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The U.S. clean energy transition is expected to accelerate this year, buoyed by recent policy and other actions, but transmission and financing are among its challenges. The following is a snapshot of some of the major developments and trends expected in nine critical areas of the energy transition this year.

FERC: Transmission planning tops agenda at shorthanded agency

The Federal Energy Regulatory Commission began the year with only three commissioners, leaving the agency at risk of losing its quorum if one of its members leaves unexpectedly.

Transmission planning and cost allocation reform is perhaps the top item on FERC’s agenda. The agency last year issued a final rule revamping its grid interconnection requirements in a step aimed at easing the massive backlog of generating and storage projects seeking to connect to the grid. Late last year, FERC Chairman Willie Phillips said he plans to advance as soon as possible a transmission planning rule that was proposed in 2022.

“There'll be a lot of pressure on the commission to get a [transmission planning] rule out pretty quickly in 2024,” said Neil Chatterjee, a former FERC chairman who is now a senior advisor with Hogan Lovells.

In the face of growing extreme weather, FERC will also likely continue to focus on grid reliability and resilience, a priority for Phillips, who formerly worked at the North American Electric Reliability Corp., which oversees grid reliability.

The agency will also likely tackle proposed gas pipelines and liquefied natural gas export projects, and may initiate efforts to reform capacity markets, according to observers. The agency is also facing pressure to respond to reliability concerns related to an Environmental Protection Agency proposal to limit greenhouse gas emissions from fossil-fueled power plants.

“FERC will be in the news a great deal this year,” Chatterjee said.

Transmission: Will 2024 mark the start of a buildout?

Several major transmission projects — TransWest Express, SunZia and Grain Belt Express, for example — made progress last year, indicating that 2024 may be the start of a significant buildout of the U.S. transmission system.

At the same time, including Grain Belt, there are 36 “ready-to-go” high-voltage transmission projects across the United States that could interconnect about 187 GW of renewable energy capacity, according to a September report by consulting firm Grid Strategies.

Some of those projects may benefit from the Department of Energy’s Grid Deployment Office — launched in 2022 — which has about $26 billion in available funding to improve the transmission system and bolster grid resilience and reliability. As part of that effort, in late October, DOE said it is entering into talks to spend up to $1.3 billion from a revolving loan fund for capacity buys on three transmission projects across six states. DOE expects the capacity purchases will facilitate financing for the projects.

In a move that could further support transmission development, DOE in December issued guidance on how it plans to designate National Interest Electric Transmission Corridors in areas where transmission capacity constraints or congestion is harming consumers.

DOE and FERC are also supporting the increased use of “grid-enhancing technologies” — such as dynamic line ratings and power flow controllers — to get more out of the existing transmission system. FERC’s new interconnection rule, for example, requires transmission providers to consider grid-enhancing technologies when assessing what upgrades may be needed to bring new generation online.

Renewable energy: Record investments and decarbonization goals will keep the momentum

Throughout 2024, the demand for renewable energy will continue to increase as states, the federal government and major corporations pursue emissions reductions in order to meet decarbonization goals.

The Biden administration has set a goal for the U.S. to achieve a 50% to 52% reduction in economy-wide greenhouse gas emissions from 2005 levels by 2030, while companies including Apple, Amazon and Microsoft say they are on track to powering 100% of their operations with renewable energy by 2025. 

Eric Pollock, chief commercial officer of DSD Renewables, said that customer interest in solar continues to increase, though corporate customers looking to meet decarbonization goals are going through “evaluation phases” as they work out the logistics of doing so.

“They have a bit of compression ahead of them,” he said. “How do they actually meet those goals with — for example — seven years left [to a 2030 deadline]? Our conversations are becoming maybe more holistic.”

Demand for renewable energy is being bolstered by the tax incentives included in the Inflation Reduction Act, particularly when those incentives are coupled with domestic content adders, or bonus tax credits designed to spur the use of U.S.-made steel, iron and other products.

“I think when we look at the tandem push of federal investments flowing into clean energy, and the pull of decarbonization demand from public and private entities, they’ve never been stronger,” said Marlene Motyka, a principal at Deloitte and the firm’s U.S. renewable energy leader. 

