The company operates two other lease areas, Empire Wind and Beacon Wind, off the Northeast coast. 

For the industry, the lease sale results included some surprising outcomes and encouraging trends, according to Sam Salustro, vice president of strategic communications with The Business Network for Offshore Wind. Bid prices were lower than the East Coast but indicate confidence in a new market that doesn’t have a very visible path to offtake agreements and still needs to build ports and develop a supply chain and workforce, according to Salustro.  

The surprising part, according to Salustro, was that the auction had only seven bidders, when 43 bidders were pre-qualified. These seven were largely developers who are already active in the U.S. market.

“I think that’s surprising because there are a lot of floating [offshore wind] developers globally and we may have thought that… some of them may have gotten involved. But they stayed out and it was people already in the American market who won the leases — which sort of signals that while there is a lot of confidence in the American market, the people who have the most confidence are the ones who are actively engaged with it,” he said.

Salustro and other experts aren’t surprised the bid prices were lower than those seen this year in the New York Bight, which drew winning bids of about $4.4 billion from six companies. 

“That was a perfect storm, because they had the ports, they have a supply chain, they have an offtake, they have a workforce that’s developing — we’re probably not going to see those prices again for a long time here in the American market,” he said. 

Nancy Rader, executive director of the California Wind Energy Association, also believes the results of the auction reflect California’s lack of a clearly charted out path to set up this new offshore wind industry, which translates to creating more risk for developers and lower lease bids.

“We don’t have enough investments in ports, we don’t have a clear offtake plan and we do not have transmission plans to the North Coast, at least,” she said. 

In fact, California’s offshore wind industry still does not have much certainty on what the final offtake agreements for offshore wind will look like. These projects are large in scale, and it can be difficult for some load-serving entities — like smaller community choice aggregators — to procure power from them, said Michelle Solomon, policy analyst at Energy Innovation. 

One way experts say the state can get around that is by creating a central procurement agency to procure the energy and sell it to smaller entities, according to Solomon.

Another point of uncertainty for the industry is that California is trying to set up a relatively new technology — floating offshore wind. The East Coast has shallower waters, so projects can have fixed-bottom turbines that are prevalent around the world. California’s waters are much deeper, so the wind turbines will need to be floating and tethered to the bottom of the ocean using cables. Floating turbines are a mature technology for depths of a few hundred meters — but California’s water depths, in the area of the lease sales, are more like 800 meters to 1,000 meters deep, she added. 

“There’s just more to be done to get the industry up and running in California… so [it’s] not surprising that the lease sale is a little bit less than New York. I would say this is still a high total,” Solomon said. 

The lower bid prices have an ancillary benefit, said Rader. Astronomical bid prices on the East Coast run the risk of pushing up power purchase prices, she said. Moreover, this money goes to the federal government instead of meeting the infrastructure needs, such as transmission and building ports, in which California needs to invest. 

“So in that sense, it’s good that the bid prices are lower, because it will affect power purchase prices to a lesser extent,” she said. 

Going forward: ports, transmission and more call areas

Offshore wind can play a critical role in California’s energy mix as the state transitions to a decarbonized grid. The state has relied heavily on solar power to provide renewable energy, whether on rooftops or large-scale solar arrays. Wind can complement solar power as it kicks in when the sun goes down, said Laura Deehan, state director of Environment California. 

This August, California regulators adopted offshore wind planning goals for the state of 2 GW to 5 GW by the end of the decade, and 25 GW by 2045. Those goals provide a critical boost to the industry, experts say. 

“Our whole thinking was we wanted to show investors and the energy industry, the folks who are building offshore wind in other parts of the world… that California is really serious about going big on offshore wind,” Deehan said. 

Looking to the next 10 years, California will need to create a clear road map for permitting offshore wind projects; a strategy to develop ports that can deploy and service offshore wind; a plan to site, permit and construct transmission; and a procurement policy for the offshore wind itself, according to Adam Stern, executive director of Offshore Wind California.

“And we need additional call areas,” he said. “It was terrific that this auction was as successful as it was, but according to BOEM, the combined capacity of the areas [is] 4.6 GW. The state, as you know, has set a goal for 25 GW by 2045, so we need more call areas to enable us to achieve that goal,” he said.

For developers, meanwhile, the next steps are to start working with the communities that will be affected by offshore wind energy development to figure out what kind of community benefit packages they can assemble, said Solomon. Developers may not have all the permits ready to start building in a leased area, and they will need to focus on construction operation plans that comply with environmental considerations.

On the regulatory side, the California Public Utilities Commission needs to see how offshore wind fits into its long-term planning and require offshore wind energy to be procured, preferably by a central procurement entity, according to CalWEA’s Rader.

There’s still a long road ahead before wind turbines off the coast of California are producing energy, according to experts.

“A big issue in our view is are we going to get any of the economic benefits from this thing? Are we going to build any of this stuff in California?” Rader said. “We’re working very hard to make sure that we’re building at least some of the floating platforms in California. That’s the biggest ticket item that we can most likely capture.”

However, the state currently doesn’t have adequate port space to build these platforms, which can be the size of football fields, Rader said. 

“That’s a challenge — and if we can’t figure out a way to build out the ports… we won’t get many of these economic benefits,” she said. 

Environmental impacts present another challenge to setting up floating turbines, according to Julia de Lamare, clean energy advocate with the Natural Resources Defense Council.

“Floating turbines are a new technology that has never been tested in the United States, which means the impacts on marine life, fisheries, Indigenous people, among others are unknown,” she said in an email.

Regulators must advance environmentally responsible offshore wind development, de Lamare said. She suggested requesting leaseholders to commit to avoiding and minimizing environmental impacts and conducting additional research to fill in data gaps.

In 2022, every segment of the solar industry but residential saw year-over-year declines in installed capacity growth as the industry struggled with the effects of various state policy decisions and ongoing global supply chain disruptions. Experts say the industry will continue to be dogged by trade barrier and supply-chain headwinds in 2023, but they are optimistic about the tailwinds solar is receiving from the Inflation Reduction Act.

The tax credits in the IRA are expected to incentivize the buildout of domestic solar manufacturing as the industry prepares for the June 2024 expiration of President Joe Biden’s executive order placing a two-year moratorium on any new tariffs stemming from an ongoing U.S. Department of Commerce investigation.

The department announced Dec. 2 that it was making a preliminary affirmative determination in its investigation into whether solar panels imported from four Southeast Asian countries circumvented tariffs on Chinese-made solar components. This announcement came as a blow to the solar industry, as uncertainty over solar component supply had led to project cancelations throughout 2022.

The Uyghur Forced Labor Prevention Act, or UFLPA, has also impacted access to solar modules. Reuters reported in November that a records request revealed U.S. Customs and Border Protection seized 1,053 shipments of solar equipment imported from China between June 21, the day the law went into effect, and Oct. 25.

Wood Mackenzie senior analyst Sylvia Leyva Martinez said that the 2023 outlook for the solar industry will be “heavily determined by the total module shipments that get released” this year, but that a lack of transparency from CBP is making projections difficult.

Martinez has heard secondhand reports that some shipments have been investigated and released, but said that it is “very, very difficult to obtain primary data on the situation.”

“We’re expecting that the total module shipments are going to normalize by the end of Q2 2023,” Martinez said. “We still don't know how the entire situation is going to evolve, but according to the preliminary news that some shipments were already released, hopefully there will be more modules available through the second half of 2023.”

John Smirnow, the Solar Energy Industries Association’s general counsel and vice president of market strategy, also cited uncertainty surrounding the implementation of the UFLPA as a major source of volatility for the sector.

“We're starting to see some small volumes being cleared from detention, which is a positive development, but still large volumes detained, and uncertainty on the process,” Smirnow said. “What's it going to take for companies to establish that their imports are free of inputs from Xinjiang? We think the companies will be able to establish that, but they need clear guidance from Customs.”

Smirnow believes that the UFLPA, plus the ongoing Commerce investigation and the resulting pivot to domestic manufacturing, will be “hangover effects through 2023.”

However, he thinks the market will improve from 2022.

“And then, as more domestic manufacturing comes online in 2024, 2025, we hope that many of these supply chain challenges are going to be reduced, then we certainly expect the deployment to start accelerating at that time,” he said.

The 2022 Q4 U.S. Solar Market Insight report that Wood Mackenzie and SEIA released in December said that the groups also anticipate “downside risk” next year as a result of Commerce’s preliminary determination that several companies were violating tariffs, though Commerce won’t release its final determination in the case until May 1.

Martinez said she expects that Biden’s executive order will stave off significant impacts of the tariff investigation through 2023 and 2024, but added that she has concerns about the balance of supply and demand after the moratorium ends.

Reconfigurations of companies’ strategy are imminent

Robb Jetty, the chief operating officer at Distributed Solar Development, or DSD, said that his company and the industry overall have experienced “significant headwinds with the policy volatility in the United States as it relates to the import of solar modules, which was pretty tumultuous for us.”

“Things changed rather dramatically, and caused a period of time where being able to import modules into the U.S. has a high degree of risk and uncertainty associated with it,” Jetty said, though he echoed Martinez in saying that the effects were mitigated by the White House’s moratorium on new tariffs.

“But the global supply chain generally has been a challenge since the latter part of 2020, when inventory started to dwindle globally of the various components that make up the broader products within the overall mix of equipment that we use,” Jetty said. “And that's continued.”

