Ryan Kelley, chief investment officer at fund manager Hennessy Funds, does not like risk. So when major utilities began to announce sales of their unregulated renewable energy assets about midway through the COVID-19 pandemic, he was rather pleased by the news.

“Utilities are that excellent space where they will tell you, here is our plan for the next five years, and they will mainly make those projections,” Kelley said. “Some people call that boring. But at the end of the day, I like boring.”

But if utilities represent, to an investor, stable and predictable returns, renewable energy does not. Solar might be the hot item on the market for large valuations and high earnings potential, but right now, Kelley — and his clients — are looking for safe places to put their money. And they view renewable energy, and solar in particular, with a growing degree of skepticism after several years of project delays and missed earnings projections.

Apparently sensitive to this growing trend among investors, major utility companies began to sell or spin-off their unregulated renewable energy assets — and some fossil generation as well — in 2021, according to Chris DeLucia, a director within the gas, power and climate solutions group at S&P Global Commodity Insights.

Beyond a hope that investors will award utilities that sell off competitive assets with higher valuations in the stock market, DeLucia and other analysts say multiple co-occurring trends have opened a window for spinning off renewable assets in return for handsome profits in a financial environment where raising capital is increasingly difficult. But while investors and even renewable energy developers might like to see more focused business models from utilities, analysts are split on whether this trend represents a long-term shift in business strategy.

Competitive assets for sale

While it’s hard to ignore the sheer size and number of renewable asset sales coming out of electric utilities, these sales are part of a broader market trend affecting the entire energy industry, DeLucia said.

In spite of policy support and rising demand for renewable energy, energy markets are particularly volatile right now, DeLucia said. The renewables sector has seen increased competition from startups and legacy oil and gas companies, supply chain constraints, permitting issues and interconnection delays. And as a capital-intensive industry, it’s particularly vulnerable to rising interest rates, DeLucia said.

“When you look at the power sector, there is a lot of change happening and a lot of volatility,” he said. “The outlook has become more muddied.”

At the same time, investors are weighing the possibility of a recession and moving their money to safer, more stable outlets, according to Benjamin Baker, managing director for Greenbacker Capital, an asset management firm focused on renewable energy. There’s also a general move among investors toward more focused, simplified business models and away from conglomerates, Edward Jones utilities analyst Michael Doyle said.

“Across the market, the companies that have a lot more focus on a particular business tend to receive better valuations,” Doyle said. “Over time, investors said this [conglomeration] doesn’t make sense. We would rather buy a more focused business” with a clear strategy for growth.

This dynamic could explain why recent utility spin-offs haven’t been limited to renewable energy assets. In May, NextEra Energy Partners announced plans to sell its natural gas pipelines in order to become a 100% renewable energy company, with CEO John Ketchum saying the move was inspired in part by investors who had indicated they would put more money into a “pure play” company. Dominion Energy has also sold some of its competitive gas assets, citing a similar strategy of simplifying its business.

But NextEra, DeLucia said, is an outlier, as the bulk of the companies looking to streamline and sell are unloading competitive renewable energy portfolios — including some that recently acquired those assets. Con Edison, which acquired renewable energy assets from Sempra in 2018, turned around and sold them to RWE in 2022 for $6.8 billion. AEP followed a similar pattern, buying renewable energy projects from Sempra in 2019 and selling for $1.5 billion earlier this year.

Duke Energy became the latest company to sell its commercial renewable portfolio when it reached a $2.8 billion deal with Brookfield Renewable in June.

Although he did not name specific companies, NextEra’s Ketchum criticized the utilities putting renewable portfolios up for sale and warned investors not to use these sales as a means of evaluating the value of NextEra’s assets during an earnings call on July 25.

“Those are not what I would characterize as high quality renewable energy assets,” he said. “We’ve worked hard to get quality assets. I like to believe, and we’re not perfect, but we don’t make some of the same mistakes that you see the other developers make. We are much better positioned.”

But the sales seem likely to continue, said Jeremy Klingel, a senior partner covering energy and utilities at digital services firm West Monroe. Utility companies with smaller to mid-sized renewable energy portfolios seem especially likely to sell, he said. These companies have always seen renewable energy as something “interesting and tangential,” something that they could be easily persuaded to sell if the right deal came along, he added.

Some bigger portfolios are still expected to hit the market in the near future as well. And that, analysts say, is simply because now is a good time to sell.

Seller’s market

In spite of market volatility, demand for renewable energy continues to boom, propelled by private and government interest in decarbonization. That demand has exceeded the grid's current capacity for new projects, and where there is an imbalance between supply and demand, prices tend to rise. That, Baker said, is what has transpired in the renewable energy sector.

“We are seeing solar farms and battery storage projects go for valuations that are much higher than we ever thought they could,” Baker said. “Even in light of inflation and [higher] interest rates and things that mathematically should cause the value of assets to go down, there has been such a fervor for this type of investment, that asset prices are not going down.”

At the same time, the price of raising capital has increased. So if a utility has a need for financing, and “if they can sell a solar farm for $5 million, that’s way cheaper than to take money from someone like us,” Baker said.

And utilities do have a need for financing, Klingel said — especially some of those that have sold large renewable energy portfolios recently like Con Edison. U.S. demand for electricity has accelerated in recent years thanks not only to economic growth, but also the growing popularity of electric vehicles and emerging trends toward building electrification.

