The Energy Transition to Renewables

In 2023, both the U.S. solar and offshore wind industries grew rapidly in spite of ongoing challenges posed by the global supply chain, the regulatory landscape, and interest rate hikes. Several offshore wind farms are nearing completion and two have already begun delivering power to the grid, while a record 33 GW of solar capacity was added to the U.S. grid last year.

Experts in both industries say they expect positive trends for these two renewable resources to continue this year, even as those challenges continue. The Inflation Reduction Act and the massive clean energy investments it’s generating play a significant role in that confidence, they say.

“For all of us in the [solar] industry, it’s a significant milestone legislation in that we're talking about a decade of certainty, which is a much different dynamic than having just a few years certainty,” said Eric Pollock, chief commercial officer at DSD Renewables.

Marlene Motyka, a principal at Deloitte and the firm’s U.S. renewable energy leader, said she sees the obstacles renewables face as “really just growing pains as the industry is scaling, rather than intractable issues that are going to stop the industry’s momentum.”

Both industries will face more challenges this year. In June, President Joe Biden’s two-year moratorium on any new tariffs on solar panels will expire. When the moratorium ends, an Aug. 18 U.S. Department of Commerce finding that four Southeast Asian countries circumvented tariffs on Chinese-made components will result in new duties on solar imports from those countries.

Solar imports also continue to be constrained by the Uyghur Forced Labor Prevention Act. In response to these pressures, the solar industry has been investing significantly in onshoring manufacturing, with several major factories announced last year. 

Though module prices declined by almost 50% globally in 2023, and manufacturing capacity tripled from 2021 levels, replacing imports with domestically produced panels will increase the overall cost of deployment in the U.S., the International Energy Agency said in a January report.

The offshore wind industry will see several developers attempting to rebid contracts they exited in 2023 during upcoming state solicitations, while the domestic workforce and supply chain needed to support offshore wind farms and their ports are being rapidly built out. As of this month, two utility-scale offshore farms are delivering power to the grid — a milestone in the U.S.

The arrival of utility-scale offshore wind power and the record explosion of solar capacity also mean that building new transmission and reducing the interconnection queue are more important than ever for the clean energy industry.

Proponents of clean energy hope to see the Federal Energy Regulatory Commission finalize its proposed transmission planning and cost allocation rule next year. Acting Chairman Willie Phillips said in November that the rule is a “chief” priority for him.

Offshore wind from scratch: ports, workforce and vessels

It may be a blessing in disguise for the offshore wind industry that so many developers had to delay or cancel projects last year, said Felisa Sanchez, of counsel with law firm K&L Gates’ maritime and finance groups.

“These cancelations are now allowing some breathing room that’s going to free up port availability, vessel availability,” she said. “There was a real crunch on and fight for those limited assets.”

Sanchez said she expects 2024 will “see the benefits of some of these rough waters” the industry has encountered in the past few months and “allow the supply chain to catch up a little bit.”

Bureau of Ocean Energy Management Director Liz Klein said that industry’s specialized vessel needs coupled with global post-COVID economic and supply chain difficulties have posed a number of challenges – but she remains “very, very optimistic” about this coming year.

“While any individual project might have a timeline that shifts, it's not an indication of failure, it's not an indication that this type of clean energy is not possible in the U.S.,” she told Utility Dive. “It just indicates that these are large, complicated endeavors.”

BOEM has four lease sales scheduled for 2024, and continues to work with other agencies to advance research and development into the floating offshore wind technology that will be needed to install turbines in the deep water off the West Coast.

“As projects are built here in the U.S., there will continue to be lessons learned by industry about the best way to move forward with construction,” Klein said. This includes innovation in equipment and vessels for both floating and fixed-bottom offshore wind farms.

The offshore wind industry’s development of necessary vessels has been hampered by the Jones Act, a 1920 law barring foreign vessels transporting goods by water. As a result, the U.S. industry has to implement workarounds to construct projects while building its own fleet of wind turbine installation vessels. 

Dominion Energy is working on building the first such vessel, named Charybdis and expected to be completed late this year or early in 2025 for use on Dominion’s 2.6-GW Coastal Virginia Offshore Wind project.

In addition, the buildout of an offshore wind labor workforce remains a “work in progress,” Sanchez said. She’s seeing developers, contractors, vessel owners and port operators increasingly recruit from high schools and colleges, and work with maritime colleges to develop industry-specific training programs. 

Though BOEM’s first-ever lease sale in the Gulf of Mexico received a tepid response last year, only receiving bids on one of three areas put up for auction, Klein said the agency sees the region as “tremendously important” to offshore wind thanks to the “existing talent, infrastructure and equipment” created by the oil and gas industry.

Klein said that going forward, BOEM will have a significant focus on “supporting project proposals and making sure that we are being as efficient and effective as possible in our permitting reviews.”

“I think one of the ways to demonstrate the success of this type of technology, this type of clean energy, is to get projects built and delivering electrons to the grid,” she said. “There are a number of exciting milestones that we've hit, and I expect a lot more of the same in 2024. I am as aggressively optimistic as I have ever been about the prospect of offshore wind in the U.S.”

A push for onshoring will bring solar manufacturing stateside

After billions of dollars of planned investment in domestic solar manufacturing were announced last year, 2024 is set to see those investments pay off. 

Domestic panel manufacturer First Solar, South Korea-based energy company Q Cells, India-based panel maker Waaree Energies, and the North American subsidiary of Italian company Enel all plan to bring new U.S. factories online this year.

While concerns linger about the fate of the solar supply chain once the tariff moratorium expires in June, Newton said that having Commerce’s final decision on the matter has been “extremely helpful” for DSD Renewables in terms of providing certainty on the issue. 