Motyka added that she expects the $220 billion of announced public and private investment in renewable generation attributed to the IRA and Infrastructure Investment and Jobs Act so far to “really help boost” solar and storage, “and maybe even tee off hydrogen.”

Energy storage: Continued growth, permitting challenges and a focus on longer durations

2023 was a bumper year for the energy storage sector: the U.S. installed a record 7,322 MWh of storage in Q3, bringing total deployments in the first three quarters to 13,518 MWh — already surpassing the 11,976 MWh deployed in all of 2022.

Experts expect that growth to continue in 2024, in part due to the continuing tailwinds from the Inflation Reduction Act. While installations are expected to increase in large markets like California and Texas, the market is also expected to grow in states like Arizona, Nevada, New York and Florida, which are increasingly turning to energy storage to ensure grid reliability, said John Hensley, vice president of research and analytics at the American Clean Power Association.

One policy development the industry will be keeping its eye on is ongoing clarity around guidance released by the Treasury Department on the standalone storage investment tax credit, according to Noah Roberts, ACP’s director of energy storage. The department released preliminary guidance in late November.

However, the storage industry will also face certain challenges, especially when it comes to permitting, said Vanessa Witte, senior research analyst, energy storage, with Wood Mackenzie.

“You have a lot of areas that have become a lot more difficult to permit — sometimes it has to do with land rights, sometimes it has to do with NIMBYism, but there’s just more issues than before that have to do with permitting…” she said.

Bogged down interconnection queues remain another source of anxiety for the industry, thanks to review processes that aren’t quick enough to match the need for new projects as well as the huge volumes of project applications that are entering the queues, according to Hensley.

Lithium-ion batteries, with durations of between one to four hours, are expected to continue as the technology of choice for 2024. However, the industry is slowly moving towards technologies that offer longer discharge durations.

The industry could see progress on some of these technologies, in the form of more pilot projects, more manufacturing facilities and maybe some projects that move from the pilot scale to commercial scale, Witte said.

Distributed energy resources: All eyes are on virtual power plants

Distributed energy resources — including rooftop solar, battery storage and electric vehicles — have been expanding on the U.S. grid in recent years, but looking to 2024, some experts see a clear focus on virtual power plants.

VPPs — essentially aggregations of distributed energy resources, which can operate on the grid like makeshift power plants — are at a potential inflection point, a September report from the U.S. Department of Energy concluded. The agency estimates that tripling VPP capacity to between 80 GW and 160 GW by 2030 could lead to power system savings of $10 billion a year.  

“The notion of distributed resources of various kinds that can be dispatched, can be controlled — that I think is a broad theme going into 2024,” said Ryan Katofsky, senior fellow at Advanced Energy United.

“We’re going to see more emphasis on ways to grow that market, and to take more advantage of those resources as they come on to the grid,” he added.

There are a couple of different factors driving this interest in VPPs. There are simply more distributed resources being deployed, leading to more scrutiny into how they can be integrated into the operations of the grid, Katofsky said. There’s also a focus on the role VPPs can play in ensuring grid reliability, as well as addressing the general need for more flexibility on the demand side, he added.

Simultaneously, the move to electrify the transportation and buildings sectors is also leading to load growth after several years of relatively flat electricity sales.

“So there’s changing load shapes and increasing demand — and distributed resources that are controllable can help address those needs,” he said.

So far, a lot of the DERs deployed on the grid have been rooftop solar. But there’s been an increasing shift towards distributed storage that is expected to continue and intensify in 2024, especially as electricity system planners keep an eye on reliability needs.

On the regulatory front, 2024 will continue to see a lot of activity around the implementation of the Federal Energy Regulatory Commission’s Order 2222, a 2020 decision that instructed regional transmission organizations and independent system operators to remove barriers that could prevent aggregations of DERs from participating in wholesale power markets, according to Katofsky.

Nuclear: Facilitating the deployment of advanced reactors

In 2024, several significant trends are likely to emerge in the U.S. nuclear energy sector in project deployment, licensing and investment, according to Judi Greenwald, executive director of the Nuclear Innovation Alliance, including “more new reactors [progressing] through the Nuclear Regulatory Commission’s licensing process.”