The grid, Klingel said, is unprepared for this growth, so many utilities have found themselves in a position where they need to make massive investments in transmission and distribution. Given the lending environment, the timing of these transmission shortfalls could perhaps be better. But as Klingel sees it, this isn’t a terrible outcome for utilities.

“You’re getting a return off the assets that you developed on the renewable side, you’re walking away with a potentially significant upside depending on how those deals work, you get to focus on your core business which will be more lucrative in the near-term because of additional infrastructure funding, and you get to reduce your risk associated with the deregulated side,” Klingel said.

These prospects are particularly tantalizing to investors like Kelley, who previously saw a similar trend in the natural gas sector in 2011. At the time, Kelley said, natural gas utilities faced something of a reckoning after a series of fatal pipeline explosions led to criticism that the distribution system’s old, cast iron pipes were unreliable. That prompted the federal Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, which created regulatory programs to improve the safety of the nation’s natural gas pipelines.

Over the past 12 years, regulators and utilities have invested billions in pipeline modernization. And the great thing about these safety measures, Kelley said, is that the replacement and maintenance of the pipes are capital expenditures that get added to the rate base, which means customers pay for the upgrades while the utility’s earnings per share and dividend growth accelerate, driving increased returns for investors.

“So I think this is basically history repeating itself, but on another side of the utility business,” Kelley said. “We saw it with natural gas, and now we’re going to see it ... with the electric grid.”

Development or distribution

Patrick Worrall, vice president of the asset marketplace at LevelTen, believes a more focused utility sector with fewer competitive assets could be good for renewable energy developers as well. Interconnection backlogs driven in no small part by a lack of transmission remain one of the biggest problems plaguing renewable energy developers, and while a few private companies have tried to address this themselves, utilities just seem better at transmission development than private developers, Worrall said.

“Regulated utilities tend to have a mindset that is pretty conservative, and there is a huge need in the energy transition for a focus on transmission — an area where you need to have a conservative and patient mindset,” Worrall said. For utilities to focus on transmission and renewable energy developers to focus on building renewable energy should be a boon to all, he said.

That benefit should extend to investors as well, Baker said, given the scale of the renewable energy portfolios changing hands. Utilities may not be full-time renewable energy developers, but some hold assets that rival those of the largest development platforms. NextEra, Worrall said, probably owns the largest renewable energy platform in the U.S. — though nobody expects NextEra to sell it any time soon. Companies that have sold renewable portfolios have in some cases earned more than $5 billion — a considerably larger sum than most existing portfolios are worth. After the top 10-15 renewable energy developers, Worrall said, “you very quickly get to much smaller [portfolios], a couple billion or less.”

To sell an asset of that size and value, you need to find a buyer who has enough capital to pay. And in the case of these utilities, Baker said, that’s increasingly limited to other large utilities, large-scale developers with comparable portfolios, and investors interested in holding large portfolios — the Blackstones of the world. Indeed, AEP’s 2023 portfolio sale went to Blackstone Infrastructure, a pension fund, and developer Invernergy. Con Edison sold to another utility, RWE. Duke sold to one of the nation’s largest renewable energy developers.

But as investors and developers consolidate these assets into ever-larger portfolios, Baker said, they’ll eventually run out of potential buyers — there simply won’t be anyone large enough left to pay for them. That will leave the owners of these assets, whoever they ultimately are, with two remaining options: hold, or go public. And no one in the investment community is complaining about the possibility of renewable energy IPOs.

“There is a dearth of publicly traded, pure play renewables in the market, and I think people would be excited to see those,” Worrall said.

New paradigm or business as usual?

Generally speaking, investors who watch the renewable energy space don’t believe we’ve seen the end of renewable energy spin-offs from regulated utilities. Several interviewed for this story indicated they had information suggesting additional large sales are in the works, though the utilities named did not respond to requests for comment on this story.

Even so, the window of greatest opportunity may be closing, said Doyle, who pointed to the fact that the Duke renewables sale took longer than initially expected. Much like the housing market, high valuations in the renewable energy sector were driven at least partly by the low interest rate environment that followed the onset of COVID-19, he said. Higher interest rates have eroded the value of renewable energy portfolios and caused market demand to cool.

So was this whole era of utility-owned competitive renewable energy a flash in the pan, or has it set the stage for a new business cycle where utilities develop competitive assets that they can sell opportunistically to raise capital? Analysts’ opinions are mixed.

Klingel believes many utilities may jump back in to deregulated energy development if the market conditions are right — and the timeline for the shift back to development could be relatively short, given the number of new opportunities created by the Inflation Reduction Act. Energy storage and solar panel manufacturing are interesting opportunities getting a lot of attention in the press, but the real “dark horse” on the horizon, Klingel said, is hydrogen.

“Given the complexity of the infrastructure required to support [hydrogen], it would not surprise me if utilities and utility holding companies continue to see that as their future business,” he said.

Crystal balls are always cloudy, Klingel said, but if the interconnection situation turns around he wouldn’t be surprised to see utilities jumping back into competitive energy development in the next 12-24 months.

Baker is less certain. It seems likely, he said, that utilities could find success going either direction — either getting back into competitive energy development after selling for a profit, or sticking exclusively with regulated assets. But investors, Baker said, do prefer a business model that is simple and easy to understand, and it might be better for everyone if utilities stayed focused on transmission and distribution.