“Tariffs, Customs and Border Protection issues, understanding the Uyghur Forced Labor Act – it’s still a relatively new thing for all of us,” he said. “We're all working our way through the supply chain mapping, and that's just another step that we all have to take in our due diligence. That said, as long as you do your due diligence, you shouldn't have problems with it.”

Newton said he thinks the impacts of the Inflation Reduction Act are still “shaking out,” but the biggest impact he’s seen so far is an increase in optimism worldwide.

“When you see that level of investment being made by fairly large global companies, it leads you to the understanding that this is seen as a viable long-term industry,” he said. “The momentum is there. And to be honest, it seems very unstoppable.”

However, Newton added that he sees uncertainty in the regulatory environment as the biggest hurdle the solar market faces.

“That tends to be more disruptive to us than anything else right now,” he said. “As far as equipment and material pricing, things are staying pretty steady. Module [prices] have declined quite a bit, actually, over the last six months.”

Motyka said she anticipates the impact of the investments generated by the IRA will come into view this year.

“A lot of producers are going to reshore, and new ones are going to come into the U.S. just to capitalize on those IRA tax credits and to help meet the demand from renewable developers who are chasing domestic content adders,” she said. 

Deloitte’s view is that these investments, coupled with the demand generated by state, federal and corporate decarbonization goals, are forces that will “enable renewables to overcome recent hurdles,” Motyka said.

As solar capacity rapidly increases nationally, some hotspots of conflict have emerged on the state level — particularly when it comes to net-metered distributed solar.

Distributed solar advocates scored a win in Virginia in September when the State Corporation Commission struck down Dominion Energy’s interconnection parameters for certain net-metered projects, which the Virginia Distributed Solar Alliance argued posed “unreasonable” barriers to small solar projects.

But a three-judge panel for California’s First Appellate District Court in December dismissed a challenge brought against the California Public Utilities Commission’s latest update to the state’s net energy metering rule, which shrunk the compensation that customers with rooftop solar receive for exporting power back to the grid from their panels, and has been linked to job losses for small solar companies statewide.

“The general outlook is grim,” said Carlos Beccar, marketing director of Fresno-based solar company Energy Concepts Enterprises, about the state’s rooftop solar industry. “[2024] is going to be even worse. The job loss is going to probably double.”

Connecting to the grid

Transmission buildout and permitting reform remain critical priorities for the renewable energy industry as a whole. In addition, without faster and better grid interconnections, many of the decarbonization benefits of clean energy could be lost, analysts say.

In November, Princeton University’s ZERO Lab leader Jesse Jenkins said the previous decade’s annual average of 1% transmission capacity growth will have to rise to 2.3% in order to avoid cutting the IRA’s potential emissions reductions in half.

“When we think about the boosts coming from the IRA and [Infrastructure Investment and Jobs Act] to renewables, that can only exacerbate the pressure on the transmission bottleneck,” said Motyka. “That is a challenge that I don’t think is going to be lessened dramatically anytime soon, but there are a lot of parties working on that, from the RTO and ISO perspective as well as from the FERC side.”

In California in particular, wind and solar generation curtailments reached record highs last year. As of September, the Energy Information Administration found that the California Independent System Operator had curtailed more than 2.3 million MWh of wind and solar output in 2023. 

Trade groups, clean energy groups and laboratories spent the last year sounding the alarm about the need for transmission buildout. Evergreen Action’s Power Sector Senior Policy lead Charles Harper said in December that he sees 2024 as a potentially significant year for transmission reform after FERC Commissioner James Danly’s term expired on Jan. 3.

Danly opposed FERC’s proposed transmission planning and cost allocation rule, and Harper said the group is now “really optimistic” about the potential for that and other transmission rules to pass this year.

“I don’t think the pressure [for transmission reform] is going to go away,” Motyka said. “I think it’s only going to increase, and there’s this resounding push and discussion around the fact that there is this generation that needs to be deployed as we continue to retire fossil generation.”

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

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

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

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

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

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

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

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

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

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

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

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By Wood Mackenzie

In August 2022, President Biden signed the Inflation Reduction Act (IRA), a watershed moment in the history of US climate legislation. The bill offered hundreds of billions for clean energy and decarbonization measures through grants, loans, tax credits, and other incentives. Specifically, many aim to rejuvenate US manufacturing and build new supply chains across North America.

After the initial fanfare, the focus quickly shifted to how all the legislation’s specific details would be implemented. In support, the US Treasury released guidance on domestic content requirements, tax credits, and identifying regions where wind, solar, and storage assets qualify for additional incentives.

But is the IRA delivering on its potential? Download the report summarizing the impacts of the IRA to date across power and renewables markets; from solar, Grid Edge and energy storage to US wind markets, electrification and supply chains. Or, read on for some highlights.

The IRA prompts a race for land in the North American power sector

The IRA’s subsidies for solar PV, wind, and energy storage assets have ensured they remain financially competitive with other generation technologies – at least in the right locations. The result has been a national land grab as developers race to secure sites with the most lucrative resources, permitting conditions, and tax bonus eligibility.

This momentum is yielding seismic changes in the PPA markets. Many developers are increasing contract pricing on expectations that the IRA’s tax credits will remain for decades – a point we’ve reinforced for some time – and lead to reduced wholesale power market revenues in the post-contract period. After years of decreasing PPA prices, the tax credits haven’t been able to curb upward trends driven by higher costs, inflation, supply constraints, and the demand for new projects dwarfing supply.

For new assets, interconnection and transmission remain primary obstacles. While the IRA does not meaningfully address these issues, there are reforms at various levels of the FERC and the ISOs and RTOs. We are more confident in reforms to interconnection than transmission, as they are more technical and administrative in nature and avoid thorny political issues posed by transmission reforms.