Jetty said that supply chain disruptions like labor shortages in shipping and trucking have led DSD and other companies to move away from a just-in-time procurement strategy and instead make bulk purchases of components “to create both price certainty and certainty of availability of supply.”

Previously, the industry had applied this strategy to solar modules specifically, in order to take advantage of a “safe harbor” investment tax credit provision for renewable energy projects and secure the tax credit of a specific year by investing enough money in materials for the project to qualify as having begun construction in that year.

“Now we've basically taken that kind of strategy and applied it to a lot of the other major system components across what's needed for solar projects generally,” Jetty said. “We’ve placed bulk purchase orders and made deposits for rooftop racking through the entirety of the mobilizations that I'll plan to mobilize on through 2023.”

Jetty said that for two hundred rooftop projects that DSD has underway, the company has already paid a deposit to secure racking for all of them in order to guarantee that those orders will be fulfilled.

“It gives me certainty of supply and locks me in at a price in that time period to protect us from the volatility in the supply chain that we've been experiencing here in the last couple of years,” he said.

Though Jetty thinks the IRA provides the solar industry with a “significant tailwind” to combat the headwinds it’s experiencing, he believes that it will take “a number of years” for the supply chain to normalize. 

“This global supply chain volatility that we were impacted by isn't going to go away anytime soon,” he said. “We're dealing with the longest lead times on electrical component availability that we've ever experienced as an industry.”

Jetty also believes that the IRA will fuel demand for growth in the solar industry that will be met with a dearth of supply after the moratorium on new tariffs runs out in June 2024. He said that it is “literally impossible” for the U.S. to build out its domestic supply chain enough over the next 18 months to meet that demand. 

“There's no way that manufacturing capacity would be able to respond in that time period to meet the demands of projects that developers are going to want to bring online in that time period,” Jetty said.

He pointed out that First Solar, the largest U.S. manufacturer of photovoltaic solar modules, is already sold out of modules through 2024.

“There's just no way that there's enough capacity, or that enough capacity will come online when manufactured domestically, to meet the gigawatts of demand that are forecasted to come online as a result of the IRA,” Jetty said. “We're going to continue to rely on foreign manufacturing for years.”

Smirnow also said that time is the biggest barrier to building up the domestic supply chain, including the time it takes for manufacturers to choose a state and a specific location for a new facility. As a result of this current uncertainty, he anticipates that 2023 will see companies reconfiguring their supply chains, altering their production processes, and negotiating pricing, with the dust settling in 2024.

“It’s a timing factor,” Smirnow said. “We are going to see a robust across-the-board solar manufacturing base in the United States because of the IRA, we are certain of that. It's just a question of, how long is it going to take to get there?”

The IRA provides a 30% solar investment tax credit through 2025, while before the law it was at 26% and scheduled to drop to 22% in 2023. Projects that certify all steel, iron and manufactured product components were produced in the U.S. can qualify for an additional 10% tax credit, as can projects located in or near a community that has historically relied on the fossil fuel industry.

As a result, solar is receiving a massive boost in appeal as an industry at the same time that the supply chain for solar components is becoming more uncertain.

Marlene Motyka, a principal at Deloitte and the firm’s U.S. renewable energy leader, said that while many solar projects were delayed in 2022, she saw few being outright canceled and no real dampening of demand. 

The extension of increased tax credits for both wind and solar supports growth, Motyka said. “Some of those projections now suggest that the law would spur 525 to maybe 550 GW of new utility-scale clean power by 2030. And that was up from what I believe was an originally projected number of 300 GW.”

Domestic optimism

Becca Jones-Albertus, director of the Department of Energy’s Solar Energy Technologies Office, is more optimistic about the industry’s ability to build out domestic manufacturing and expects a “very robust” domestic supply chain to be in place by 2025.

“It is an aggressive timeline to have manufacturing capacity up and ready by June of 2024,” Jones-Albertus said. “But I think it's too early to say whether or not the industry can get there.”

She added that though Commerce’s preliminary determination found evidence that four of the companies it investigated were circumventing tariffs, it did not find evidence against the other four, and the companies that were found circumventing “also have that time frame to reconfigure their supply chains.”

Jones-Albertus believes that the passage of the IRA sets up the U.S. solar industry for successful domestic expansion, partially due to the nature of the current barriers to domestic solar manufacturing.

The U.S. has plenty of quartz, she said, which is the material used to make polysilicon, a key component of photovoltaic solar cells. The challenges for domestic expansion have been economic ones like the U.S.’s higher labor costs and more stringent environmental regulations for manufacturing facilities.

“That's why the manufacturing production tax credits in the Inflation Reduction Act can be so powerful, because they are directed at different supply chain segments, and they provide tax credits that can directly offset those higher costs of manufacturing in the U.S. and make U.S. manufacturing competitive with imported products,” she said.

Jones-Albertus said that between the passage of the IRA and Dec. 16, when she spoke to Utility Dive, 17 new solar manufacturing facilities representing more than 75 GW of proposed capacity had been announced.

Hanwha Q Cells, the second-largest domestic solar manufacturer, announced on Jan. 11 that it will invest more than $2.5 billion building up the domestic supply chain, opening a second plant in Georgia and raising its total annual solar panel production capacity to 8.4 GW by 2024.

Martinez said that she believes the IRA provided the boost necessary to jump-start the domestic solar supply chain, as producing solar components in the U.S. is more expensive to the point of rendering production almost entirely non-competitive without subsidies.

However, she cited outlying uncertainty about the impact of the IRA, and she said that it’s too early to fully estimate the law’s impact when it comes to total energy generation or domestic manufacturing buildout. 

“I think the biggest thing to look for in 2023 is what other guidance the IRS provides on the implementation of all the tax credits in the IRA, and after that, we'll have a better view of exactly how that is going to impact total renewable buildout in the U.S.,” Martinez said.

Four major viable paths to a net zero emissions “clean electricity” power system by 2035 “in which benefits exceed costs” are detailed in an August study by the Department of Energy’s National Renewable Energy Laboratory, or NREL.

But it does not explain how adequate land to reach a 90% clean electricity penetration can be acquired or how reliability will be protected beyond that 90% penetration, stakeholders acknowledged.

Today’s clean energy technologies can take the U.S. “to about 90% emissions reductions because of reduced costs and our maturing understanding of renewables and storage,” said Paul Denholm, DOE principal energy analyst and study co-lead author. But “90% is a proxy for where we don't know what resource or multiple resources will be needed for reliability,” he said.

Markets may resolve uncertainties about long-duration energy storage, or LDES, technologies for reliability, DOE and storage analysts agreed. But resolving the continuing local opposition to building new infrastructure will require smarter planning, environmentalists said.  

“Most people have not yet envisioned the coming scale of development and local permitting and siting challenges,” agreed Nicole Hill, project lead on The Nature Conservancy, or TNC, report Power of Place – West. But TNC’s new planning approach of “working slowly and responsibly now to be able to go faster later,” can achieve both climate and conservation goals, she said.

The full scale of needed infrastructure growth may be hard to envision, but new federal, state and utility LDES technology investments and proposed planning policy innovations are taking on the uncertainty, DOE’s Denholm and other analysts said.

Paths to 100%

The four paths to a 100% clean power sector by 2035, even with 66% higher demand from transportation and building electrification, can lead to a net zero emissions economy by 2050, the NREL study said.

One path assumes “improved cost and performance” of all zero emissions technologies, including carbon capture, NREL reported. Another assumes more transmission capacity from “improved transmission technologies” and “new permitting and siting approaches,” a third assumes higher costs from generation and transmission constraints, and the last assumes limited carbon capture.

The study focused on meeting needs with large-scale energy supply, but an alternative path could use more energy efficiency and demand-side flexibility, NREL added. Relying on those alternatives instead of building large-scale infrastructure lowers projected annual load growth nationally from 3.4% to 1.8%, with “lower demand peaks” and “winter peaks,” and uses more “clean” hydrogen in transportation, industry and generation, the study said.

Modeling included 2021 state and federal policies but not 2022’s Inflation Reduction Act, or IRA, and 2021’s Bipartisan Infrastructure Law, NREL said. Subsequent DOE analyses estimated those investments driven by those laws, in conjunction with other planned buildouts, can lower economy-wide emissions 40% from 2005 levels and grow clean energy 60% to 81% by 2030, but lead to no more than 78% power system emissions reductions by 2035, NREL found.

A combined 2 TW of new wind and solar, “roughly three times the 2020 level,” provide 60% to 80% of new generation by 2035, in NREL’s paths. Projected annual growth rates by 2030 of 43 GW to 90 GW for solar and 70 GW to 145 GW for wind, are “more than quadruple” current levels, it added.

Overall capacity in the four scenarios, which also included 5 GW to 8 GW of new hydropower and 3 GW to 5 GW of new geothermal by 2035, could be reduced 16% to 20% with more energy efficiency and distributed energy resources, NREL reported.

For reliability at “all hours of the year,” a total of 120 GW to 350 GW of  2 hour-to-12 hour “diurnal storage” will be needed by 2035, NREL estimated. It may be batteries, pumped storage hydropower, or technologies still being developed. Depending on power system uncertainties, an additional 100 GW to 680 GW of LDES will be needed at very high variable renewables penetrations, it added.