“The one thing I would bet on is humans being in a constant loop of repeating the things that they did in the past in a slightly different way,” he said. “Every business cycle is just long enough for a whole new group of people to examine a business model and say, well, they all failed, but I could do this better.”

Historic clean energy investments propelled by Biden administration climate initiatives are shifting energy economics in ways that have developers, investors and analysts recalculating clean energy’s value. 

By 2050, Biden initiatives could grow U.S. wind capacity 235% and solar capacity 1,019%, with proportional battery storage growth, according to the Energy Information Administration’s Advanced Energy Outlook 2023, published in March. Already accelerating growth has driven up renewable energy prices and left builders and buyers scrambling to find the lowest cost investments, analysts reported.

New utility-scale solar, paired solar and storage, utility-scale onshore wind, and paired wind and storage, even without subsidies, clearly have the lowest levelized costs of energy, or LCOEs, of the full range of utility-scale generation options, according to the April 2023 Lazard LCOE report.

But “the least-cost solution is no longer just the lowest LCOE, it is an evaluation of how renewables fit into a power system,” Wood Mackenzie Vice Chair, Energy Transition and Power & Renewables, Christopher Seiple told Utility Dive. Comprehensive procurement requires evaluating the “proposed project’s specific location and output profile, its interconnection costs, and the system’s transmission and reliability needs,” he added.

Comprehensive project evaluation is especially necessary and complicated now with renewable energy contract prices spiking since late 2022 in response to a range of policy and economic drivers, market watchers including LevelTen Energy and Edison Energy agreed.

“There is no easy way to identify the lowest [renewable energy] project prices because the project and macroeconomic factors compound” as value is forecast, Edison Energy Managing Director, Renewables Advisory, Joey Lange said. “Even where renewables were recently the most economically viable, market congestion and price suppression are making them harder and more expensive to build,” he added.

IRA-driven demand, interconnection backlogs, interest rate turmoil and supply chain constraints are driving spikes in new renewable project prices, analysts and stakeholders said. But the magnitude and duration of those factors are uncertain, making a more sophisticated project analysis necessary and offering a new appreciation of how the suboptimal renewable energy project choice can deliver the optimal value in cost-effectiveness and locational benefits, they said.

The big picture

The average power purchase agreement, or PPA, price in North America rose 6.6% during Q1 2023, with solar project PPAs up 8.5% and wind project prices up 4.9%, LevelTen reported in April. And that price increase might actually have been as high as “almost 11%,” when measured across “almost every market and technology,” according to the Edison Energy Q1 2023 Global Renewables Market Update Report. 

Final Q2 data has not been released but the trend of higher PPA prices, though moderating slightly for solar, has continued in 2023’s second quarter, with uncertainties subject to multiple market dynamics as the key price drivers rise, both LevelTen and Edison Energy said. Though some details of the 2022 Inflation Reduction Act are being clarified, the uncertainties due to slow federal guidance remain frustrating to developers and investors, Edison Energy added.

The IRA extends solar’s investment tax credit to standalone storage and its 30% deduction of project costs may be significantly increased by adders for qualifying projects, analysts reported. In addition, the IRA extends wind’s production tax credit to solar projects that choose it, with similar adders that could bring the deduction to as much as $23/MWh, they added.          

The unsubsidized LCOE for new utility-scale solar is as low as $24/MWh and the LCOE for broadly calculated new paired solar and-storage projects can be as low as $46/MWh, Lazard reported. The lowest unsubsidized and broadly calculated utility-scale onshore wind LCOE is $24/MWh and the lowest broadly calculated paired wind and storage LCOE is $42/MWh, it found.

LCOEs for coal, combined cycle natural gas plants, and nuclear plants are non-competitive, Lazard showed. The $39/MWh low LCOE for new combined cycle natural gas plants is competitive with paired renewables and storage prices, though they come with emissions and volatile fuel prices, analysts agreed. 

But the lowest Lazard LCOEs calculated specifically for a 100 MW utility-scale solar project paired with 50 MW of 4-hr storage, $65/MWh, and calculated specifically for 100 MW of onshore wind with that storage, $33/MWh, challenge the economic competitiveness of natural gas in many locations, analysts added.

With these broad price advantages, the clean energy industries can learn to manage price dynamics due to growing pains like interconnection and supply chain constraints and IRA tax credit impacts, said former Edison Energy Senior Clean Energy Advisor and update contributor Lauren Kielley.

But multiplying near-term drivers leading in different directions and uncertainties created by most of those drivers make it difficult now to identify the best clean energy investments, many analysts agreed.

Drivers and uncertainties

Policy- and price-driven off-taker demand for renewables is growing while developers face policy and market factors obstructing supply, the recent LevelTen and Edison Energy market reports said.

IRA requirements and supply chain obstacles are driving up costs for components, raw materials and labor, and rising interest rates are making project financing more expensive and uncertain, said LevelTen Energy Director of Commercial Analytics Stefan Pugatchenko.

As a result of the uncertainties, 78% of Q1 2023 U.S. projects previously expected to be operational before 2025 due to increasing demand for renewables will be delayed, Edison Energy reported.