For solar and storage developers, interconnection remains the biggest hurdle overall. Reducing the mounting national backlog requires a concerted effort to reform processes and enable grid operators to streamline applications. The IRA’s incentives are only exacerbating this situation, as many developers are now exploring opportunities that previously seemed unviable.

The IRA unlocks a bright future for US domestic manufacturing

When the IRA first passed, we projected that the law would be a powerful catalyst for US solar growth. Today, there are still many unanswered questions the industry must resolve before its benefits can be fully realised.

One area where the IRA is succeeding is reigniting interest in domestic manufacturing. There have been roughly three dozen announcements for new US solar manufacturing facilities in the last year.  While not all of these announcements will come online as promised, the IRA has still caused a surge in domestic solar manufacturing.

In terms of solar project development, developers and financiers are still combing through the details of IRS guidance, or waiting for further clarity. We still expect the IRA to be a long-term driver of solar capacity growth – our latest outlooks put average annual growth for the next five years at 15%. But in the near-term, the industry is still grappling with the uncertainty surrounding qualification processes for various IRA provisions. 

The IRA’s domestic content requirements mean the US needs to develop a local battery supply chain – and then quickly ramp up production to meet its exploding demand. Even though US-made battery modules won't be available until at least late 2024 or early 2025, most are fully committed as soon as they become available. 

We expect these evolving market conditions to yield various manufacturer pricing strategies. Many buyers are willing to pay a premium for US-made equipment - as long as manufacturers provide cost transparency and IRS-compliant documentation.

Final thoughts

The IRA has generated encouraging progress and lucrative investment opportunities, although uncertainty remains around many specifics of the legislation. While it’s unclear when (or if) all these questions will be resolved, it seems clear that the IRA will ensure renewables, electrification, and decarbonisation remain critical pillars of the US’s economic future.

The Wood Mackenzie IRA Summary report explores the impacts of the IRA to date across power and renewables markets. Download the complimentary report to gain insight on the opportunities and challenges for solar, wind, energy storage, grid edge, electrification and supply chains.

As the U.S. offshore wind industry expands to meet state and federal goals, colleges in and around New Orleans are establishing wind energy programs geared at both young students and experienced workers from the oil and gas sector who are looking for new opportunities.

The offshore wind industry offers a significant economic opportunity for the region and those who live there, says Lacy McManus, executive director of future energy at economic development agency Greater New Orleans, or GNO. The state has lost “about 20,000 jobs over the last twenty or so years in the oil and gas sector,” she said. “So we have a number of folks who have the right skill sets, the right occupational profiles, who could be redeployed into the wind buildout.”

Program leaders at the University of New Orleans, or UNO, and Nunez Community College say they have partnered with companies like German multinational energy company RWE and Norwegian wind workforce education center Energy Innovation AS to develop a wind energy curriculum that adheres to global training standards and imparts the most in-demand skills.

“I see an opportunity for us to build an industry hub around some of our existing expertise, and universities will really play a key role in making that a reality,” said Shafin Khan, vice president of external affairs and innovation at UNO’s Research and Technology Foundation.

Khan was instrumental in the development of UNO’s Wind Scholars Program, which launched with an inaugural cohort of engineering students last fall. The program provides students with scholarships for courses specific to renewable energy, and paid internships with one of the participating companies — RWE, Entergy, Gulf Wind Technology, Edison Chouest Offshore or Keystone Engineering.

“Edison Chouest, a massive maritime oil and gas servicing player here in South Louisiana – they're very aggressively investing in the wind landscape, and have taken on one of those wind scholars,” said McManus. “The most important thing that our schools can be doing right now is having a hand-in-glove relationship with the different industrial players in their own backyards.”

The state of Louisiana has set a goal to deploy 5 GW of offshore wind by 2035, and an offshore wind lease off the state’s coast was purchased by RWE Offshore US Gulf last August for $5.6 million.

This was the first wind auction that the Bureau of Ocean Energy Management held in the Gulf of Mexico, and it wasn’t met with much enthusiasm – the price per acre was lower than it had been in previous auctions, and two tracts offshore Texas went unsold. But BOEM officials say they remain committed to offshore wind in the Gulf, and finalized four new wind energy areas there in October.

“The Gulf of Mexico is just a tremendously important region for offshore wind generally,” BOEM Director Liz Klein told Utility Dive in a December interview. “There's so much existing talent, infrastructure and equipment. The traditional offshore oil and gas industry is right now, as we speak, supporting the offshore wind industry. There's a lot of cross-pollination in the use of vessels and workforce and infrastructure.”

Companies in the region are already “exporting [their] know-how” when it comes to offshore operations, Khan said. Both he and McManus pointed to a May 2023 estimate from the Oceantic Network that Gulf Coast contractors have captured 26% of the U.S. offshore wind supply chain. 

“The innovative turbines that we designed down here in the Gulf to address hurricanes and the unique conditions we have here – I see an opportunity to take those internationally to other markets, and help them install offshore wind in similar conditions,” Khan said.

At first, conversations about creating these programs were characterized by hesitancy about the novelty of offshore wind, McManus said. But GNO is now trying to “dispel the idea that we need to reinvent the wheel.”

“We're not creating space ranger academies,” she said. “So much of what's going to be needed is what we've always needed, and what we've had.”

Meeting a need

Demand for skilled workers is high in the U.S. wind energy industry. The Biden administration established a federal goal of deploying 30 GW of offshore wind by 2030, but employers are having difficulty finding experienced applicants, according to the National Renewable Energy Laboratory. To meet the 2030 goal, NREL found that full-time annual employment levels will need to reach “15,000 and 58,000 based on 25% and 100% domestic content scenarios, respectively.”