Nuclear is likely to be 9% to 12% of generation in 2035 under three of NREL’s scenarios but could more than double to 27% with siting and permitting constraints on generation and transmission, models found. But that is unlikely because the cost-effectiveness of investments in wind, solar, storage and transmission is “clearly” better than that of new nuclear, NREL’s Denholm said.

Between 1,400 miles and 10,100 miles of new high voltage transmission will be needed annually to achieve net zero power sector emissions in 2035, reaching “1.3 times to 2.9 times current capacity,” NREL estimated. Building the most transmission and wind has “the lowest average system cost,” it found in analyzing the pathways.

The “main uncertainty” is the technologies mix, modeling showed. With carbon capture viable, the scenario using all net zero emissions resources includes up to 5%, or 660 GW, of fossil fuels in the total 2035 generation. But more energy efficiency and DER reduced the need for new generation capacity “about 20%,” and both mixes reduced land needs and system costs, NREL found.

Health benefits from “substantial” fossil fuel reductions can provide “$390 billion to $400 billion” in total economic savings by 2035, NREL estimated. With the 2020 social cost of carbon, or SCC, of “about $80” per metric ton, rising to “about $100” in 2035, savings reached a total “net benefit” of $900 billion to $1.3 trillion over the projected $330 billion to $740 billion in “capital, fixed, and variable” power system costs, modeling estimated. Net benefits would be significantly higher with a more speculative $275 per metric ton SCC, NREL added.

But resource mix and cost uncertainties grow after 2030 with the need to meet growing diurnal and seasonal demand peaks from clean generation penetrations above 90%, NREL reported.

Molecules or electrons?

LDES choices beyond 2030 are largely between clean hydrogen fuels containing molecules produced from renewables and water or from natural gas with carbon capture, and clean energy projects generating electrons.

And “the future energy mix may be determined by how fast transmission for stored electrons and pipes for stored molecules are built,” said Jason Burwen, vice president of energy storage at the American Clean Power Association.

Through 2030, lithium-ion batteries of up to 10-hour durations and pumped hydro storage of up to 12-hour durations will become “increasingly cost-competitive” with natural gas plants for meeting ”mismatches” between renewables generation supply and load that last for 24-hour or less periods, NREL reported.

LDES, which NREL calls “seasonal” storage, is “represented” in the study by clean hydrogen fuels but could come from “a variety of technologies” still unproven at scale, NREL said. They include synthetic natural gas or ammonia fuels, new battery chemistries, thermal storage, compressed-air, pumped storage, or gravity-based technologies, it added.

Stored clean LDES can address the “seasonal mismatch” from rising summer and winter demand peaks as clean energy approaches 100% and electrification grows, LDES Council Executive Director Julia Souder, NREL’s Denholm, and others said. Storage depleted by use for extended high demand-low renewables periods in the summer or winter can be replenished by spring and fall renewables oversupplies to avoid curtailment and economic losses, they added.

Overall, LDES will be expensive, “but there is so much uncertainty” about firm resources like unproven-at-scale fossil generation with carbon capture “that comparison is speculative,” said Denholm. But some version of LDES “will be needed to achieve the 2035 target,” making investment “in demonstrations of potential technologies important now so they will be ready,” he said.

“Multiple solutions,” will be needed to reach the 2035 goals, agreed Jacob Susman, CEO and co-founder of Ambient Fuels, which supplies green hydrogen from renewables and water, and Nidhi Thakar, vice president of policy and regulatory at Form Energy, a developer of a groundbreaking 100-hour, multi-day iron-air battery chemistry.

There is no need for batteries and green hydrogen to compete while policy and market design are still being shaped, and “narrowing opportunity now will miss value later,” the LDES Council’s Souder added.

Access to adequate land is a more immediate concern creating uncertainty about meeting the 2035 net zero emissions power sector goal, stakeholders agreed.   

Planning for land

The 2035 goals could require new generation at “three to six times” recent growth rates, new rights-of-way for “doubling or tripling” transmission, and “new pipelines and storage for hydrogen and CO2,” DOE found.

It is “doable” by “balancing environmental protections against carbon’s impacts” on climate change, Denholm said.

Permitting language was removed from September’s Continuing Resolution on government funding (H.R. 6833), while the Federal Permitting Reform and Jobs Act (S.2324), introduced by Senator Rob Portman, R-Ohio, in 2021 to streamline the infrastructure development, has not progressed. And the still uncompleted stakeholder process at the Federal Energy Regulatory Commission to reform transmission planning includes proposals to streamline permitting. But neither get at the innovative reforms really needed, stakeholders said.

Smart planning can protect “sensitive natural areas and working lands” and reach economy-wide net zero emissions cost-effectively by 2050, TNC’s Power of Place – West study agreed.

Without improved planning, the 2050 goal would require “up to 39 million acres” in the 11 studied states for new generation and transmission infrastructure and cost $260 billion, TNC’s modeling found. But with spatially specific regional, state and local planning and siting in pre-defined “priority renewable energy zones,” only 21 million acres would be needed, an almost 50% reduction, at an increased cost for all the extra siting and permitting work of only 3%, to $268 billion, it found.

Though made separately, TNC’s projections would likely represent a significant portion of the $330 billion to $740 billion in infrastructure development costs projected by NREL to achieve net zero emissions in 2035.

TNC identified where reconductoring upgrades and use of rights-of-way can meet half the new capacity needed for those states. That would limit additional land needed for rights-of-way for 16 GW of additional transmission capacity to 6,259 miles, only a 7% to 8% increase over current land used for the West’s 86,000 miles of transmission lines. Solar can be planned safely away from wildlife corridors and wind can be built offshore, it added.

“Power providers like Los Angeles County’s Clean Power Alliance, local governments like San Diego County, and private project planners are using these kinds of planning approaches,” TNC’s Hill said. And the strategies can be applied nationally, as shown by the priority renewable energy zones already used successfully for clean energy in California and transmission in Texas, she added.

Elements of TNC’s planning approach can accelerate development of Southwestern solar, Midwestern onshore wind, East Coast offshore wind, and inter-regional transmission nationally, agreed Natural Resources Defense Council Senior Renewable Energy Policy Analyst Nathanael Greene.

At least eight IRA provisions providing over $1.5 billion to under-resourced and understaffed federal permitting agencies can allow improved planning to streamline environmental reviews, Greene added.

But TNC’s approach may be “an optimistic outlook,” and underestimate the “intense opposition” in local communities to new infrastructure buildouts, the Los Angeles Times observed October 6. 

“Local community opposition is real and will likely continue to make siting and permitting a challenge,” but might be addressable, said University of Notre Dame Associate Professor of Sustainable Energy Policy Emily Grubert, who has worked with federal agencies on related issues.

To earn a community’s trust, development proposals “should explain why a project is needed, why the community’s resources are needed, and how the community can benefit,” Grubert said. They should also “assure the community its concerns have been heard and it will be protected,” she added.

DOE’s formal Community Benefits Agreements, which are used for new infrastructure development and stipulate the benefits a developer will deliver for the community, “could also have a powerful impact on streamlining siting and permitting,” Grubert said.

“No project should go ahead without a Community Benefit Agreement to assure real benefits for the host community,” agreed NRDC’s Greene. But in many places, “political polarization has turned reasonable project development questions into obstructive, misinformation campaigns,” Greene said. “Overcoming that will take a lot of work,” he added.

“People, especially in smaller communities, can get very passionate, and even exchange death threats, which shows how important and undervalued trust is,” Grubert agreed.

California legislation jump-started battery storage growth in 2016 and its most recent planning mandates may do the same for LDES by calling for storage that protects system reliability, ACP’s Burwen said.

But at present even California’s advanced integrated energy resource planning process needs updating to recognize the need for climate and extreme weather adaptation and the new affordability of clean energy, said V. John White, executive director of the Center for Energy Efficiency and Renewable Technologies.

Long term planning in California and across the country must now focus on accelerating clean energy deployment because “the IRA has shifted the ground underneath us,” White said. It has turned new resource procurement into “an affordability strategy” because “the sooner low-cost clean resources are online, the sooner natural gas prices coming out of rates will allow customer bills to come down,” he added.

U.S. power system planning “still relies too heavily on natural gas,” which was the “root cause” of the February 2021 Texas outages, NREL’s Denholm agreed. “Not enough planning today addresses the changing peaks across seasons and times of day that will come with electrification” and “the need for transmission even where siting and permitting are barriers,” he added.

But the DOE study’s most critical finding “is that right now the answer is ‘yes’ to building any possible solar, wind, storage and transmission project as quickly possible to meet the national goals,” he said.

Disadvantaged communities in many parts of the U.S. are bearing the brunt of clean energy supply chain blockages that range from materials to labor, according to environmental justice advocates and utility officials. 

In marginalized communities, it is “substituting one kind of delay for another,” said Shelley Robbins, project director for the Clean Energy Group, based in Vermont. “If you can’t get something, the price goes up.” 

Historically, renewable energy and electrification projects in underserved communities have been “way too expensive,” she said in a recent phone interview. 

The rise in prices caused by serious crimps in the supply chain for key materials is delaying virtually all solar, storage and other fossil-free energy projects, but the stakes and impacts are higher for overburdened communities because of longstanding inequities. Clean energy replacements of inefficient fossil fuel power plants are slowing, along with weatherization and electrification of home water and space heaters, stoves and other major appliances, according to advocates and utilities.