While various factors are driving up the price of renewable energy projects, macroeconomic factors like the Ukraine war, inflation and bank instability have kept natural gas prices atypically high, driving renewables’ market competitiveness, said former Edison Energy Advisor Kielley. But natural gas’ historic tendency to price volatility adds to renewable energy PPA price uncertainty, she added.

The push-pull of the many drivers and their uncertainties is what has driven PPA prices rapidly up in 2023, agreed LevelTen’s Pugatchenko.

“Easy interconnections are gone, projects are further from load, and interconnection studies cost more, which has led to a doubling or tripling of the project cost,” Edison Energy’s Lange said. And a resulting renewables demand spike has limited availability of the contractors who build wind and solar projects, which is likely to continue adding to project costs, he added.

In the last two years to three years, the momentum moving low-priced projects into operation “has moved in the wrong direction,” Lange said.

The push-pull of demand and uncertainty may not change soon.

Over 90% of surveyed developers expect price impacts from IRA provisions, but without IRS guidance it is uncertain whether the tax credits will drive PPA prices up or down, LevelTen reported.

And the “full impact of the IRA can’t be realized” without “large-scale change” to existing transmission, LevelTen’s Pugatchenko added. The new IRA incentives could drive both higher interconnection backlogs and renewables penetrations, leading to more transmission congestion, more negative market pricing, and new uncertainties in PPA pricing and contract terms, he said.

Those high renewables penetrations will be a key driver of new investments in dispatchable generation, Pugatchenko, Lange, Seiple and other analysts said. But the new IRA tax credits for energy storage, advanced nuclear, green hydrogen, and natural gas plants with carbon capture add to investor uncertainty about the best technology investment, they agreed.

Increased demand could drive renewable project costs down if some of the uncertainties are clarified and IRA benefits lead to lower project costs, Lange said. But it is not certain developers would lower PPA prices while off-takers are willing to pay higher prices, he added.

Upward price pressure on renewable energy projects could continue if utilities continue to commit to higher-priced renewable energy PPAs to meet stakeholder demand for more renewables, agreed consultant Karl Rabago, a former Department of Energy assistant secretary and Texas utilities commissioner.

And new tax credits for storage will help drive demand for batteries, Rabago added. IRA-supported domestic battery production could meet that demand and drive down costs, “but prices only fall with increased battery supply, and it is uncertain how renewables PPA prices will impact [storage] demand,” he said.

It is also not certain that offtaker demand for paired renewables and storage projects will increase, Kielley added. Off-takers benefit if the PPA price falls, but developers benefit if the price rises, and demand for those projects “may depend on aligning those interests,” she added.

Finally, emergence and sustained use of many of the policy drivers could be disrupted “by a political shift or a new administration,” said LevelTen’s Pugatchenko.

With this driver-uncertainty push-pull, finding the best-priced renewables may require a new kind of more sophisticated due diligence for off-takers, the analysts agreed.

No easy answers

Though many worry about the PPA price spike, some say it is largely inflation driven and only a near-term concern.

But in response to current demand, power providers are “looking now for the lowest-cost renewables,” said BloombergNEF Head of Research, North America, Tom Rowlands-Rees. The IRA “is likely to lower the cost for all renewables,” but the specific choices made by developers and off-takers will depend on legislation, regulation and location, he added.

“Some need renewables to meet state mandates, others have renewables but need storage, and some want to use local solar or offshore wind resources,” Rowlands-Rees said. The “logical” choice now “is investing in renewables and storage and preparing to choose firm capacity later, but regulation makes owning and operating rate-based fossil resources a better choice for many utilities,” he added.

To meet near-term renewable energy project demand, “some developers have moved from the best solar or wind locations to where permitting and interconnection are easier,” Edison Energy’s Lange said.

“There is no simple way to summarize all the variables, but it is not just the cheapest renewable generation or lowest cost PPAs because there are other dynamics,” agreed former Edison Energy Advisor Kielley. Some resources’ generating profiles, combined with some markets’ rules “provide the opportunity to capture alternative revenue streams like peak electricity pricing,” she said.

The best procurement processes for renewable energy projects seem to begin with detailed utility planning that leads to competitive developer bidding, said Wood Mackenzie’s Seiple. Xcel Colorado’s competitive procurement invites bids after identifying all “specific utility needs,” and California recent planning identified “zones where renewables would have the lowest cost and be most valuable for the system,” he added.

From the developer’s perspective, the challenge is also multi-factorial, but the factors are different.

“The utility’s concern is optimizing the per MW cost and reliability of the project, but developers have many levers to optimize cost and reliability,” said Giovanni Bertolino, head of Enel North America’s 3Sun USA development subsidiary. Developers face a “new due diligence” in “an equation to determine the most competitive bid” which should include “the resource site, the technology, and the system design,” he said.

“Maximize the resource, pick the appropriate conversion device, wind, solar or battery, and ensure the revenue stream solves the energy, capacity, or peak pricing problem,” agreed General Electric Vernova Onshore Wind Chief Commercial Officer Stephen Swift.

“There are averages, but the real-time answer is more complicated because it depends on the hour of the day, the day of the year, and the transmission node’s specific location,” he added. “Identifying the best renewable energy investment requires thinking at that level of detail,” Swift said.

In short, identifying the lowest cost clean energy investment may no longer be exactly the right objective, analysts agreed.

Changing objectives

Investing in clean energy begins with planning, and planning includes project specific considerations, agreed LevelTen’s Pugatchenko.