Jacqueline Richard, coastal studies and GIS technology program manager at Nunez Community College, said the school has developed a “three-tiered pathway toward wind,” but prioritized the career and technical certificate.

“That piece was the most important one to get started right away, because we recognize there are a lot of people in the offshore energy production realm that already have this training,” Richard said. “We wanted to offer an easy pathway for them to come in and get credit for prior learning, so they don't have to repeat material.”

Classes for the workforce development certification will start being offered this summer or fall, Richard said, while a program offering a technical diploma in wind energy will begin in the fall. 

“We partnered with Energy Innovation AS out of Norway, and we're deploying their approved curriculum inside of our four-credit program,” Richard said. “And I received a grant from the [National Academies’] Gulf Research Program to support the first cohort of students through the program, so their tuition will be fully paid.”

A Global Wind Organization-certified associate's degree in wind energy technology will also launch at Nunez in the fall, and Richard said the school is working on building a “two-plus-two” relationship with UNO for students who want to transfer and earn a related bachelor’s degree.

“Prospective students that I've talked to, for the most part, are generally very excited — especially by the earning potential,” she said.

Students who complete the one-year program can expect to earn a base salary of around $60,000, Richard said, while Louisiana’s median household income in 2022 was around $58,000.

“I think the thing that excites me the most is this opportunity Louisiana currently has to shift our narrative,” she said. “We've been an energy leader since the early 1900s, we developed offshore energy production. And now we have this ability, and this knowledge, and all these skills to do the exact same thing but in the sustainable realm.”

However, Richard said, Louisiana’s long history with the oil and gas industry makes some prospective students a “tough sell” when it comes to educational opportunities in renewable energy.

“There's a lot of people who, understandably, are going to stay loyal to oil and gas because that's what their family has done for generations,” she said. “But when we meet with people who have a few reservations, but see the potential in how easy it would be to move over – usually the conversation heads off in a better direction.”

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

The emerging system

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

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

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

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

Smoothing variability

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

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

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

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

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

Managing demand spikes

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Stabilizing the system

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

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

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

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

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

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

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

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

For the first time, the Bureau of Ocean Energy Management will conduct a Programmatic Environmental Impact Statement, or PEIS, on offshore wind development across multiple lease areas at once, the agency announced Jan. 8.

The six lease areas, located in the New York Bight, total over 488,000 acres and contain up to 7 GW of potential offshore wind capacity. BOEM has already completed a draft PEIS for the areas, examining the impact of a variety of development scenarios in the region on air quality, water quality and emissions. 

BOEM chose to evaluate the areas as a group because of their close proximity to each other, “and the timing of when BOEM expects to receive future project plans for review,” according to a Jan. 8 release.

“We look forward to receiving additional public comment to inform this first ever regional environmental review of offshore wind energy development on multiple leases,” BOEM Director Elizabeth Klein said. “We are confident that this comprehensive approach can create efficiencies for future project-specific wind energy reviews in a manner that protects the ocean environment and marine life.”

BOEM said the new regional approach is an “evolution” of the agency’s process. This new strategy comes as the U.S. offshore wind industry is experiencing economic turbulence that has led to a few project delays and cancelations, putting state and federal procurement goals at risk.

“We are hopeful that by undertaking this comprehensive environmental review of issues common across all six lease areas, BOEM can significantly accelerate the federal permitting process while more effectively identifying and addressing any potential impacts,” said New York Offshore Wind Alliance Director Fred Zalcman in an email.

Zalcman said that the release of the draft PEIS for these areas is an important milestone as the U.S. attempts to meet the Biden administration’s goal of deploying 30 GW of offshore wind energy by 2030. 

“Additional environmental analyses specific to each proposed wind energy project will build off this programmatic review once BOEM receives individual proposed project plans from the leaseholders,” BOEM said.

The draft PEIS will be published in the Federal Register on Jan. 12, followed by a 45-day public comment period.

Renewable energy companies profit margins shrank across the board in 2023, but the reasons for the decline varied from one sector of the industry to the next, according to a report by AlphaSense.

While rooftop solar is struggling with new customer acquisition, offshore wind has taken a hit due to a crowded marketplace and a lack of differentiation. Hydrogen, meanwhile, has its own problems with cost effectiveness, according to the report.

The coming year could bring a reckoning for renewable energy companies that aren't able to adapt to a more competitive market, said Xavier Smith, director of energy and industrials research at AlphaSense.

If you're thinking that renewable energy will revert back to a status quo of rapid growth and easy money in 2024, you might be disappointed, Smith said.

Beside the inflationary pressures and supply chain constraints that dominated headlines in 2023, each major sector of the renewable energy industry is facing its own set of difficulties that seem unlikely to resolve in 2024, Smith said.

In the solar industry, the profitability of rooftop solar installations has declined as the cost of customer acquisition has increased. Most early adopters have already installed solar, Smith said, and bringing more hesitant homeowners into the fold is a long and often expensive process.

“Firms like Sunrun have partnerships with stores like Costco and Home Depot, and running these stands at these retail outlets is pretty costly,” Smith said. “And they are not getting the customer return that they anticipated.”

Tesla, Smith notes, has attempted to solve the problem by moving its sales operations to an online platform. But consumers seem to prefer human interaction in solar sales — Tesla has lost market share in the past year to other major installers.

Meanwhile, it's no secret that offshore wind struggled to maintain profitability in 2023. But while offshore wind developers have cited rising costs and inflation as the reasons for project cancelations this year, Smith said there are other issues that haven't received as much attention.

The offshore wind industry, he said, is overcrowded, with too many companies offering essentially identical products. This forced developers to try to compete on cost by bidding razor-thin margins that left no room for error when economic conditions changed.