Supply chain delays — from containers stuck in ports to disruptions from the war in Ukraine — may not only “exacerbate the [lack of] affordability of distributed energy resources for underserved communities” but also “lengthen the timeline for deployment of cleaner technologies,” Carolyn Slaughter, the American Public Power Association’s director of environmental policy, wrote in an email.

In addition, the havoc wreaked by hurricanes may cause underserved communities to experience “undue delays with power restoration due to the limited supply of transformers, which could impact access to clean water and other essential services,” Slaughter said.

Many believe that the Inflation Reduction Act will help alleviate supply chain constraints by allocating billions of dollars over the next decade for clean energy projects. That funding includes $15 billion in rebates, grants and loans for greenhouse gas reductions and zero-emission energy in struggling communities, according to David Roberts, a former Grist and Vox staff writer who now produces the Volts podcast.

Project funding “will be a lot easier” because up to 50% of the cost basis of projects can now be covered under the new law, according to Robbins. 

‘Super-duper feasible’ fossil-free peaking power

Inflation Reduction Act funds can be used to replace aging, polluting peaker plants in poor communities with renewable energy and storage projects. Combustion-free energy systems address local reliability “without the negative impacts” of fossil projects, Erin Childs, a director at Strategen Consulting, said during an Aug. 14 Clean Energy Group webinar.

Energy storage, she added, has all the characteristics of peaker plants but can power up faster, integrate renewables seamlessly, and provide voltage and frequency support. “These transitions are super-duper feasible,” Childs said of swapping in batteries for peaker plants that fire up as electricity demand is surging.

According to a Clean Energy Group analysis, 32 million Americans live within three miles of a peaker power plant. These facilities that fire up when power demand soars “are some of the dirtiest, least efficient and most expensive energy sources and most of them are located in low-income communities, environmental justice communities and communities of color,” it states.

But the Inflation Reduction Act is untested, and there are many unknowns, so “utilities are being cautious” on advancing projects. “I hope utilities are doing the math” on peaker replacements, Robbins said.

Focusing on equity

Equity has to be foremost in utility clean energy investments and there should be community involvement when determining needed clean energy projects, said Robbins. Many utilities are “not used to thinking this way and they will have to adapt to a lot of changes,” she said.

Two-thirds of low-income customers spend more than 6% of their income on their energy bills, compared with average U.S. consumers spending just 3%, according to a report by the Smart Energy Consumer Collaborative. “These customers look to their energy utility for support and understanding, as well as programs or services to help ease their energy burden,” it states.

A growing number of utilities and regulators have prioritized energy equity, including ones in Washington and California. Their efforts include installing projects in underserved areas where community members want them, utility staff members said.

“Our programs are centrally focused on equity,” with increased outreach and engagement with marginalized communities, said David Logsdon, Seattle City Light director of electrification and strategic technology. The public agency provides a 60% rate discount to qualifying low-income customers to help ensure they benefit from clean energy. “We are also partnering with local community-based organizations to deploy electric vehicle chargers and incentives in these environmental justice communities,” Logsdon said. 

Delays and higher costs from supply chain constraints have created big challenges for clean energy projects in all communities, including installations of heat pumps for space and water heating. “The upfront cost is a huge barrier with disproportionate impacts,” said Joe Fernandi, Seattle City Light’s director of customer energy solutions. The Inflation Reduction Act, however, is expected to help reverse the trend by “ultimately helping bring down costs,” Logsdon said.

Also in Washington, Tacoma Power engaged its community to better understand how to serve income-qualified customers who have electric heat with energy efficiency programs to help reduce utility bills, said Lis Saunders, Tacoma Power’s residential manager, customer energy programs. 

“For customers wanting to reduce their carbon footprint, buying an electric vehicle and charging it with our almost carbon-free electricity is one of the best options, especially given the climate of the Pacific Northwest,” she said.

Tacoma just launched a program that offers landlords loans to install energy efficiency upgrades and heat pumps in dwellings rented to those with moderate and low incomes. “The property owner can get a grant for insulation and a forgivable loan for single-pane window replacements and heat pumps, if the property has electric heat,” Saunders said. The loan is forgivable if the property owner continues affordable rents for low and moderate-income tenants for five years.    

Seattle City Light and Tacoma Power have large carbon-free portfolios, with hydropower a major component of their energy supply. Hydro was 86% of Seattle’s resource portfolio in 2020 and it serves the demand of about half of Tacoma’s customers at 3 billion kilowatt hours of energy each year. That has helped stabilize rates by avoiding the rate volatility of natural gas supplies according to Logsdon.

California provides rate discounts for low-income ratepayers. In addition, on Sept. 22 state air pollution regulators unanimously approved a ban on sales of gas-fired air and water heaters and coolers starting in 2030 to reduce nitrogen oxide-laden smog and greenhouse gas pollution, with a focus on overburdened disadvantaged communities.

Last April, the California Public Utilities Commissions added $40 million in incentives on top of an earlier $45 million the state provided for electric water heat pumps and needed electric panel upgrades for households, with low-income home subsidies up to $9,285. Electric pumps can preheat water with excess renewable energy, store energy, provide grid services, lower utility bills and reduce indoor air pollutants, CPUC President Alice Reynolds said before the April 7 vote approving the additional incentives.

A report, Gas Appliances and Smog: California’s Hidden Air Pollution Problem, released Sept 20 by the San Francisco Bay Area Planning and Urban Research Association (SPUR), RMI and the Sierra Club found that 99% of the disadvantaged communities in California live in an ozone nonattainment area.

To help address that problem, Gov. Gavin Newsom in late July set a goal of 3 million climate-ready and climate-friendly homes by 2030 supplemented by 6 million heat pumps, directing 50% of investments to low-income and disadvantaged communities.

Weatherization lands big federal dollars

A major financial boost to get low-income home weatherization up to speed is being provided by the bipartisan infrastructure law’s allocation of $3.5 billion over five years.  

“We have to have a flawless launch,” David Bradley, CEO of the National Community Action Foundation, said of the law’s weatherization program support. NCAF represents weatherization assistance program agencies before Congress. 

Supply chain constraints — particularly workforce shortages — and current funding restrictions present high hurdles to increased residential efficiency work to lower energy consumption, emissions and utility bills for struggling households according to Bradley.

The federal government requires funded weatherization programs to include job training. While the government provides valuable training, federal funding does not cover the cost of “invaluable on-site training of apprentices,” according to Bradley. When appropriations are limited, the more time spent training apprentices from disadvantaged communities on job sites, the less money is available for weatherization measures, Bradley said.

Bradley also pointed to the challenge of the $8,000-per-home cap for weatherization spending. Pending federal legislation, S. 3784 and H.R. 7947, would increase the weatherization cap to $12,000, which would help cover the rising wages of the much-sought-after workers the expanded program will need, he said. 

NCAF is seeking Department of Energy regulations that separate the on-the-job training costs from the cost charged to each home. “The higher average cost is driven by the true, growing cost of materials and the need to attract and retain workers,” Bradley said.

But of more significance on the equitable weatherization front, according to Bradley, is that S. 3784 and H.R. 7947 would authorize a weatherization readiness fund for repairs that are not in themselves energy-savings measures but are essential to fix run-down homes occupied by the most marginalized community members. Those repairs enable effective energy efficiency installations, such as by keeping a leaky roof from causing insulation to get wet and moldy and replacing faulty electrical panels to avoid blowing out new appliances.

National models indicate the Inflation Reduction Act may help the United States cut its greenhouse gas emissions by about 40% by 2030, but renewable energy developers are warning there are a range of challenges that could keep those estimates out of reach.

The hurdles include the “three-headed monster” of clogged interconnection queues, permitting delays and a congested transmission system, according to Devin Hartman, director of energy and environmental policy at the R Street Institute.

Organizations estimating the effects of the IRA on carbon emissions acknowledge those real-world issues.

In a report released Aug. 23, Energy Innovation found the IRA’s climate and clean energy provisions could help cut U.S. greenhouse gas emissions 37% to 43% below 2005 levels by 2030 compared with a 25% reduction under a business-as-usual scenario. The Biden administration aims to cut U.S. carbon emissions by 50% to 52% by the end of this decade.

The energy policy group found that by 2030 there would be 795 GW to 1,053 GW of operating wind and solar in the United States, with “clean electricity” providing 75% of all electricity under a “moderate” scenario.

Last year, about 32,300 MW of wind as well as utility-scale and rooftop solar came online, bringing their total installed U.S. capacity to 226 GW, according to the Energy Information Administration.

Energy Innovation’s moderate scenario envisions the U.S. having 877 GW of wind and solar by the end of this decade. Reaching that amount would require adding 81.4 GW a year on average, roughly 2.5 times the pace of last year.

The group warned its assessment doesn’t account for factors that could limit clean electricity deployment.

“In particular, the modeling assumes that necessary transmission will be built, interconnection delays are addressed, supply chains provide the necessary materials to deploy these levels of clean electricity, and a sufficient workforce can supply the labor,” Energy Innovation analysts said in their report.

Success hinges on states, local governments

In a factor not mentioned in the report, state and local governments will play a major role in how effective the IRA is at spurring clean energy deployment, according to renewable energy developers and advocates.