Planning clean energy projects is more complicated than it used to be because market conditions and prices “could be completely different by the time the project goes into service,” recalled independent policy and government affairs consultant Ted Ko.

And “the IRA legislation was not intended to complicate development but to move beyond building big projects to projects with local community and system benefits,” Ko said. That requires “recognizing how IRA tax credits can offset reduced project output and how new kinds of contracts with local partners and multiple off-takers, enabled by new IRA benefits, can streamline community acceptance,” he added.

The new reality may be that “a suboptimal resource to meet near-term needs is the optimal choice,” added BloombergNEF’s Rowlands-Rees. “Each path forward has limitations, but that does not mean progress stops, and even if the objective is the optimal investment, the definition of optimal can change.”

Two new reports examining hiring and recruitment data for companies in the renewable energy sector show them ramping up their demand for early-career hires, who in turn are joining the industry in record numbers.

The Interstate Renewable Energy Council’s latest National Solar Jobs Census shows a “booming” solar sector, said a release from the Solar Energy Industries Association, with 18- to 29-year-olds making up nearly a third of the solar workforce in 2022. Early career platform Handshake reports that U.S. energy employers increased outreach to students by 86% over the past year.

Eric Johnson, senior manager of talent acquisition at First Solar, said in an interview that the company has internally seen a “dramatic spike” in requests for interns, and it hired its largest-ever intern group this summer.

Previously, First Solar brought in the majority of its interns to work in the research and development division, Johnson said, but it recently has been adding roles for interns in manufacturing, supply chain, human resources, product and technology.

He said that he considers it an “area of opportunity” for the company to rework its intern program so that interns are able to get experience across multiple divisions of the company and be exposed to a variety of roles. 

The National Solar Jobs Census, released July 19, found that 34% of the industry’s jobs are in installation or repair, 6% are in manufacturing, 19% are in administrative, 20% are management roles, 16% are in sales, and 6% are “other.”

The industry will need additional workers in all of these roles, the report said.

Solar companies reported to the Interstate Renewable Energy Council that the three most difficult categories of positions to fill at their firms are management roles, engineer and scientist roles, and electrician or construction worker roles.

Overall, the companies reported that a small applicant pool is the biggest contributor to this difficulty. Despite a growing migration of young workers to the renewable energy sector, the U.S.’s bold decarbonization goals necessitate even more labor. SEIA said in its release that solar reaching 30% of domestic electricity generation by 2030 will require the workforce to grow to “more than a million workers” and said the sector still has “a long way to go” to meet that goal.

”The solar industry is expected to take off dramatically in the coming years, and despite gains in labor productivity, it will require hundreds of thousands more workers to keep pace with the growth in installations as a result of the incentives in the Inflation Reduction Act,” said IREC in a summary of the report.

IREC’s solar jobs census found that in 2022, 44% of solar industry employers said it was “very difficult” to find qualified applicants, the highest percentage the survey had recorded over the last 13 years. 

“This challenge comes with the territory for an industry that is growing rapidly and expanding into new geographic areas,” IREC said. “Mentorship programs, including registered apprenticeships, can be a valuable way to help people gain a foothold at solar firms, and are particularly helpful for women, BIPOC individuals, and other underrepresented groups seeking to advance in the industry.”

IREC reported that 38% of solar firms have a mentorship or sponsorship program, with 21% providing on-the-job training. Only 13% of firms had an internship program as of 2022, the report said.

Kate Urban, a senior research writer at Handshake and the author of the company’s July 20 report, said that the enthusiasm of First Solar and NextEra Energy for recruiting and training interns “stood out” to her when Handshake spoke to those companies.

“There's a lot of enthusiasm for early talent in this space,” she said.

Many renewable companies are in need of skilled trade workers and registered apprentices, but Urban said the industry also needs workers with backgrounds like engineering and cybersecurity. 

Looking ahead

Johnson said that First Solar currently does a majority of its manufacturing in Ohio, where it has a “well-oiled machine” of recruitment and often engages with community colleges and high school students who plan to go directly into the workforce after graduation.

Outreach with high school students has been “critical” for the company’s ability to fill manufacturing and skilled trade jobs, he said.

First Solar committed $1.3 billion to expanding its domestic operations earlier this year, bringing its investment in the U.S. solar supply chain to a total of $4 billion and expanding its manufacturing facilities. The company announced further investments last week.

The company is looking to replicate its Ohio recruitment strategy as it staffs a new facility in Alabama, Johnson said. 

Though the IREC census found that the total number of solar manufacturing jobs increased “only slightly” from 2021, there has been a post-IRA “flurry of announcements” for new domestic manufacturing facilities, “which if built could substantially increase manufacturing employment in 2023 and beyond.”

Handshake is geared primarily toward students at four-year institutions, but the platform works with community colleges and technical schools and is "growing into" offering services to more of them, Urban said. The report’s data, which focused on students at four-year institutions, shows a “real jump” in interest about the renewable energy industry from students in technology majors.

“I think as hiring in big tech has slowed down, there are a lot of college students who are open to other industries and looking for something that feels more stable and secure,” Urban said.

Overall, she said that the data she examined showed a 71% average increase in applications to jobs at renewable energy companies over the past year. 