TerraPower is expected to submit a construction permit application to the NRC for its Natrium fast reactor in Kemmerer, Wyoming, and X-energy is expected to submit a construction permit application for its Xe-100 gas-cooled reactor at a Dow Chemical facility in Seadrift, Texas. Regulatory reviews are also expected to advance for GE-Hitachi Nuclear Energy’s BWRX-300 SMR and other reactors.

In addition, in 2024, the NRC “may issue the proposed ‘Part 53’ rule for public comment, which is a major overhaul of its regulations intended to make it easier to license new reactors,” Union of Concerned Scientists Director of Nuclear Power Safety Edwin Lyman noted.

In 2024, the Union of Concerned Scientists expects to see more utilities pursue subsequent license renewals — from 60 to 80 years — for existing reactors “as well as power uprates that would enable them to obtain tax credits for new sources of ‘clean’ energy made available under the Inflation Reduction Act,” Lyman said.

Regarding state and federal policy priorities around nuclear, in 2024, “we hope to see continued momentum around legislative issues like expanding energy standards, repealing prohibitions and moratoriums on new nuclear energy, removing regulatory impediments, and modernizing market structures,” said John Kotek, senior vice president of policy development and public affairs at the Nuclear Energy Institute.

“In 2023, major financial institutions including Citibank began to publicly discuss new nuclear energy as a clean energy solution,” Greenwald said. “In 2024, we expect to see additional financial institutions focus on the potential opportunities related to new nuclear energy projects and for potential customers to work with these institutions to better understand how to structure projects to reduce financial risk,” she added.

Hydrogen: Tax credit uncertainty could stall projects in 2024

The hydrogen industry could be in for a relatively quiet 2024 — at least in terms of project announcements and construction.

With the final tax credit guidance still in the air, uncertainty around which projects will qualify for the incentive continues to delay decisions about which hydrogen projects get built, Frank Wolak, president and CEO of the Fuel Cell and Hydrogen Energy Association, said. Litigation could further drag out the debate around the guidance if leading hydrogen companies end up suing the Treasury Department for its decision, Wolak said.

Meanwhile, the guidance itself stands to delay projects if one of the requirements proposed in the draft takes effect, Wolak said. Treasury's proposal to require hydrogen producers to use new renewable energy or fuel resources would mean that hydrogen projects will need to wait three to four years for these new resources to come online. Between this rule and the delay of the guidance itself, Wolak said it was likely that many projects slated for 2024, 2025 or even 2026 may be postponed or canceled entirely.

The coming year is also expected to bring more detail around what the DOE's selected hydrogen hubs will ultimately look like, said Nick Connell, interim executive director of the Green Hydrogen Coalition. DOE is expected to finalize its negotiation with the hubs in the coming months. Yet some of the proposed hubs passed up for funding by the DOE have continued to move forward, Connell said. And several states — regardless of whether they will receive hub funding or not — are working on their own incentives for hydrogen producers. This could mean projects outside the selected hubs may be able to move faster than those eligible for federal funding, Connell said.

Cybersecurity: More collaboration, implementation of new initiatives

Hackers are expected to keep up a relentless stream of cyberattacks on the U.S. electric sector in 2024, meaning new approaches, collaboration and funding will be required to keep the grid safe, say experts.

From a policy perspective, the Biden administration took several steps to address cybersecurity threats in 2023, experts said. “We don’t anticipate any substantial shifts in policy or regulation federally,” Katherine Ledesma, head of public policy and government affairs at cybersecurity firm Dragos, said in an email.

“We will continue to see a push for regulatory harmonization as the administration has promised to use all policy and regulatory levers to raise the baseline level of cybersecurity for infrastructure across all sectors, including a focus on securing the software supply chain,” Ledesma said.

The electric sector will also see continued efforts to update North American Electric Reliability Corp. rules to allow the newest technologies to be utilized, said security consultant Tom Alrich.

Experts say cloud technologies can provide cost, security and reliability benefits to the grid but NERC’s Critical Infrastructure Protection standards do not allow them to be used for certain larger assets. In December, NERC’s standards committee began the process to modify the CIP standards to allow use of cloud computing by all systems.

“This problem has imposed a huge cost on NERC entities, as more and more software developers shift to the cloud as the primary or only delivery vehicle for their software,” Alrich said.