“It's really important that everyone understand how contingent that capacity expansion is going to be on state-level decision making,” Tyler Norris, Cypress Creek Renewables vice president of development, said.

In many regions, state utility commissions will have a significant effect on determining the future resource mix through their rulings on utility resource plans and rate cases, according to Norris.

“The success or failure of the Inflation Reduction Act rests at public service commissions because if the utilities are not making good decisions and the commissions are not regulating appropriately, then those states are going to be left behind,” Simon Mahan, Southern Renewable Energy Association executive director, said.

The national models estimating how much carbon emission reductions the IRA may achieve are helpful, but they don’t take into account issues such as county moratoria on solar and wind farms or state processes that devalue solar, according to Mahan.

“Those models are based almost entirely on economics, not on politics or sociological activities that are going on locally,” Mahan said. “It's just going to be really critical that the folks that have been so engaged at the federal level don't rest on their laurels and say the job is done.”

In some states, the process of developing long-range utility resource plans will be a focus for groups like the SREA, according to Mahan. IRP processes vary, Mahan said, noting Alabama, for example, lacks a public process, preventing stakeholders from offering suggestions as plans are developed and reviewed.

Aligning state policies with the IRA is a two-part process, according to Pari Kasotia, senior director and head of policy for DSD Renewables, a company that develops commercial and industrial projects as well as community solar.

First, states need to set top-level goals, such as expanding their renewable portfolio standards, she said.

Second, they need to make sure their permitting and generation interconnection processes are timely and efficient, she added.

“A number of states, I'm sure, have already started to think about what that alignment looks like, but I think policymakers and policy advocates will be doing a lot more work in making sure that alignment is there,” Kasotia said.

The IRA, coupled with high natural gas and other costs, is making rooftop solar combined with energy storage less expensive than utility rates across the country, according to John Berger, CEO of Sunnova, a residential solar company.

That will lead to pitched battles at state utility commissions over rules ranging from net metering to allowing customers to shop for power from non-utilities, Berger said.

“Congress certainly didn't unknowingly set us up for an absolute Big Bang in consumer choice and regulatory discussions with the passage of this bill,” Berger said. “The regulatory framework is going to change and have to change fundamentally on a state-by-state basis. It's going to be a war.”

Getting onto the grid

The interconnection process is another top challenge in expanding the pace of adding clean energy to the grid.

“There has to be a huge shift in how much renewable energy gets added to the grid every year to meet the goals under the IRA,” Kasotia said. “And in order to do that, that has to be aligned with the state policies and processes on how quickly you can get through an interconnection application.”

There are about 1,400 GW of planned generation and storage capacity in interconnection queues across the U.S., reflecting a surge in solar, energy storage and wind development, according to a report released in April by the Department of Energy’s Lawrence Berkeley National Laboratory.

As the queues have grown larger, it takes longer for transmission providers to complete interconnection studies, which determine if grid upgrades are needed to bring proposed projects online, according to the report. It took 3.7 years on average between a project entering the interconnection queue and coming online in the last decade compared to 2.1 years for projects built between 2000 and 2010. The Federal Energy Regulatory Commission proposed reforming the process earlier this summer.

“What we ask of our grid operators is an enormous task given the acceleration in the number of [renewable energy] projects and the size of the projects,” said Cary Kottler, Pattern Energy senior vice president of North American development. “So making sure that they are able to make their way through these interconnection queues is going to be crucial to meeting our goals.”

Transmission is needed, but hard to build

Even if the interconnection processes are improved, is there enough transmission to deliver power from clean energy facilities to the places where it would be used?

“It's great to incentivize low-cost renewables — and the demand is there from customers and it’s growing, whether it's from utilities or big corporations, or small corporations, that are hungry for carbon-free power — the demand is there, but if you don't build out the grid, you can't get the power to the load,” Kottler said.

The power sector needs to be “forcefully behind” the transmission build-out to make sure renewable energy can grow fast enough to meet governmental and corporate goals, he said.

The blueprint for reaching 70% and higher renewable penetration levels will be building a growing web of transmission lines that can move electricity from renewable energy sources with different profiles, coupled with energy storage, back and forth regionally, according to Kottler.

However, that plan depends on making sure the transmission gets built, or it will be a struggle to reach emissions-reduction goals, he said.

“Transmission has traditionally been the hardest thing and has the longest time horizon to get done. So that's the rub,” Kottler said.

Georgia Power is delaying shuttering some coal-fired units because the state’s transmission system can’t handle their exit from the grid or the renewable energy additions that would be needed to replace the power plants, according to Mahan.

“The transmission system, if it is not fixed and expanded on, will restrict the success of renewable development in many states,” Mahan said, noting FERC has proposed reforms aimed at improving the transmission planning process.

“We are so far behind that I don't think folks understand how far behind we are and where we need to be with regards to robust transmission planning so that we can fully implement what could be done with the Inflation Reduction Act,” Mahan said.

Permitting reform, renewable energy bans

Currently, project permitting and zoning is governed by a patchwork of local and state requirements, and there aren’t federal plans to address the issue for generating projects, according to Norris.

In a related challenge to meeting carbon reduction goals, it typically takes about four years to complete a renewable energy project after it has been procured, Norris noted.

While there is generally a strong awareness of the permitting challenges energy infrastructure developers face, there is less understanding of how long it takes to build interconnection upgrades to connect generating sources to the grid, Norris said.

“What we're ultimately going to see, especially because we have such a limited window here, at least for the 2030 target, is more build-out occur in the states and jurisdictions that have more streamlined and efficient permitting processes,” Norris said.

Permitting is a challenge, but so too is a rise in bans on renewable energy development, according to Kasotia.

“Certain communities in various states are imposing moratoriums on land-based solar development,” Kasotia said.

Local governments in nearly every state have adopted policies to ban or limit renewable energy projects, according to a March report by Columbia Law School’s Sabin Center for Climate Change Law. The report’s authors found 121 restrictive local policies and 204 contested renewable energy facilities, up 17.5% and 23.6%, respectively, from a report issued six months earlier.

Renewable energy developers acknowledged many of the IRA’s benefits for their industry, such as a 10-year tax credit for emissions-free resources and stand-alone energy storage as well as incentives to develop domestic production of renewable energy equipment.

“We're certainly delighted that the bill includes provisions for U.S.-based manufacturing,” Kasotia said. “That's a great first step. The real question is how quickly can we ramp up production in the U.S. so we can make our supply chain more efficient, more local, and have more certainty around that?”

It will take time for that manufacturing base to be developed and it may take years before new transmission lines can be planned and built, which will require a simultaneous focus on near-term steps that can advance the energy transition, according to Kasotia.

“We have to think long term and fix what we can at this point, but make sure that we continue to work towards long-term goals in terms of the infrastructure that we have to support the energy grid,” Kasotia said.

Private investment in renewable energy projects hit an all-time high with over $10 billion devoted to renewable energy in the past year, Supria Ranade, head of power markets for SoftBank Group subsidiary SB Energy, told an audience at the RE+ conference in Anaheim, California last week.

In addition to the overall increase in investment, the renewable energy market is also seeing a greater diversity of investors looking to put money into renewable energy projects and technology, according to Britta von Oesen, partner and managing director at CohnReznick Capital.

“There is a lot of capital chasing this space and lots of funds being raised looking for deployment,” von Oesen said.

Raising capital for renewable energy projects has become significantly easier over the past 12 months — and will likely only accelerate in the wake of the Inflation Reduction Act, financiers at the RE+ conference agreed.

Once largely limited to niche, purpose-driven funds, the number of investors looking to get in on the renewable energy boom has grown rapidly, panelists said. Even types of investors that might be considered more conservative than most, including pension funds, have begun to enter the market in recent months, van Oesen said.

“I had one deal where I think we had every type of investor end up at the finish line with a bid,” she said. “Insurance, independent power producers, domestic utilities, infrastructure, private equity — a pension fund showed up. Really it’s not hard to find the capital these days. It’s hard to find the right capital, and that’s what we spend a lot of time doing.”

As competition between investors has grown, the kinds of projects they’re willing to entertain has also expanded. Individual wind and solar projects have captured most of the private investment to enter renewable energy to date, but the latest wave of capital has shown growing interest in new options such as offshore wind, energy storage and even electric vehicles, according to David Felix, senior director of energy development and strategy at Inspiration Mobility. Private investors have also expressed more interest in projects at earlier stages of development, said Eric Stam, senior director of structured finance at Sol Systems. But most investors have so far stopped short of buying the development platforms themselves, he said.

Volatile supply chains and increasing fuel and energy costs have helped bring renewable energy into the mainstream by putting more pressure both on investors’ and consumers’ balance sheets, Ranade said. Between that and the increasingly apparent impact of climate change, customers and stockholders alike have begun to demand that companies make real efforts toward environmental and social progress, van Oesen said. Where ESG goals were a nice to have — or even mere greenwashing — just two to three years ago, she said, they’re now essential and pushing even greater numbers of private and corporate investors toward renewable energy deals. And the Inflation Reduction Act will likely further increase interest in renewable energy investments, she said, by creating a ten-year period of stability for federal tax credits and policy support.

“I’m not going to lie, it’s a good time to be a banker,” von Oesen said.

High inflation in the U.S. could make things difficult for the clean energy sector, but the passage of the Inflation Reduction Act could more than make up for those impacts, experts say.