Urban noted that students also seem particularly enthusiastic about the mission of the renewable energy industry. The University of California at Berkeley, one of Handshake’s higher education partners, has a sustainability-focused student organization that coordinates career fairs that connect renewable energy employers with students for roles like internships, she said.

Johnson said that after significant growth of First Solar’s summer intern program over the last two years, the company expanded the program to take on interns in the fall and spring. 

“The interest has seemingly spiked like crazy as people are pivoting their thought process to get into an organization like ours that is not only stable, but growing,” he said. “And it’s a company in an industry that’s trying to help the world, trying to change climate patterns. I think kids in school are seeing that, and the overall mission of the organization has driven them to us, as well.”

The Federal Energy Regulatory Commission’s generator interconnection reform rule issued last week will likely improve the bogged down procedure, but may do little to speed up the process across broad swaths of the country, according to lawyers and industry experts.

The central reform in FERC’s Order 2023 rule is a requirement that transmission providers adopt a first-ready, first-served cluster study process to weed out speculative projects in interconnection queues, Stephen Hug, a partner with the law firm Akin Gump Strauss Hauer & Feld, said during a webinar August 3.

However, it is unlikely the new rule will speed the interconnection process in regions that already study interconnection requests in clusters, Hug said.

Grid operators and transmission providers that study interconnection requests in groups, instead of one-by-one, include the California Independent System Operator, the Midcontinent Independent System Operator, the New York Independent System Operator, the PJM Interconnection, the Southwest Power Pool, NV Energy, PacifiCorp and Public Service Co. of Colorado.

Interconnection queues around the country grew 40% in 2022 compared with the year before, with more than 10,000 projects — representing 1,350 GW of generation and 680 GW of storage — waiting for approval to connect to the grid, the Lawrence Berkeley National Laboratory said in an April report. The vast majority of the planned projects are solar, storage or wind.

With FERC’s encouragement, transmission providers that use the cluster study approach are looking beyond the agency’s final rule, according to Hug. “They acknowledge ... even … a cluster study process that includes readiness requirements, site control requirements, is not sufficient to meet the current demands that are being placed on the queue,” he said.

More changes needed

Order 2023 is “an important step in the right direction,” but more changes are needed to address interconnection challenges, according to RMI, a non-profit group focused on reducing greenhouse gas emissions from the energy sector.

Most regional transmission organizations already use a cluster study approach, yet they are experiencing long interconnection wait times, RMI analysts said August 2 in a blog post.

The root causes of interconnection delays include a U.S. transmission system that has little spare capacity and that is largely built without consideration for planned generation and storage, the RMI analysts said.

“This leaves it up to the interconnection process to build the infrastructure needed to connect these new resources — an inefficient, piecemeal approach to grid expansion that places the financial burden on individual projects to build network upgrades that benefit the entire system,” they said.

Several FERC commissioners have said that the interconnection reform rule is a first step in broader efforts to improve the grid and bring generating and storage resources online, according to Ben Reiter, an Akin Gump counsel.

“If we really are going to connect the amount of renewable generation to meet state clean energy goals and the renewable generation that is now largely economical, thanks to the Inflation Reduction Act, we’ll really need holistic transmission reform,” Reiter said during the webinar.

FERC is working to release a rule reforming transmission planning and cost allocation in the “coming months,” the agency’s Acting Chairman Willie Phillips said last week.

Reform seen as ‘evolutionary improvement’

FERC’s interconnection reforms could resolve some of the planning challenges the electricity sector faces in handling the rapid growth of utility-scale renewable energy deployment, ClearView Energy Partners said in a note August 3.

Generally, the final rule, compared to FERC’s proposal, eased requirements on transmission providers and increased regulatory hurdles for interconnection customers, according to the research firm.

The final rule, for example, requires interconnection customers to pay a single upfront deposit to enter an interconnection study instead of several payments through the study process, a change that could strain project developers financially, ClearView said.

ClearView expects that during a transition period to the new rule, many proposed projects will likely remain in existing interconnection queues. FERC’s reforms are a “significant evolutionary improvement,” but not a revolutionary one, ClearView said.

Order 2023 will likely have major effects on the interconnection process, but its impacts will not be fully known until multiple cluster-based processes are completed, Vinson & Elkins attorneys said July 31 in a blog post. 

The rule will produce winners and losers, according to the attorneys. Interconnection customers that would otherwise languish in the queue will be able to proceed through the process faster, but some customers may find that continuing through the process is cost-prohibitive, they said.

Rehearing requests on the interconnection reform rule are due 30 days after it is published in the Federal Register. Transmission providers have 90 days after it is published to file their compliance plans at FERC.

Despite White House and other efforts, new transmission projects to deliver the growing amounts of clean energy in the U.S. to where it’s most needed face what some observers call a permitting “Valley of Death.” But non-transmission solutions can fill the gap, stakeholders agree.

President Biden’s policies and executive orders have initiated many new transmission approval strategies, but permitting remains “the poster child for how things can get held up,” Senior Advisor to the President for Clean Energy Innovation and Implementation John Podesta told a May 23 CleanPower 2023 conference audience.

Policy and regulatory agencies have “many ways to say no” to new development, leaving the potential for streamlined transmission expansion in serious doubt, BloombergNEF Head of Research, North America, Tom Rowlands-Rees told Utility Dive.