Utilities will also respond to the growing cyber threat by improving risk governance, said David Chaddock, managing director of cybersecurity for business and technology consulting firm West Monroe. One approach is through the use of protection level agreements — similar to service-level agreements — which utilities can utilize either internally or with third-part vendors to harmonize efforts and ensure security initiatives have needed resources.

Whether you call it data governance or cyber governance, “you’re going to hear a lot more about governance this year,” Chaddock said.

Electrification: Load growth, interconnection delays expected as more vehicles and buildings go electric

Electric vehicles and buildings added to utility loads in 2023, and experts anticipate the trend will continue in 2024 even as the grid may struggle with increased power demands.

Load growth caused by EV adoption first began showing up in the U.S. “in a very localized way,” with individual feeders being stressed by a few new vehicles in a neighborhood, said Mike Henchen, RMI principal for carbon-free buildings.

“We're starting to see the first ways that building electrification has an impact. And in a similar way, I think it’s very local,” Henchen said.

“We've seen a lot of interest in all-electric new construction, especially driven by building codes and local policies around the country,” Henchen said. But there can be “friction” because the utility “may or may not have the capacity readily available to interconnect all electric neighborhoods.”

“We started to see the first inklings of that in 2023 and probably will see more of it in 2024,” he said.

Efficiency can play a major role in limiting the electricity demand impacts of buildings, and in 2023, the U.S. made “significant strides” on appliance efficiency and industrial decarbonization, Steve Nadel, executive director of the American Council for an Energy-Efficient Economy, wrote in a Jan. 2 blog post.

ACEEE officials said they are also watching California, where the state’s 2025 building code is expected to be published this year and could push more homes to go electric rather than use natural gas.

Electric transportation is also adding to demand, as more consumers choose an EV. There were 1.2 million EVs sold in the U.S. last year, according to estimates by Cox Automotive.

EVs made up 7.6% of new vehicle sales in 2023, up from 5.9% in 2022, Cox said. And in the fourth quarter, EVs were 8.1% of new sales. Though growth has slowed, the firm’s expectations are for EV sales to surpass 10% of new sales in 2024.

The rollout of electric vehicle chargers through the federal National Electric Vehicle Infrastructure program will also continue, said Ryan McKinnon, a spokesperson for the Charge Ahead Partnership, which represents businesses interested in providing EV charging. States, however, will be putting a greater focus on where those chargers are installed, and there is a need for new EV-specific charging rates, he said.

“Many NEVI-funding recipients will struggle to turn a profit on EV charging because of demand charges, so expect to see increased calls for EV-charging-specific rates,” he said.

The Charge Ahead Partnership supports laws that restrict utility ownership of charging stations, and McKinnon said the group expects success on the issue this year.

Texas, Georgia and Oklahoma have laws limiting or prohibiting utility ownership of EV charging stations. Arizona, Florida, Nebraska, Ohio and South Carolina “are all likely to take up the issue of utilities owning EV charging again, after legislation stalled in 2023,” McKinnon said.

The Federal Energy Regulatory Commission enters 2024 with Willie Phillips starting his second year as the agency’s head and at least one issue — transmission planning and cost allocation reform — teed up for early action.

Other top priorities for FERC this year include continued efforts to improve the interconnection process, consideration of expanded transmission ties between regions and possible power market reforms, according to agency experts.

Also, with Commissioner James Danly’s term ending, the agency is down to only three commissioners: Phillips and Allison Clements, Democrats, and Mark Christie, a Republican. Clements’ term ends June 30, although she can remain as a commissioner until the current Congressional session expires at the end of the year.

Having only three commissioners — just enough members for a quorum to vote on issues — presents risks and benefits.

“FERC functions best when it has a full complement of five, and I always get nervous when you get down to three,” said Neil Chatterjee, a former FERC chairman who is now a senior advisor with Hogan Lovells.

A commissioner could leave the agency for some reason or may have to recuse themselves from a vote, leaving the agency without enough commissioners to vote on pending matters, according to Chatterjee and former FERC Chairman Richard Glick — now a principal with GQ New Energy Strategies, a consulting firm.

However, having three commissioners means there are never tie votes that could prevent action on an issue, such as transmission planning reform.