In the U.S., consumer prices in July were up 8.5% compared to the previous year, albeit slightly lower than June’s 9.1% year-over-year increase. Late last week, the House of Representatives passed the Inflation Reduction Act, which authorizes $369 billion in funding for climate change-related and clean energy initiatives. The legislation includes a wide range of incentives and tax credits for clean energy, electric vehicles, nuclear power, and clean hydrogen, among other things, and is projected to decrease U.S. carbon emissions by 40% by the end of the decade. 

Clean energy projects that began to get underway as inflation ramped up face two countervailing forces, according to Harry Godfrey, managing director at Advanced Energy Economy: on the one hand, as natural gas gets more expensive, interest in solar and wind, for instance, is likely to increase. But at the same time, the primary way to combat inflation is to raise interest rates, in an attempt to “cool” the economy, which means that the cost of capital for clean energy projects will also rise. 

“So while there is, I think, a greater appetite to build these projects because they are deflationary, there is also [the fact that] the cost of the capital I need to raise to then build a multi-million dollar – let alone a multi-billion dollar – project has gone up. So those are the two forces at work there,” he said. 

Two countervailing factors  

It’s difficult to ascertain the impact that inflation has had on the solar sector, particularly because it’s been an especially weird time for the industry, according to Dan Whitten, vice president of public affairs at the Solar Energy Industries Association. In March, the U.S. Department of Commerce announced an anti-dumping circumvention investigation of solar cells from Cambodia, Malaysia, Thailand and Vietnam, in response to a petition from California solar panel assembler Auxin Solar. A few months later, President Joe Biden implemented a two-year exemption on tariffs for solar panels imported from these countries, which the industry expects will continue in parallel to the investigation. 

“There are a lot of outside forces beyond pure economic analysis that have influenced the price of solar over the last year, tied to supply chain, tied to trade policy – and so it’s really hard to evaluate the impacts inflation is having in solar based on those other forces,” he said.

At the same time, renewables do not lend themselves to price volatility, Whitten added – “and so therefore, we don’t think it’s as bad as it has been for other energy sources.”

Clean energy projects tend to be inherently anti-inflationary – if not deflationary – in nature, Godfrey agreed. Conventional resources like coal, oil and natural gas are coupled to the global commodities market, and therefore subject to significant price volatility – but renewable projects, which don’t involve a fuel factor risk, can be viewed as a kind of “shock absorber” in the economy.

“The greater your share of that, the less you’re going to see your energy prices rise as those commodity prices rise,” he noted. 

But future renewable projects face a different dynamic, according to Morten Lund, partner with Stoel Rives. Take a solar project for instance – a developer would essentially need to spend nearly 100% of the lifetime cost of the project in building it, he noted. Which means that an inflationary cost of construction, including the cost of financing, will be baked into the power purchase agreement price for a new solar project – essentially locking it in for 20 years.

“So then in five years, when oil prices come back down, those solar PPAs will still be high,” he said. 

The two countervailing factors impacting clean energy development could affect projects at the margins, according to AEE’s Godfrey. That being said, wind and solar projects aren’t only built because they are the least cost resources – they are also driven by emissions reduction goals, as well as a need to diversify energy sources.

“So it’s important to note the cost of capital, and how that can impact these projects, but it’s not the sole determinant of project viability,” he said. 

‘A mild headwind’

High inflation has also had implications for storage projects, industry advocates agreed, and the sector is facing several sources of increased cost due to inflationary pressures and supply chain constraints, like materials, labor, and the cost of capital to get things financed, said Jin Noh, policy director with the California Energy Storage Alliance.

“My view is that [inflation] is like a mild headwind” against the backdrop of a larger transition from the conventional, fossil fuel fleet to new energy sources, said Alex Morris, CESA’s executive director.

The impacts of inflation on the ground include some projects getting downsized or delayed, or force majeure invocations, he added. 

In California, this has led to responsiveness both from the industry as well as the utility or load-serving entity side to keep project deals intact – efforts that signal the industry’s commitment to absorbing a portion of the risk, as well as the power providers’ commitment to moving deals forward and serving load with clean resources, Morris said.

“It hasn’t been perfect, and each load-serving entity negotiates these things and approaches these things differently, so it’s hard to draw a single, standard conclusion – but generally, we are still seeing progress,” he added. 

The Inflation Reduction Act

The Inflation Reduction Act, however, could change many of these dynamics. 

Take, for instance, the cost of capital. AEE’s first-cut analysis suggests that the provisions in the IRA are going to more than offset the increased, underlying cost of capital driven by inflation, according to Godfrey. The IRA would restore to full value and extend the Investment Tax Credit and Production Tax Credit for clean energy projects, as well as institute a credit for standalone storage. It also includes a variety of adders, like meeting domestic content requirements, and when stacked together, “for the ITC, you can get like a 50% tax break on it for a big project – that’s huge,” he said.

Another meaningful aspect of the legislation is that it will continue many of the tax credits into the 2030s, providing developers with more certainty and a clearer line of sight, said Godfrey.

“I think what’s in the IRA more than counterweights the inflation of this moment,” he added. 

In California and the West, there is already a fundamental drive toward more renewables and storage, and the IRA essentially reflects a continued commitment and reduced cost to achieving that, said CESA’s Morris. In addition, the legislation could also lead to changes in how storage is configured and shows up on the grid.

“We’ve seen a lot of storage paired with renewables – we know that that can make a lot of sense, but it’s also linked to the investment tax credit for solar. And now, we may see different configurations of storage, including more independently connected standalone storage not necessarily colocated with solar,” he said.

Boone Staples, director of transmission analysis for the engineering and construction group at energy developer Tenaska, has been doing essentially the same job for the last 15 years. And in spite of his tenure, he says he can’t remember a single solar project that hasn’t run into interconnection delays.

“We have projects in the [Midcontinent Independent System Operator] queue that have been there for four and a half years now. In [the Southwest Power Pool]...we’re looking at eight years start to finish on a project. In PJM we have projects that have been there since March 2019 – these projects were shovel ready. They have offtake contracts completed with full permits ready to start construction, just waiting on PJM,” Staples recounts. “Those have been put on pause. With queue reform it looks like they will get kicked out to late 2025, so that’s pretty severe for us.”

Tenaska, Staples says, is ready and willing to participate in interconnection studies and pay for transmission upgrades. And yet the ever-growing queue times, he says, continue to cost the company projects. Power purchase agreement negotiations have fallen apart, and options on land have even expired, as projects wind their way through the lengthy interconnection process – difficulties that can trigger the cancellation of an entire project.

Data from the Lawrence Berkeley National Laboratory show that interconnection queue times have increased dramatically since 2005, when a typical solar project could be built, start to finish, in two years. Today, the average developer can expect to need four years or more to complete a project, according to Joseph Rand, a senior scientific engineering associate tracking interconnection queues at the Lawrence Berkeley Lab.

But it’s not just that navigating the queue takes longer today than in the past decade, Rand says. Projects are also significantly less likely to succeed. Less than a quarter of the projects that enter interconnection queues around the U.S. will make it through to completion. Between the delays and the need for developers to hedge their bets, the U.S. currently has roughly 700 GW of solar, 400 GW of energy storage, and more than 200 GW of wind energy sitting in overflowing interconnection backlogs – just gigawatts shy of what the Biden administration projects is needed to generate 95% carbon-free energy by 2035.

“Our backlogs are indicating that our wind and solar developers are eager to meet that demand,” Rand says, “but that our transmission and interconnection system and procedures are not keeping pace with meeting that demand.”

So how did we get here? After decades of dominating the energy and technology scenes, the U.S., it seems, got complacent. Instead of upgrading the grid and related bureaucratic systems, industry, regulatory and government leaders took a business as usual posture that assumed the nation’s traditional ad hoc, bottom-up approach to energy development would work for renewables, too.

And it did – partially. But the bottlenecks this process creates, experts say, now threatens the nation’s ability to transition to clean energy with the same speed seen in countries with more cohesive regulatory systems.

Legacy Transmission

One of the fundamental problems contributing to interconnection backlogs around the nation, Rand says, is the lack of transmission. If you could somehow set all the other issues aside – the rapid pace of the energy transition, the inefficient regulatory system, the labor shortages – the U.S. still wouldn’t have enough transmission to connect all the incoming renewable energy to the grid.

Yet it’s not as though the U.S. just stopped building transmission. According to the latest numbers from JPMorgan Chase, U.S. transmission has continued to grow at a steady – albeit slow – pace of roughly 2% per year.

The problem, according to Liza Reed, electric transmission research manager at the Niskanen Center think tank, isn’t so much a lack of transmission in general, but a lack of specific kinds of transmission needed to facilitate renewable energy generation. Renewable generation, she says, requires long-distance, high-capacity transmission. And to understand why the U.S. hasn’t built that, you have to go way back in the history of the electric grid – long before the energy transition glimmered on the horizon.

Because the U.S. was an early adopter of electricity – and therefore of transmission technology – there was no central plan or vision for a national electric grid when the first lines went up. Instead, Reed says, transmission became a local issue, with utilities and grids and interconnections all scaling from the ground up as the system grew.

“The system built out very slowly, but quite expansively. There is electricity all over the United States now,” Reed says. “And it’s largely been a victim of a successful engineering system that works until it doesn’t.”