Even with historic Inflation Reduction Act funding, U.S. power suppliers “cannot deliver the energy transition” if it continues to take 10 years to permit and build the needed transmission, Berkshire Hathaway Energy Renewables President and CEO Alicia Knapp told the same Cleanpower audience.

But new technologies and materials and new ways to use renewables, batteries and distributed energy resources can get more from existing transmission, analysts, utilities and other stakeholders said. They cannot defer the need for new transmission indefinitely, but the urgency to reduce customer costs and meet clean energy goals mean the time for them has come, they agreed.  

The transmission deficit

Through 2022, 1,350 GW of generator capacity and 680 GW of storage were actively seeking interconnection to the transmission system, an April Lawrence Berkeley National Laboratory study reported.

Market congestion costs from insufficient transmission were an estimated $13.4 billion for ratepayers in 2022 and are expected to grow, a March Grid Strategies paper calculated. And much of the U.S. faces an elevated risk of energy shortfalls from extreme heat-induced demand spikes, added the May 17 North American Electric Reliability Corporation 2023 Summer Reliability Assessment.

In response, Biden administration initiatives will prioritize interconnection queue, permitting and cost allocation reforms to expedite transmission deployment, the White House announced May 10. There will also be new emphasis on the economic, reliability and climate benefits of new transmission corridors, inter-regional transmission, grid-enhancing technologies and line upgrades, it added.

The interconnection queues are not the whole story, said New York Independent System Operator Vice President of External Affairs Kevin Lanahan. New York’s “class-year” approach, which identifies the most substantial project proposals, accelerated approval of 27 generation projects totaling 7,452 MW in 2021, and more than 90 class-year generation projects are being studied, he said.

New Southwest Power Pool, or SPP, queue management practices initiated in January 2022 put it on track to eliminate its queue backlog by the end of 2024, added SPP Director, Grid Asset Utilization, Casey Cathey. A consolidated planning process that “merges and optimizes queue requests with regional long-term planning” can eliminate organizational silos, he said.

“There can be no transition without transmission,” but “there are still issue like land permitting outside of SPP’s control,” Cathey added.

“Too many jurisdictions have authority to stop new transmission development,” agreed Dynamic Grid CEO Kay Aikin. Other options can, however, begin increasing the power system’s capacity to meet policy goals, she added.

As battery storage costs continue to fall, it has emerged as a non-transmission solution, though opponents insist it must be located precisely to be cost-effective.  

Storage-as-transmission

In 2019, SPP studies of its first storage-as-transmission proposals showed it was a viable alternative to new transmission builds or upgrades but was not cost competitive because batteries were too expensive at the time, SPP’s Cathey said.

Even then, batteries strategically placed at congested nodes where load profiles of limited capacity lines allow energy to be stored when loads ease to offset later demand spikes could defer new transmission builds, Cathey said. SPP’s storage-as-transmission tariff was approved May 26, and costs are now or will soon be low enough to make properly located storage a viable least-cost option to transmission line upgrades, he added. 

National Grid’s $50 million, 8-hour, 48-MWh battery which deferred an estimated $250 million transmission line for Nantucket Island is an example of the right kind of use case, said National Grid Clean Energy Development Director Terron Hill. It remains the largest storage-as-transmission project in New England, he added.

Regulators, utilities and system operators must use planning criteria that value optimizing existing transmission with storage, said Long Duration Energy Storage Council CEO Julia Souder. That will require “recognizing that battery project costs might be offset by the ratepayer benefits of reduced [renewable energy] curtailment and deferred capital expenditures for transmission,” she added.

Independent storage providers are concerned about owners of storage-as-transmission assets bidding into energy markets, said Jason Burwen, vice president of policy and strategy at merchant battery provider GridStor. “Owners of storage-as-transmission receive cost recovery through rates and should not compete in markets,” he added.

The locational and regulatory limits on storage-as-transmission make new grid-enhancing technologies, or GETs, and advanced wires materials, which are easier and faster to deploy, the smarter near term choice as a non-transmission upgrade, their advocates insisted.

Grid-enhancing technologies

The most often-used GET, Dynamic Line Ratings, or DLR, can expand a transmission line’s carrying capacity in real time based on readings from sensors throughout the system. Advanced Power Flow Control moves electricity away from overloaded lines to streamline energy delivery. And Topology Optimization uses multi-factor awareness to maximize a system’s carrying capacity.

National Grid’s upstate New York DLR deployment and its study of other GETs show they can begin to cost-effectively optimize today’s aging transmission system for a renewable energy future, said National Grid’s Hill. With engineering and deployment expenditures, DLR may cost $100,000 per mile, while new overhead transmission’s per mile costs in the Northeast are from $3 million to $6 million, he added.

Despite efforts at policy reforms, permitting remains the transmission project “Valley of Death” for Los Angeles Department of Water and Power, said its Power Engineer Manager Denis Obiang.

Where building new lines is impeded, LADWP is exploring “reconductoring,” which is replacing traditional line materials with advanced conductor materials, but is not one of the commonly identified GETs, Obiang said. “At a slight increase in cost over traditional steel, the new materials can increase performance 10%,” which is the highest capacity increase of any non-transmission alternative, he added.

But unlike reconductoring, GETs are the quickly deployable “low hanging fruit” for improving existing lines, Obiang added. “For a struggling load dispatcher, bringing marginally more power onto the system in a high demand hour can make a real difference,” he said.