Hydrogen has also experienced cost-related difficulties in the past year, Smith said. This emerging sector has struggled to establish itself as a cost-competitive energy resource, and will likely continue to do so until the cost of transporting hydrogen is reduced. Widespread adoption of hydrogen is unlikely until dedicated pipelines are built, Smith said.

None of this is meant to suggest that renewables can't or won't continue to grow, Smith said, but he believes many renewables companies are still waiting for markets to return to a pre-pandemic paradigm where financiers choose investments based almost solely on a company's potential for growth.

“Firms will have to generate their own cash flow” in 2024, Smith said. “I think things will change, but I don't think we will go back to that plentiful capital environment any time soon. The firms that don't adjust ... they're going to struggle.”

As solar energy booms in the U.S. with record investments and installations, a wave of technological advancements is set to transform the amount of energy solar can produce, where it can be deployed, and how long it can last.

“It seems like when there’s a good idea, it can very rapidly get rolled out through the whole industry,” said Chris Deline, a research engineer who leads the National Renewable Energy Laboratory’s photovoltaic field performance group.

Over the last five years, Deline said, the industry “entirely switched over” from aluminum back surface field solar, or Al-BSF, cells to passivated emitter rear contact, or PERC, cells. “And it seems like there are new emerging entrants within n-type silicon that are poised to do the same thing,” taking over from PERC, he said.

For example, the solar industry is now beginning to make a switch from p-type PERC to n-type tunnel oxide passivated contact, or TOPCon, cells. N-type cells have their wafers doped negatively using chemicals like phosphorus, while p-type cells are doped positively. Doping is the process of adding an impurity to the semiconductor to increase its ability to conduct electricity.

In the early days of solar technology, installations were limited to space applications like satellites, and p-type cells proved more resistant to radiation and degradation in space than n-type cells. This allowed p-type technology to stake out a larger market share early on, and this domination continued after terrestrial solar installations began — though n-type cells are more efficient and resilient for utility and other applications outside of space.

Now, n-type cells are gaining ground.

“That's going to be a big transition,” Deline said. “It’s like Moore's Law of faster and faster computer processors that allows them to keep going to higher and higher efficiencies.”

PERC continued to dominate the solar panel market in 2022, but experts predict the technology will go the way of its predecessor, Al-BSF. The German industrial association VDMA said in an April report that it projects TOPCon’s market share will increase from around 10% in 2022 to as much as 60% globally within the next decade, and become the dominating cell type after 2025.

“It is a generally accepted view that TOPCon will ramp up relatively quickly in market share and likely dominate crystalline silicon solar technology in the not-so-distant future,” said First Solar's Chief Technology Officer Markus Gloeckler.

Across all panel types, the average dollars-per-kilowatt cost of solar construction has fallen by a few thousand dollars since 2013, and fell 6% to $1,561 per kW in 2021, the Energy Information Administration said in an October analysis.

What makes up a solar cell?

While Gloeckler sees a bright future for TOPCon, he says First Solar is “confident” in its commitment to thin film technology in the form of cadmium telluride, or CdTe, which is the most popular panel technology for utility-scale deployments — while crystalline silicon panels like TOPCon continue to dominate overall. 

The company is set to deploy production of its proprietary copper reduction technology CuRe in the second half of 2024, which Gloeckler said the company expects “will be able to compete very well with TOPCon” due to its “anticipated lower degradation rate” when exposed to high temperatures and humidity.

Gloeckler said the company is also optimistic about its ability to harness the potential of perovskite solar cells, which are “fundamentally thin film semiconductors.”

Perovskite cells have made recent leaps in efficiency, but remain tricky to deploy at commercial scale due to the chemistry presenting stability issues.

In comparison to silicon, perovskite is “relatively inexpensive,” Deline said. “Fundamentally, though, the fact that it's so easy to make may be part of why it's so hard to get it to be stable.”

First Solar and its competitor Hanwha Qcells both made investments this year in perovskite-based tandem cell technology. First Solar acquired Evolar, a Swedish start-up focused on tandem cells, and Qcells announced a $100 million investment in a tandem-cell production line.

Tandem-junction cells offer “a path toward higher module efficiencies over single-junction designs,” according to NREL. Multiple junctions — or boundaries between layers of semiconducting materials — allow solar cells to break through the Shockley–Queisser limit, a theoretical limit which prevents single-junction cells from absorbing more than 30% of the solar energy that shines on them.

But researchers are still pursuing higher efficiencies with single-junction cells.

NREL announced a single-junction efficiency breakthrough on Oct. 25, reaching an efficiency of 27% with a gallium arsenide cell. In a release, the lab said researchers optimized the doping and structure of the top layer of the cell to minimize the negative impacts of defects.

Bifaciality, or the ability of a solar cell to produce energy when illuminated from either side, is another cutting-edge innovation. One significant trend Deline sees across the solar industry is “bigger and bigger modules,” which make it easier to reap the efficiency gains of bifaciality.

“You can buy a 630, 650 watt module now, and that's just because [the module] is massive,” he said. “In a lot of cases, these include two layers of glass on the front and the back,” increasing bifacial gain on the back side of the panel where there is “clear glass instead of a white polymer sheet.”

Garrett Nilsen, deputy director of the U.S. Department of Energy Solar Energy Technologies Office, said other areas for innovation in solar panel manufacturing and deployment include different ingot and wafer types, wafering techniques and cell structures, or module architectures, along with cheaper, simpler and more resilient racking systems.

“This is a great time to be involved with solar technology,” Deline said. “There's a lot of innovation going on, and there's a lot of new investments.”

Where can solar panels deploy?

As the technology behind solar cells undergoes rapid innovation, researchers are also working to expand how and where installations are deployed.