Even though the scale of the grid grew, regulation of the grid remained – and remains to this day – a primarily local concern. Sure, the Federal Energy Regulatory Commission has some limited authority over transmission, but permitting is still managed at the state level, where each state sets its own rules and priorities.

“I’d describe transmission as a federalism mismatch – the law has not kept up with the regional and national impact that the grid has,” Reed says. “The necessity of sharing power, planning together and having an established set of criteria – none of that has been federalized or standardized, even as the impact of our power systems are seen on a broader scale.”

Now that this system is in place, it’s difficult to go back in and assign oversight of transmission to a federal authority, because the states interpret that as an attempt to seize their authority, Reed says. And to complicate matters, states have generally tasked their public utility commissions with regulating for the least-cost option within a relatively short planning period, such as 10 years.

“Even though transmission is a small percentage of the cost of electricity and the transition toward electrification ... it is visually the biggest, so it becomes an avatar for ‘what are we paying for,’” Reed says. “You need a single transmission line for a lot of other projects, but that transmission line has a dollar sign next to it and it’s large.”

That means, Reed says, that it’s much easier for a PUC to approve a new gas plant, which can be constructed near existing transmission, than to approve the construction of a high-capacity transmission line that will unlock a swatch of wind or solar projects, which much be located where the natural resources exist.

Bhaskar Ray, vice president of interconnection and development engineering for energy developer Qcells USA Corp., has observed that this dynamic can manifest in ways that resemble the NIMBY – or "not in my back yard" – phenomenon. But the reality, he says, is much more complicated, with each state looking out for its own interests.

“Whenever you try to build a new line between states, the states start playing politics and saying why should we build a line through Arizona when California gets all the benefits, and vice versa,” Ray says. “That kind of game has got to stop.”

Systemic Delays

The energy transition began with this groundwork for delays already in place. At first, only a couple renewable projects came online at any given time, so utilities and regional transmission organizations had no trouble keeping pace, recalls Dave Gahl, executive director of the Solar and Storage Industries Institute. But then a handful of projects turned into hundreds, and the influx caught many entities flat-footed, Gahl says.

It wasn’t just that the needed transmission didn’t exist, Gahl says – many transmission authorities failed to allocate an appropriate number of staff to the interconnection process, and existing processes and procedures were woefully inadequate to the task of processing hundreds of requests all at once.

Take the interconnection process itself for example. Regional transmission organizations, generally, do not share enough information publicly for a developer to easily identify the best, most cost effective locations to connect to the grid, Gahl says. So developers have to apply for interconnection with incomplete information – and may learn during the study process that a project will be financially or technically infeasible.

This process has also forced developers, in some cases, to apply for interconnection as a sort of exploratory exercise to identify the best locations to connect to the grid, and therefore to construct projects. But these exploratory efforts take time and resources to study just like any other project – and add to the overwhelming surge of projects waiting for attention from an RTO or utility.

“You want to build the project, but you don’t know where to put it and the only way to get the information is to put in an application,” Gahl says. “Seems to me there is a better process.”

The queue system further exacerbates this dynamic, Staples says, by assigning projects priority status according to when they enter the queue on a first-come, first serve basis. As queue lengths began to expand with growing numbers of projects seeking information on the grid, developers began to submit their interconnection requests earlier and earlier in the development process in an effort to essentially hold their place in line, Staples says. This meant projects began to enter the queue before offtakers or property rights had been secured in some cases – further holding up the process, which in many regions still does not allow a project to jump ahead if the applications ahead of it aren’t prepared to begin the study process.

These early-stage projects, which some have complained are essentially speculative, have drawn numerous complaints and triggered some RTOs to take steps that make it harder to enter and remain in the queue – to the frustration of renewable energy developers.

“Maybe there are some people who carpet bomb the queues with speculative projects, but I think in general they appear to be speculative because people know it’s going to take five years to get through the process, so you have to do that early on,” Staples says. “It would be unwise to fully develop your site prior to entering a queue that you have no certainty on getting through, especially because so many things can change in five years. In a sense, every project is speculative until it can get through the queue process.”

Efforts by some independent system operators to create “clusters” of projects for simultaneous studies have helped make it easier to get through the queue, Staples says. But the clusters have come with their own unique challenges. The large number of projects initially assigned to each cluster means the first series of studies completed tend not to be particularly meaningful or useful, he says. As more projects drop out and the cluster group becomes smaller, the studies become increasingly specific – but after a certain point, each time a project drops out of the cluster, it triggers the need to revisit and revise completed studies. Cost estimates derived from what are supposed to be late-stage studies can still prove highly volatile.

“It’s still taking five years,” Staples says, “but I don’t see how MISO for example would process that many hundreds of requests in a serial fashion, so it seems essential to have a cluster process.”

Emerging Solutions

As complicated as untangling the queue backlog may sound, there is some good news, according to Rob Gramlich, president of Grid Strategies and co-founder of both Americans for a Clean Energy Grid and the WATT Coalition: fixing the interconnection process is currently among FERC’s top priorities.

At the top of the to-do list, Gramlich says, is sorting out a regional transmission planning process so that in the future transmission is built where it’s needed, and not just where it’s the cheapest or easiest. FERC issued a proposed rule on the subject in April.

Also near the top of the list of needs, he says, is restructuring the interconnection process itself.

“The RTOs are faced with massive lists of generators in the queue, and a dysfunctional process where if one project drops out then others need to be restudied,” Gramlich says. “So the amount of restudy and churn in the queue with projects coming in and out is really unmanageable right now.”

The solution to the problem is two-fold, Gramlich says. Transmission managers must make more information publicly available about their systems so that developers don’t need to apply for interconnection just to determine whether a project is viable. Then, RTOs and generators must be bound by reciprocal expectations that make it harder to miss study deadlines and to drop out of the queue without penalty.

FERC initiated a second round of transmission rulemaking in June that takes aim at these issues. The interconnection reform package FERC envisions includes implementing a first-ready, first-served model, penalties for transmission planners who miss study deadlines, and calls for the adoption of new technologies that would speed the interconnection process.

That last piece, Gramlich says, is an oft-forgotten, but important potential solution to interconnection gridlock. Energy storage, for example, could function as a transmission asset, allowing grid operators more flexibility in how they connect renewables to the grid. Other technologies such as power flow control and optimization software could further enhance RTOs’ ability to accommodate more renewable energy on the grid without extensive transmission upgrades.

“Unfortunately it’s going to take some time,” Gramlich says. “There’s not a magic wand here to eliminate the problem immediately. We’re going to have to build our way out of it, and work our way through the queues, sorting the projects and meeting the timelines – and that takes time.”

So in the meanwhile, some developers have considered taking things into their own hands. Qcells, according to Ray, has begun doing internal studies to locate the project sites with the best transmission resources and shortest interconnection queues.

“That is a strategy we are doing and seeing some degree of success, where we are sailing to the finish line,” Ray says. “But not all developers have the in-house technical capabilities to accomplish that amount of study to understand where we have to go.”

Qcells has also entertained the prospect of entering the transmission business itself by building the transmission projects it needs to complete its generation projects, and then selling that transmission capacity to other developers.

“Developers like NextEra have already gotten into building merchant transmission, and third-party transmission is very much welcomed,” Ray says. “If there are FERC incentives to get into the transmission construction business, we’ll consider it.”

Even with industry and regulators working toward solutions, Rand still believes it could take several years to work through interconnection and transmission backlogs and get the energy transition in full swing. But there’s still reason for optimism, he says.

“Can we hit 100% clean energy by 2035? I get less and less optimistic every year and that’s sad,” he says. “But I will say that – this is a back of the envelope calculation – but we estimated that if all the capacity currently in queue today, wind, solar and storage, if we built that by 2030, we would hit 80% clean electricity share. And that’s factoring for load growth... The transition is right at our fingertips, but to realize it we need to reform our interconnection and transmission processes.”

After years of studies showing a national transmission system is the most cost-effective way to meet growing clean energy and carbon reduction mandates, there is still no nation-spanning solution.

New initiatives at the Department of Energy and the Federal Energy Regulatory Commission are refocusing on that goal. A modern “macrogrid” could access the nation’s diverse clean energy from coast to coast to affordably protect against extreme weather, cyber, and demand spike reliability threats, power system analysts told a March 15 Department of Energy (DOE) webinar.

“A national macrogrid system is an important concept and FERC’s outreach to state and regional stakeholders and DOE’s ongoing study can resolve a lot of the doubts about it,” former Federal Energy Regulatory Commission (FERC) Chair said James Hoecker, now Husch Blackwell senior counsel and energy strategist and Hoecker Energy Law and Policy principal told Utility Dive.

The longstanding hesitation on building a nationally interconnected system “shows the lack of political courage to deal with tough issues, and recent power outages in California and Texas show the consequences,” added former FERC Commissioner Nora Mead Brownell, now a venture partner with Clean Energy Ventures. “An independent DOE review can show the economic, social, and environmental benefits are far greater than the costs of inaction.”

The proposed 2023 Biden budget’s over $3 billion for new transmission adds momentum to a DOE National Transmission Planning Study and FERC efforts to answer key questions like who will pay and where to build, transmission analysts said. Joint federal, regional, and local advocacy could be the way to resolve objections to connecting the nation, they acknowledged.