“In some ways, there will be more freedom and more ability to move out orders because there's not a possibility of a tie,” Glick said.

Also, FERC may be able to draft and issue orders more quickly because commissioners won’t need to respond to Danly’s relatively frequent dissents, he said.

“I think this group of three will work very well together,” Chatterjee said. “I think this is going to be the year of Willie Phillips at FERC. He will be able to work well with both of his colleagues.”

While usually best to have a full commission, filling FERC’s empty seats could delay the agency’s work on key initiatives, such as its pending transmission planning rule, according to Glick and Chatterjee.

“If you had two new commissioners, even if they had some experience, it takes a long time for everyone to get up to speed,” Glick said. “It might be easier to allow the commission to work with the three members that have been there a while and get some of those orders out and then nominate two new commissioners.”

Transmission a top Phillips’ priority

Earlier this month, Phillips outlined his priorities for the agency: grid reliability, resource adequacy — ensuring there are enough power supplies to meet demand — and transmission, including a rulemaking on its backstop siting authority for power lines in national interest transmission corridors.

“There are matters that are critically important, beyond transmission,” Phillips said Jan. 18 during a media briefing. “We're focused and we can do more than one thing at a time.”

Phillips said he aims to issue a final rule on transmission planning and cost allocation in the coming months. “I’m confident that the collective expertise and commitment of FERC will lead us to equitable and forward-thinking transmission solutions that will stand the test of time,” he said. “There’s nothing that I know … that can make me believe that we can’t get this work done.”

FERC is under pressure to issue its transmission planning rule, in part because of concerns current rules incentivize utilities to build local power line projects instead of regional projects that may provide larger benefits, such as accessing new renewable energy supplies.

In the last two months, companies such as Amazon.com, Apple, Google, Meta and Microsoft, industry groups like the Clean Energy Buyers Association and the American Council on Renewable Energy, environmental groups like the Natural Resources Defense Council and the Environmental Law & Policy Center as well as 21 Senate members and 113 House members have urged FERC to issue its pending proposal.

Danly’s exit from FERC may give Phillips the ability to “do a little bit more” on transmission, Karen Onaran, president and CEO of the Electricity Consumers Resource Council, said, noting the former commissioner opposed FERC's transmission and cost allocation proposal.

Christie appears open to elements of the proposed transmission rule, according to Onaran. “He may not be 100% there, but I think the commission can actually move forward at least on some of what’s pending,” she said, adding that Phillips would prefer a unanimous order.

Interregional transfer capacity on deck

Besides the planning and cost allocation rule, FERC has other transmission-related priorities on its plate. It is also exploring the possibility of taking steps to bolster transmission capacity between regions, Phillips said during the Jan. 18 media briefing.

Those efforts are running alongside a North American Electric Reliability Corp. interregional transfer study, he said, noting the study has started and may not take 18 months, the amount of time Congress gave NERC to do it.

“We are working on these two projects in parallel so that when NERC concludes its study, FERC is ready to act immediately,” he said.

NERC expects to complete its transfer capacity analysis in July and it has a Dec. 2 deadline to submit the study to FERC.

Interconnection reform efforts continue

FERC observers expect the commission will continue its efforts to reduce grid interconnection queue backlogs to follow up on its landmark Order 2023 issued in July, which set new interconnection requirements.

FERC is preparing to respond to requests for rehearing and clarification on its interconnection decision, according to Caitlin Marquis, a managing director at Advanced Energy United. And in early April, regional transmission organizations and transmission providers will file their Order 2023 compliance plans for FERC review, she said. Both events will give FERC an opportunity to offer additional guidance on its expectations for revised interconnection processes, she said.

Also, Phillips has indicated the commission would hold a technical conference on automation in the interconnection process this year, Marquis said.

“There's still a lot of issues associated with the interconnection processes around the country,” Glick said “I think FERC is still going to be very busily involved in interconnection reform in 2024.”

Grid reliability, resource adequacy

Grid reliability — a topic Phillips regularly says is FERC’s “job number one” — is another major issue the commission will grapple with this year, according to agency experts.