Power provider EDF Renewables North America has helped finance new transmission capacity, its Vice President of Transmission Analytics, Rodica Donaldson said. But EDF has found GETs can be brought online in 16 months to 24 months with a cost in the tens of millions of dollars to defer transmission builds that could take years and billions of dollars, she added.

The data on congestion reduction with GETs are changing the historically conservative mindset of transmission owners, Donaldson said.

“Batteries help resolve the time dimension of congestion by shifting when energy is used, but GETs help resolve congestion’s distance dimension by optimizing the system-wide use of existing wires,” said Hudson Gilmer, CEO of DLR provider LineVision.

GETs can reduce the amount and cost of needed U.S. transmission, reduce some highly congested locations by 40% or more, and relieve the financial risks of transmission expansion, the Department of Energy’s draft “Transmission Needs” study reported in February. And they can potentially double system renewables capacity with a six month payback, an April Brattle Group study found.

It “intuitively makes sense to turn to easier-to-deploy, least cost technologies, but they require utility resources and studies,” SPP’s Cathey cautioned. And “not all transmission owners have an appetite for what they perceive as new technology risks,” he added.

“The industry has a reputation of being slow to adopt new technology,” Gilmer responded. “But many electric utilities are starting to see GETs near-term viability as new transportation and building electrification loads increase the need to protect their systems,” he added.

Duquesne Light’s Pittsburgh region DLR deployment is expected to increase transmission system capacity by an average of 25%, the utility reported in September 2022. It is now studying power flow control and sees topology optimization as “the end goal,” Duquesne Light Director, Advanced Grid Systems and Grid Modernization Elizabeth Cook said.

But deploying new technologies “is a business decision” guided “by regulatory mandates and by the utility business model,” Cook acknowledged. Use of GETs and advanced conductors may be limited by perceived risk as opposed to guaranteed returns through rates with traditional capital expenditures, she added.

Overbuilding strategically located utility-scale generation and batteries might be a more appealing near-term solution for regulated transmission owning utilities, some analysts said. 

Economic overbuilding

Building more solar, wind and batteries adjacent to existing transmission and load “is not a silver bullet for the queue problem but a way around it,” suggested Meredith Fowlie, professor of economics and faculty director for the Energy Institute at Haas, University of California, Berkeley.

“If transmission bottlenecks remain formidable, and if the costs of renewables and storage keep falling, overbuilding might be more economic than dealing with queue and permitting obstacles,” Fowlie said. “Instead of building where solar or wind are most productive, building where they can interconnect without additional costs or local objections might be adequate to reduce the need for new transmission,” she added.

Developers are already taking advantage of slightly less ideal renewable resource locations near load and existing transmission, “not because of policy but because of economics,” said SPP’s Cathey. They have realized they can optimize for conditions, costs and the opportunity to address congestion in SPP’s East rather than adding renewables to its backlogged Western queues, he added.

A fourth, and undervalued, non-transmission option is customer-owned distributed energy resources, which can cost-effectively meet demand at the local level, advocates said.  

Engaging customers

Engaging customers’ resources is becoming more urgent as loads from transportation and building electrification accelerate, DER advocates said.

Distribution system load flexibility can be a solution to transmission constraints that limit supply by flattening customers’ peak demand during the 5% to 10% of system hours that cause reliability threats, said Astrid Atkinson, CEO and co-founder of software provider Camus Energy. FERC Order 2222 recognizes enabling DER in wholesale markets can be a powerful tool in deferring the need for new transmission, she added.

But regulators must recognize and compensate customers for their resources’ value as energy, capacity, ancillary services and resource adequacy, Atkinson added.

Because of regulators’ resistance to doing that, “it is not possible right now to know how big a role DER can play” in reducing the need for new transmission, the LDES Council’s Souder added.

“DER plays a role, but it does not significantly change transmission needs because the localized transportation and building electrification load growth will be larger than the local DER can meet,” said LADWP’s Obiang. “It will take a comprehensive approach that includes all available options,” he added.

Rethinking transmission

There is no ideal non-transmission alternative to address the challenges facing new transmission development, analysts agreed.

But consideration of the roles of storage-as-transmission, GETs, overbuilding and DER “might force a redesign of the [planning and interconnection] process from the ground up to include modeling that recognizes constraints on building new transmission,” Haas economist Fowlie said.

Many utilities see GETs and other alternatives as a threat to reliability, “like rebuilding the airplane engine while flying it,” said Duquesne Light’s Cook. But non-transmission alternatives “allow rethinking transmission planning with coordination of all options that can defer the need for the many years it will take to bring new transmission online,” she added.

Regional studies of the right subset of technologies could lead policymakers to “a national optimization” of the transmission and distribution systems and the role of all the potential strategies to strengthen them, Dynamic Grid’s Aikin agreed. It should begin with increased use of DER flexibility “to take the burden off transmission,” and then use strategic overbuilding of renewables and storage, and deployment of GETs and reconductoring “until new transmission can be built,” she said.

No non-transmission solution can eliminate the need to expand and renew today’s 100-year old transmission system, added EDF’s Donaldson. “But policymakers and stakeholders need to act proactively to support deployment of alternatives to encourage companies like EDF to keep investing in clean energy development to meet U.S. climate goals,” she warned.

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.

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.