A nation interconnected

Today’s patchwork U.S. transmission system is inadequate to integrate new clean energy resources, stop rising electricity costs and protect against operational, environmental and cyber threats to reliability, system analysts agreed.

Those can be benefits of new links between now disconnected sections of the system, according to the DOE's National Renewable Energy Laboratory 2020 Seam study. Such links would allow "substantial energy and operating reserve sharing," and return $2.50 or more in benefits for every dollar invested in transmission, the study found. 

Barriers to linking the seams, especially those to fairly allocating costs among beneficiaries, were highlighted in a June 2020 FERC report to Congress.

But if barriers to inter-regional transmission building were overcome, a national transmission system could offer even better solutions than stitching together the seams, Energy Systems Integration Group (ESIG) Associate Director Debra Lew told the DOE webinar.

ESIG’s proposed high voltage direct current (HVDC) backbone “macrogrid” version of a national system “is the electric system's national interstate highway system," Lew told Utility Dive. A macrogrid can cost-effectively deliver the new clean energy resources needed to meet the Biden 2035 100% clean electricity goal, she said.

ESIG proposed an approach for a macrogrid design and identified studies needed to assess the macrogrid's technical and operational reliability and cost-effectiveness in a February paper. ESIG also proposed a “looped circuit” architecture that would maintain reliability on a macrogrid even if a transmission line went out unexpectedly.

But like most previous studies, ESIG did not consider every factor pertaining to regional transmission organizations, independent system operators and other power system stakeholders, Lew acknowledged.

DOE’s National Transmission Planning Study is part of its Building a Better Grid Initiative enabled by 2021’s Infrastructure Investment and Jobs Act (H.R. 3684). DOE’s Pacific Northwest National Laboratory and National Renewable Energy Laboratory will work with power system stakeholders on a comprehensive study for meeting the Biden 2035 goal.

An HVDC macrogrid is only one of DOE’s scenarios, but the paper’s modeling shows "it is the best choice," Lew said. New advanced technologies like dynamic line ratings and advanced conductors make meeting the challenges of a high renewables penetration system more feasible, other power sector analysts agreed.

Expansion of inter-regional transmission planning and development are valuable steps forward in meeting federal and state clean energy policies, both Tammy Ridout, spokesperson for U.S. transmission development leader American Electric Power, and Matt Lindstrom, spokesperson for the Midwestern transmission developer Xcel Energy, agreed. 

But detailed transmission planning that answers all stakeholder questions is still lacking, most observers agreed.

Ways to get there

The federal agencies and transmission advocates now intend to convincingly show how to build a national transmission system.

At least seven comprehensive studies since 2017 from authoritative research institutions like MIT, NREL and Princeton have failed to produce significant new inter-regional transmission, an October 2021 Brattle Group and Grid Strategies study found.

Key study shortcomings included not incorporating actual state clean energy policies, not identifying feasible transmission projects, and not showing granular economic benefits, Brattle found. Studies also often omitted solutions to barriers like cost allocation, siting and permitting, it added.

While DOE works to answer these and other daunting questions, there is federal and regional policy work that could move transmission forward, Brattle Group Principal Hannes Pfeifenberger said.

One is FERC’s April 21, 2022, Notice of Proposed Rulemaking, or NOPR, on transmission planning, cost allocation, and generator interconnection reforms, he said. Its concerns about threats to reliability from emerging renewables, changing loads, and new technologies echo DOE’s concerns.

Other justifications for regional links could come from either federal legislation requiring regional sharing of reliability "for extreme weather events or renewables variability” or a national clean energy standard allowing FERC to order transmission for integrating new renewables, Pfeifenberger said. But neither is currently feasible in today's Congress, he acknowledged.

Utilities' past resistance to inter-regional transmission to protect their own generation's revenues can be overcome, Pfeifenberger said. The opportunity for so much new rate-based capital expenditures would be a “major expansion” of the more than $20 billion now invested annually in transmission and would be an incentive to utilities, he said.

But some see broader obstacles to a national transmission system. Unlike the national interstate highway system, we do not have a “bipartisan national sense of shared purpose on renewables, decarbonization, and transmission,” former FERC and DOE staffer and consultant Alison Silverstein said. “And we have many more spending priorities,” she added.

But federal action can change that, stakeholders agreed.

What DOE can do

DOE's Transmission Planning Study will compare a macrogrid-like national system scenario and a scenario for closing inter-regional seams with today's scenario leaving it to each region to meet the Biden 100% clean electricity by 2035 goal, said NREL Senior Analyst and Economist David Hurlbut.

To prevent DOE’s study from ending up on the shelf like others, it must involve the organizations, planners and engineers that build transmission, former Wisconsin utilities commissioner Lauren Azar told the DOE webinar. It could also incorporate 2021 Infrastructure Act-granted leverage to authorize new national interest transmission corridors, Azar added.

“A lot of what happens will be determined by how good the DOE study is and how effective the department is at coordinating its effort with stakeholders,” agreed former DOE and FERC staffer Silverstein.

“This study’s public outreach process will make all costs and benefits of a larger system clear,” NREL’s Hurlbut promised. And it will “add transparency to the process” by presenting interim preliminary results to the public and a technical review committee made up of RTO/ISO and utility planners, state regulators, environmental groups, and others, he added.

The estimated timeline is “about two years” because “we expect to do a lot of new analysis which cannot be done quickly,” Hurlbut said. “Sooner is definitely better because penetrations of variable renewables are growing,” but effort could be wasted if the study is done “faster than the institutional capability of approving transmission,” he said.

New transmission solutions will be needed “before higher renewable penetration begins to cause increased cost and decreased reliability,” Arkansas Public Service Commission Chair Ted Thomas emailed Utility Dive. That means “we better get started fast,” 

The biggest opportunity in this study “is finding ways to deliver the most amount of clean energy at the lowest cost with the minimum impacts on the power system and the environment,” Hurlbut said. But the biggest obstacle is demonstrating “the benefits of those solutions in ways that can be used for the next stage of transmission’s evolution,” he added.

Researchers will set aside concerns about opposition from vested power sector interests because “they often change their perceptions of what is in their interests as the process evolves,” he said.

Though it may not be completed before a final FERC rule, the final DOE study will be “a complete response to FERC’s NOPR,” and “will hopefully inform future FERC transmission reforms,” Hurlbut said.

That means important questions on transmission planning will be open for FERC and its stakeholders, analysts and former commissioners said.

What FERC can do

Many of DOE’s concerns about reliability, emerging renewables, changing loads, and new technologies were echoed in an Oct. 12 filing by the National Association of Regulatory Utility Commissioners (NARUC) in FERC’s docket on transmission reforms.

NARUC’s filing followed the formation last June of the FERC-NARUC Tack Force to develop federal-state cooperation on those concerns, according to FERC’s announcement of the task force.

Key among the concerns is a need for better FERC guidance on how to allocate transmission costs based on how the benefits for large-scale inter-regional projects are shared, former FERC Chair Hoecker said. “The different RTO/ISO allocation schemes have become a puzzle with pieces that don’t fit together,” and a FERC ruling could provide “equitable cost allocation principles” to guide future transmission development, he added.

But FERC should maintain “the foundational principle" that transmission costs should be allocated to benefits “solely within the transmission planning region,” NARUC’s filing cautioned. This could keep the puzzle pieces described by Hoecker from fitting together.

RTO/ISOs are “largely caught in the middle between FERC and state-level stakeholders protecting their own local interests,” former FERC commissioner Brownell said. “We need to move away from that kind of cost allocation.”

State regulators and stakeholders may be intimidated by the sheer size of trillion-dollar inter-regional transmission proposals, she said. But “a cost allocation process with clear data on how that may be significantly less than the cost of cyber-attacks and extreme weather could help change their minds,” she added.

New approaches “are beginning to value long-term inter-regional reliability and resilience benefits that far exceed the narrow geography of the current cost allocation calculations,” Silverstein added. A national transmission system offers “national security, environmental, and economic benefits for our children and their children, and FERC can use the NOPR to develop that perspective,” she added.

If the focus of transmission planning was broader, it would show significantly greater benefits and that could lead to transmission-building opportunities, agreed Charles Marshall, vice president of transmission planning for independent FERC-regulated transmission utility ITC Holdings Corp. But that requires a “refocusing of transmission planning policy,” he said.

NARUC endorsed reforms to "better align regional transmission planning with state needs and ensure meaningful opportunities for the states to provide direction and input,” its filing said. FERC should allow the region's stakeholders "to evaluate transmission system needs,” choose “resources that states want,” and “refrain from establishing overly prescriptive rules.”

By taking on hard issues like cost allocation, the FERC NOPR can make incremental progressive improvements in transmission planning, but that may not lead to a macrogrid, former FERC Chair Hoecker said. The “missing piece” is a vision of how to politically achieve the transmission that is needed and “neither the FERC nor the DOE has articulated that vision yet,” he said.

An urgent issue

The “atmospherics” for a national transmission system are as good as they've ever been, Hoecker acknowledged. "But I hope advocates are not blind to the difficulties that still exist in the law and in communications with stakeholders up and down the value chain.”

It is time for Congress and the business community to recognize the need for a national transmission system as “an urgent national issue” and address those difficulties, Brownell said. An “independent accurate analysis of benefits and of the costs of not acting can make that happen, and the current efforts at FERC and DOE can lead the way.”