DOE projects that the U.S. will need to install 1 TW of solar capacity by 2035 to meet its decarbonization goals, which will require “more diversity of siting configurations,” the department says. 

Floating solar is relatively common in Southeast Asia and Europe, but so far has only been deployed at a small scale in the U.S., said Juan Gallego-Calderon, a clean energy engineer at Idaho National Laboratory, or INL. These deployments have been limited in size to around 10 MW, and sited in manmade water bodies that aren’t federally regulated.

Gallego-Calderon is working on an INL project to accelerate the deployment of floating PV in reservoirs that are controlled by federal entities like the U.S. Army Corps of Engineers, the Bureau of Reclamation and the Federal Energy Regulatory Commission.

“The reason why there hasn't been any deployment in those is just because the regulations are not in place,” he said. “So we are investigating the regulatory and environmental pathways, and we’re producing a techno-economic assessment tool that also includes environmental modeling.”

The largest floating solar installation in the U.S. is an 8.9-MW array in the Canoe Brook reservoir in Short Hills, New Jersey, which is owned and operated by the utility New Jersey Resources. 

Floating solar in federal reservoirs can help avoid conflicts over land use — such as opposition to solar installations as “eyesores” — and siting it in a hydroelectric reservoir to create a hybrid system can reduce solar curtailment, NREL found in a 2022 report. 

“We're looking at a proposed pumped storage hydro facility where they’re actually working with a company to design a floating PV system to put in the upper reservoir to operate in conjunction with the pumped storage hydro,” Gallego-Calderon said. “And they're working on the license right now to submit to FERC, so things are happening.”

Is sustainable recycling possible?

The INL and First Solar are also collaborating to develop a more sustainable recycling process for CdTe panels, participating in a project led by the University of Kansas. 

“About half of the utility-scale solar projects are using these tellurium-based thin film solar panels,” said Daniel Ginosar, group leader of the chemical systems group at INL. “The lifespan of those [is] typically twenty years until they start losing efficiency.”

There are also supply chain considerations. As the U.S. aims to deploy massive amounts of renewable energy, the Biden administration has announced a goal of reducing reliance on China for critical minerals, including tellurium. 

“We wanted to understand how we can recover the tellurium to reuse it in new solar panels, and at the same time reduce the amount of waste that's going to be generated by the systems coming out of use at end of life,” Ginosar said. Currently, recycling CdTe panels is “not a complete process.”

The existing technique involves trying to break the polymer bonds in panels by crushing them into powder and attempting to leach the cadmium and tellurium from that powder. 

The researchers came up with an alternate process of using an ultrasonic mixer to enable fluids like liquid butane to melt the polymer bond, which makes it easier to retrieve the cadmium and tellurium.

Ginosar estimates a “tremendous” buildout of solar capacity over the next 10 to 20 years, though between now and then, solar panels won’t be coming out of service quickly enough to supply materials for the new panels being made.

“But by 2050, those [new] panels will be reaching their end of life, and that's when we can really make a big difference with recycling,” he said. 

This particular project is only focused on CdTe panels, Ginosar said, but the researchers are looking to expand the method to “all different types” of solar panels, both thin film and silicon-based.

“We’re just barely getting started, the funding has only just shown up,” he said. “In the short term, it's hard to recycle your way out of the problem. But in the long term, we can be relatively sustainable and be able to recover the tellurium effectively, and completely eliminate the need for mining it from China.”

The number of early-stage renewable energy projects entering queues around the country exceeds the availability of labor and capital needed to build them, Brent Nelson, managing director of markets and strategy at market intelligence firm Ascend Analytics, said during a webinar.

Despite the large number of new renewable energy projects, prices for power purchase agreements, or PPAs, continue to rise, said Anthony Boukarim, senior manager of resource planning and valuation for Ascend Analytics.

Renewable energy projects that lack interconnection and permit approvals are seen as high-risk, low value investments and financiers are turning down the majority of these projects, Nelson said.

In theory, the recent surge in renewable energy projects should help drive costs lower for would-be buyers of renewable energy. But the reality is not so simple — at least for the time being, according to Ascend Analytics.

The majority of the the renewable energy projects currently in development pipelines around the country will never be built, Nelson said. There are simply too many projects chasing limited materials, capital and labor — not to mention that the majority of these projects have yet to receive interconnection and permit approvals.

Whether a developer has such approvals in hand has become a key distinction in the renewable energy market, Nelson said. Projects without a clear path to interconnection in particular are seen as high-risk, low value assets; the potential value of that same project increases by some 60% once developers have their notice to proceed in hand.

This has created a split in the renewable energy market. On the one hand, Nelson said, he has heard from financiers that they are turning down the majority of the project proposals that come through their doors. On the other, the average price paid for PPAs continues to rise as corporate and other buyers of renewable energy vie for the handful of projects that do successfully navigate the interconnection and permitting process.

But Ascend Analytics does not expect the current trend to last, Boukarim said. In the short-term, he said, PPA prices should begin to normalize and then gradually decline as ongoing advances in technology and management bring down the pandemic-era price spikes driven by inflation and supply chain shocks. By the late 2030s, he said, prices are projected to rise again as the Inflation Reduction Act tax credits begin to expire.

Boukarim also noted that a growing number of energy buyers are changing the way they evaluate PPAs in search of contracts that meet specific needs within their company's emissions portfolio. And the PPA that most closely matches those needs is not always the cheapest, he said.

“Corporates really want to find what is the best project for them in terms of carbon abatement cost,” Boukarim said.

A new market for Inflation Reduction Act clean energy tax credits will bring significant new capital to wind, solar, battery, clean hydrogen and carbon capture projects, financial analysts say. 