“Extreme weather is highlighting the vulnerabilities of a gas-dependent system,” said John Moore, director of the Sustainable FERC Project at the Natural Resources Defense Council. “There is more than sufficient replacement capacity in the interconnection queues to offset retiring capacity, and more on the way, but the queues are moving far too slowly to integrate the new resources. FERC really needs to take a look at further interconnection reforms to help fix this serious problem.”

“There are red flags out there,” Moore said, pointing to a recent NERC report indicating most of the United States face possible power supply shortfalls over the next decade.

That could spur FERC action on interregional transfer capacity and interregional transmission planning, as well as possible efforts to lower barriers to high-voltage, direct current transmission projects, which can move power efficiently over long distances and provide other reliability benefits, Moore said, while noting that regional transmission organizations have many tools at their disposal to address reliability issues.

Capacity market reforms

There may also be action on ensuring that capacity markets are able to procure adequate power supplies amid an evolving resource mix, according to observers.

“In many regions, resource adequacy and capacity reform and capacity accreditation continue to be topics that are moving through the stakeholder processes,” Marquis said. “There are pending cases around those issues and likely to be further filings this year that the commission will be asked to weigh in on.”

Other key issues FERC will likely tackle this year observers said include:

• the use of grid-enhancing technologies, including dynamic line ratings, to squeeze the most out of the existing transmission system;
• proposed gas pipelines and liquefied natural gas export projects;
• guidance on how the agency considers environmental justice when it reviews proposed gas infrastructure projects; and
• reliability concerns related to an Environmental Protection Agency proposal to limit greenhouse gas emissions from fossil-fueled power plants.

Little expected from Congress

Given that it’s a presidential election year, the Senate has a slim Democratic majority and the House is controlled by Republicans, observers doubt Congress will pass transmission, permitting reform — a priority for Sen. Joe Manchin, D-W.Va. — or other energy-related bills.

“I don't even know that they're going to be able to keep the government open, let alone have a legislative vehicle to carry permitting reform,” said Chatterjee, a former Senate aide.

“It's very hard to see the parties coming together on any major piece of legislation in this election year, given what the stakes are for the election,” said Glick, also a former Senate aide.

Uncertainty about the election may spur the Department of Energy to sharpen its efforts to distribute funding for clean energy and other programs in the Inflation Reduction Act and the bipartisan infrastructure law, according to Glick.

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 2023 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.”

Last year was a challenging one for electric utilities: Share prices lagged broader market gains, supply chain constraints added costs and time to renewable energy projects, and electricity prices continued a 3-year rise. What does 2024 have in store for the sector?

“An exceptional level of volatility and opportunity,” is how Bank of America Global Research analysts described the situation for electric utilities and the clean energy sector in its Jan. 9 look ahead.

The U.S. is less than 10 months away from a presidential election that could have significant impacts on energy policy and the implementation of clean energy tax credits and federal loan guarantees. Interest rates may have stabilized, but at higher levels than in the past 15 years that experts say will increase refinancing and debt service risks for renewable energy developers. Higher electricity demand and moderating natural gas prices signal a mixed bag for consumers bills, say market observers.

Investment in new technologies will grow, but not uniformly. Experts say hydrogen near-term expectations may be outsized, and investment in virtual power plants could see rapid expansion. Solar deployments may stabilize after years of supply chain constraints and tariff uncertainty, and batteries could reach “critical mass” as an asset class, said BOA. .

Electricity prices to remain elevated

Residential electricity prices averaged $0.1588/kWh in 2023, completing a rapid runup from $0.1372/kWh in 2021, according to data from the U.S. Energy Information Administration. Prior to that, electricity prices had been relatively stable for years.

EIA expects U.S. retail electricity prices to fall slightly in 2024, to average $0.1573/kWh, before rising again to $0.1611/kWh in 2025. The forecast is based largely on moderating gas prices, which EIA expects to remain near $3/MMBtu through 2025 when liquefied natural gas exports begin to rise.

That level “should keep average wholesale power prices in most regions less than or close to prices last year,” according to the agency’s short-term outlook.

There are regional differences, however: EIA is forecasting wholesale electricity price increases for New York and New England this year.

Moody’s Investors Service in December said it was maintaining a stable outlook on the unregulated utilities and power generation sectors, “based on our expectations for higher power prices.” Increased electricity demand from data centers, industrial activity and weather will be a factor in “driving higher forward power prices across most markets.”

The Electric Reliability Council of Texas market “is the exception,” Moody’s said in its 2024 outlook, “with declining on-peak power prices as solar power is forecast to grow rapidly in Texas over the next 3 to 5 years.”

However, both EIA and Moody’s say Texas could see electricity price spikes under constrained market conditions.

And in California and the West, there is a “shortage of generation, so even if gas prices stay low, power prices could stay high in some areas,” said Moody’s Vice President Toby Shea.

Moody’s expects gas prices this year to range from $2.50/MMBtu to $3.50/MMBtu — a significant decline from 2022 when prices reached almost $9/MMBtu, said Moody’s analyst Jillian Cardona.

Henry Hub spot prices closed out 2023 around $2.50/MMBtu “so that's fairly supportive for credit, for the regulated utilities,” Cardona said. “We don't expect them to have difficulties with excess gas costs.” Moody’s maintains a stable outlook on the regulated utility sector.

But while gas often sets the price of power as the marginal fuel it is not the only factor, said Paul Cicio, president and CEO of the Industrial Energy Consumers of America.   

“We have entered into a period of accelerating electricity price inflation for decades to come,” he said, and laid the blame on increasing capital investment in transmission that is built without competitive bidding.

The Federal Energy Regulatory Commission has proposed new transmission planning and cost allocation rules, but it “steps away from requiring competitive bidding of transmission projects instead of embracing it,” Cicio said. “Without competition, monopoly incumbent electric utilities do not have an incentive to reduce costs when building new transmission projects.” 

The impact of competitive bidding is “complicated,” said Mark Dyson, managing director of RMI’s Carbon-Free Electricity program. But "if you build the right kind of transmission — for example, the kind that helps you unlock very low cost wind and solar resources that otherwise would not be deliverable to market — that actually lowers the price” of electricity going forward.

But those aren’t the kind of lines utilities have been building recently, he added.

“The kind of lines that we ended up building in this country for the past five years are more regional lines that are not necessarily optimized around bringing low cost resources to market [and] are more justified from a reliability perspective,” Dyson said.

Power demand rises in 2024, flat the next year

Electrification of both the transportation and the building sectors is beginning to add to utility loads, but so far the new demand is showing up mostly at the local level, experts said. Weather and economic growth will drive national increases in power demand in 2024, observers said.

EIA expects U.S. electricity demand to rise 2.6% in 2024, largely based on weather, and then remain stable in 2025.

“US economic growth is also likely to drive higher commercial and industrial demand, including incremental demand requirements for data centers across the country,” Moody’s said.

RMI in December looked at utility integrated resource plans to quantify the potential demand impacts of the Inflation Reduction Act, which was passed in 2022 and invests billions of federal dollars in clean energy and electrification.

About half of U.S. utilities file an IRP, said Dyson, and RMI’s analysis showed that in January 2021 those utilities expected demand to increase by 6.5% by 2035. Since the IRA’s passage, expectations for demand growth by 2035 now exceed 16%, RMI found.

“Demand growth projections are ticking up steadily,” Dyson said. “We've had 15 years of flat demand in this country, and now that is no longer the case.”

The industry must cope with higher interest rates

While interest rates have stabilized, they remain high and will be a challenge for some industry segments, debt analysts said.

For unregulated utilities and clean energy developers, “the much higher cost of debt increases both debt service costs and refinancing risk,” Moody’s said. “For new renewable projects, the higher cost of debt raises the levelized cost of power.”

The combination of higher capital costs and elevated inflation “has threatened the viability of some planned renewable power projects especially for offshore wind,” Moody’s said in December in its 2024 outlook for the sector.

On the regulated side, there are bigger impacts on utility holding companies than operating companies since interest expense at operating companies typically flows through to customers, said Cardona.

“The biggest risk is for holding companies that have significant debt maturities coming up within the next year that need to be refinanced, as well as any exposure to floating rate debt,” she said. “There's some potential that interest rates may come down. It seems like the Fed is signaling that that's a possibility for early 2024. But that remains to be seen,” she said.

Impact of the election?