The IRA transferability provision allowing the buying and selling of federal production and investment tax credits could more than triple the $20 billion annual tax equity market that today finances clean energy in the U.S., the analysts say. Clean energy developers can earn revenues by selling tax credits, buyers can reduce their tax burdens while financing new projects, and utilities could increase ownership of low cost clean energy to reduce customer rates.

Currently, a limited number of very large investors are obtaining tax credits through complex partnership agreements with project developers. The new IRA provision allows much more streamlined sales of tax credits by clean energy developers and a much larger pool of buyers is expected to bring capital to the sector.

Selling tax credits “helps offset costs of the clean energy transition for our customers” and the impact could be “profound,” Duke Energy Vice President for Tax Cooper Monroe said. Duke intends to use transferability and “is considering an auction-style process,” Monroe added. Auctions are typically used to make financial transactions more efficient and transparent.

The Treasury Department’s June 14 guidance on tax credit transfers, or sales, was “comprehensive” and offered “a very clear description of the transaction process,” analysts and attorneys say.

“Tax credit sales are ramping up more quickly than expected,” affirming forecasts of potential $60 billion annual sales in the near term, said Keith Martin, partner and co-head of projects, U.S., for Norton Rose Fulbright, which just facilitated a tax credit sale involving Bank of America Securities. And the new transactions “are likely to increase in 2023 as more investors face year-end tax liabilities,” he noted in June.

The new financing tool may create competition for tax credits from tax burdened investors, financial analysts agree. But the new transactions must still prove to be cost effective and secure for new investors, resolve complications unique to utilities, and the new opportunities for taxpayers must avoid the political backlash of previous tax reallocations, some analysts caution. 

Following the money

The promise of tax credit transferability is enormous, analysts and attorneys agree.  

“Over $50 billion in just wind and solar tax credits could be transferred in 2024,” Andy Moon, co-founder and CEO of transfer broker Reunion Infrastructure recently told financial analysts Pivotal180. “With new IRA support for hydrogen, carbon capture, and other clean energy technologies, there could be $80 billion per year in tax credits looking to be monetized,” he said.

Tax equity partnerships with large investors like Bank of America or J.P. Morgan have been “a great tool,” allowing renewable energy developers to “assign tax credit rights in return for upfront cash equity investments,” added Reunion co-founder and President Billy Lee.

But the legally complex, costly partnership agreements require significant legal and other due diligence work which can cost “up to 15% of the value of the original tax credit,” according to a Center for American Progress summary of transferability.

The “unintended consequence” has been financing going to “the biggest and lowest risk projects,” and has limited tax credit monetization to “around $20 billion per year,” Lee said.

Less costly and complex tax credit transfers are likely to attract more and different types of investors, Lee and Moon said of strategies they are developing to simplify and standardize the new transactions. They will also finance smaller projects and more innovative technologies overlooked by risk averse tax equity investors, they agreed.

Tax credits are currently selling for $0.85 per dollar to $0.95 per dollar, with prices nearer $0.95 for 2023 credits “because sellers know those buyers are eager,” said Becca Glazer, senior director of growth initiatives, for renewables investor AES Clean Energy. Prices for 2024 are “about $0.90,” and even lower for credits in 2025 and later, she added.

“The highest prices of $0.95 are going to utility-scale solar and wind tax credits,” where developers choose transferability instead tax equity, said Norton Rose’s Martin. Unproven technologies’ tax credits are selling at lower prices, he added.

Both availability of tax credits from developers and demand for them from corporate interests are growing, said Generate Capital Principal of Structured Finance, Jessie Robbins. But it is too early to say how it will impact tax credit pricing, or how institutional tax equity investors will react, she added.

The traditional tax equity market “does not yet feel threatened,” and it will take time for transfer transactions to develop streamlined “standardized structures,” Glazer agreed. But “by next year, in a more defined transferability market, tax equity investors are likely to feel more competition,” she said.

“Transferability will not be perfect, but it will be better” than tax equity partnership transactions. “It won’t be simple, but it will be simpler. It won’t be cheap, but it will be cheaper. It won’t be fast, but it will be faster,” responded Segue Sustainable Infrastructure Managing Partner Dave Riester, in comparing tax credit sales to tax equity agreements. “There will be due diligence to perform, but a lot less.” These factors will improve the economics of renewables deployment, he said.

Other analysts are less certain. Transfers may be “transformative” because they remove negotiating complexities, acknowledged Generate’s Robbins. But “it still takes a lot of work to get a single tax credit investor over the line, whether it is a $100,000 project or a $100 million project,” she added.

However, transferability will be especially valuable for some technologies and investment opportunities, analysts said. 

Transferability players and deals

Some renewable energy technologies like utility-scale wind and solar are expected to benefit more and sooner from the new transactions because they are more familiar to the investment community, Segue’s Riester, Reunion’s Lee, AES’s Glazer and others said.

A recent tax credit sale returned $459,000 from an undisclosed buyer for two commercial rooftop solar and storage projects with a combined 537 kWdc capacity and a total cost of $1.5 million, reported Matthew Coleman, CEO of renewables builder Davis Hill Development. The numbers were verified by the James Richards, CEO for transaction intermediary Evergrow.

“A tax equity transaction of that size would be too difficult” because of the extensive legal and other verification by project experts for the complex tax equity partnership agreement that allows investors use of the tax credits, Coleman and Richards agreed. But the reduced due diligence required in the IRA for transferability’s tax credit sale “makes financing feasible,” they added.

Another transferability use case will be for less proven technologies like carbon capture and clean hydrogen with “too much risk for traditional tax equity investors,” said Generate’s Robbins. But those projects’ capital expenditures “are large enough to justify transferability negotiations and due diligence, even though they are higher risk investments,” she added.

Transferability may also change the financing of merchant utility-scale battery projects, Robbins continued. Their more variable, less predictable revenues will discourage risk averse tax equity investors but allow transferability until merchant storage market risks are better understood, she added.

“Transferability will be absolutely essential” for merchant storage, agreed Jason Burwen, vice president of policy and strategy, for merchant storage provider GridStor.

But to the surprise of many tax credit market-watchers, traditional institutional tax equity investors have been involved in many initial uses of IRA tax credit transferability, instead of the wider investor market that was expected to leap at the opportunity. Generate’s Robbins offered an explanation.

Some equity investors are combining tax credit sales with tax equity partnerships “for technologies like renewable natural gas that are now but were not previously eligible for tax credits,” Robbins said. “The project owner can sell some credits to tax burdened buyers familiar with the technology to reduce the investment debt,” and a tax equity partner could then take limited ownership, and “get the remaining credits and the depreciation value,” she added.

Transferability can also be part of tax equity transactions for technologies with limited risks like solar and wind, Robbins continued. Tax equity investors can monetize their excess tax credits by transferring them to the new buyers like corporate interests coming into the transferability market, she said.

Segue’s Riester disagreed. Tax equity and transferability “will most commonly be used separately” because the hybrid concept tends to make buyers and sellers “skittish,” he said. Financing with transferability will be “faster, with fewer parties, fewer documents, and smaller project finance teams”, he added.

Norton Rose Fulbright’s experience supports Robbins’ idea that many new tax credit sales will be combined with tax equity transactions. The law firm has facilitated the closing of seven tax credit sales through transferability, has 19 in preparation, expects more, and most investors insist on some form of hybrid transaction, Martin said. They want the depreciation deduction available only through tax equity partnerships and not through tax credit sales because it can be worth “up to 14% of a project’s capital cost,” and “that is a lot of money to leave on the table,” he added. 

Financial transactions involving tax credit sales through IRA-enabled transferability are only emerging slowly while investors and their legal representatives carefully consider deals with hundreds of millions or billions of dollars at stake.

A $580 million tax credit transfer to Bank of America Securities was part of a recent $1.5 billion equity investment by renewables developer Invenergy and multinational investors CDPQ and Blackstone Infrastructure that closed August 16, according to a release from Norton Rose Fulbright.

On Sept. 27, unregulated renewables developer Avangrid, a subsidiary of the Iberdrola Group, announced the sale of an estimated $100 million of 2023 production tax credits from eight wind projects. Transferability “will allow us to pay down debt and make further capital investments to benefit our customers,” Avangrid CEO Pedro Azagra said in a statement.

On Oct. 2, developer Ashtrom Renewable Energy announced a $435 million equity investment in a Texas solar project that included a $300 million tax credit transfer to an undisclosed “leading U.S.-based institutional entity.”

Utilities are also interested in the IRA’s new mechanism for financing clean energy projects. Transferability can help “ensure we have a diverse mix of energy sources to achieve this ambitious transition in a way that protects reliability,” Duke’s Monroe said. More information on Duke’s potentially groundbreaking auction of tax credits is expected after further Treasury guidance “on IRA implementation is more complete,” he added.

Though some utilities are already buyers and sellers of tax credits, their opportunity "is complicated,” Norton Rose’s Martin said. They face accounting rules imposed by Congress in the 1970s that limit their ownership of renewables and require further specific guidance by the IRS to ensure they can benefit from transferability, he added.

But “if the cost of capital goes up, the cost of energy goes up, power prices go up, and rates go up, and utilities should evaluate how transferability might bring those costs down,” said Reunion’s Lee.

“Many utilities can and should be buyers of tax credits” and some could even handle their own tax credit transactions to “improve their net income,” and lower costs to customers, Segue’s Riester added. “Any and all” tax credit buyers will be needed “to satisfy the absurdly large new supply,” he said.

Two key questions

There are two hurdles transferability still faces, financial and policy analysts say.

Too expensive? The Congressional Joint Committee on Taxation estimated the total tax credit value by 2033 will be worth $663 billion, significantly more the original projection of $369 billion for all the IRA’s climate and energy provisions.

That will, however, depend on how long transferability remains an option, Forbes contributor Marie Sapirie reported June 8. A similar 1981 tax reallocation option was repealed in 1982 after Congress found taxpayers had “responded too enthusiastically,” making it “too expensive” and a threat to taxpayer “respect for and compliance with the tax laws,” Sapirie wrote. “The IRA has the same potential problem,” she added.

A political backlash is concerning, but it is likely to be “reasonably contained,” said Segue’s Riester. Legislative procedure may limit a future Congress’s power to “cancel” the IRA, and the “disproportionate benefits” in red states may make many representatives, though not all, unwilling to vote “against their constituents’ interests,” he added. 

Too complex? Transferability advocates are confident transactions will be streamlined, but other analysts are not as certain.

Both tax equity and transferability are relatively complex financial investments that have transaction costs and due diligence complexities that could make scaling transactions difficult, Generate’s Robbins said. Software-enabled platforms that partially automate transactions might, however, “bring new corporate buyers into the market,” and “other possibilities for this marketplace are still emerging,” she added.

Standardization that reduces friction and streamlines transactions “will be challenging initially but participants will move in that direction,” AES’s Glazer agreed.

Digital platforms to streamline transactions are at present “only matching single buyers to single sellers,” Norton Rose’s Martin responded. Their standardized agreements will not replace “due diligence by buyers facing penalties for inaccurate credit valuations,” he added.

But IRA provisions have introduced a “new world” of financing opportunities, and “many new financing structures will emerge to support the many new technologies,” said Generate’s Robbins. “There will be frictions as these new markets develop, but there are a lot of good options,” she added.