The Republican caucuses and primaries have just begun but former President Donald Trump promised that if reelected he would end the “Green New Deal atrocities” on his first day in office. Observers say the election poses some risk to clean energy incentives funded through the Inflation Reduction Act, including tax credits and Department of Energy loan guarantees.

“To the extent that the various Biden administration agencies do not complete work on carbon emissions (actual emission limitations and disclosures), hydrogen, electric vehicle, and other policy objectives, there is a risk that a Republican administration can stop or overturn many elements,” Bank of America analysts wrote.

The largest risks are tied to changes in “executive interpretation of the IRA, rather than the credits themselves,” they wrote.

BOA analysts also said they are looking for the completion of DOE federal subsidy programs for clean energy in 2024. “Watch for real progress on preliminary awards” early in the year, they said. “We perceive conditional loan approvals need to be established prior to the end of calendar year ’24.”

“There's talk of repealing or changing the IRA if Republicans get in power, but we don't know exactly what they would do,” Moody’s Shea said. “So it's kind of hard to say what the impacts would be. The IRA benefits utilities across the country. So it's not like there's a blue-versus-red kind of issue. They all benefit.”

The Department of the Treasury and the Internal Revenue Service in December released proposed regulations defining criteria hydrogen producers will have to meet to qualify for the 45V clean hydrogen production tax credits created by the Inflation Reduction Act.

The proposed ruleis just one among a series issued by IRS and Treasury on how to qualify for various IRA clean energy and EV tax credits.

There is some pressure on the Biden administration to finalize the rule “expeditiously,” said Alex Piper, senior associate with RMI’s U.S. program. The comment period ends Feb. 26, and even if the rule is finalized “there are certainly other ways in which ... a future administration that's different than this one could could come in and start to hinder the progress.”

Investment in new tech: Hydrogen, VPPs

2024 will be a year of investment in new technologies though some will start with more momentum.

"We see hydrogen prospects as subdued heading into 2024 despite the passage of the IRA,” BOA said. “We stress this is all about expectations where hydrogen expectations around a ‘green new economy’ have appeared meaningfully outsized after IRS released quite stringent new regulations regarding its implementation.

“On balance, we expect 2024 to prove a ‘reset’ year in expectations as hydrogen companies had anticipated meaningfully greater latitude” on hourly matching of emissions and other considerations, BOA said.

Under the proposed rules, hydrogen producers would have to use renewable or zero emission electricity from generators who began operation no more than three years prior to the construction of the hydrogen facility. The electricity would also have to be sourced from within the same geographic region as the hydrogen production facility, and would be subject to hourly matching rules beginning in 2028.

Piper said he doesn’t expect to see big electrolyzer projects deployed this year, “but we will hopefully see announcements and investment decisions made around hydrogen and industrial decarbonization.” 

New offtakes for clean hydrogen that can decarbonize steel, fertilizer and aviation fuel “are kind of the big investment decisions and [utility] business trends I think we'll start to see in the later half of this year and into next year,” he said.

Dyson said he also expects investment to increase in virtual power plants which “solve a bunch of problems that are now pressing for utilities across the United States. ... We've seen reliability go down and we've seen costs go up. If you get it right, VPPs can help address both of those challenges.”

Significantly expanding VPP capacity in the United States could save about $10 billion a year in grid costs, DOE concluded in September. There is 30 GW to 60 GW of domestic VPP capacity today, depending on how the resource is defined.

Dyson also said he expects to see more “clean repowering” projects, which are renewables sited at former fossil plants that have grid interconnections. RMI research published Jan. 16 found a 250 GW potential for repowering projects across the country.

“This is going to be a trend this year. We will see more and more utilities take advantage of this opportunity, because of the economics spurred by the IRA and because of the technical capacity of the grid to absorb new renewables at sites of existing interconnection,” he said.

A critical technology is needed to sustain the U.S. energy transition’s momentum, according to engineers focused on power system reliability and clean energy.

Inverters with “grid-forming” capabilities, or GFM, are needed to support the growing penetration of inverter-based resources, or IBRs, like wind and solar, according to engineers with the North American Electric Reliability Corporation, or NERC, and engineers with the Energy Systems Integration Group, or ESIG, which advocates for integrating and managing higher levels of renewables.

Inverters convert renewables-generated energy into the alternating current flowing through the U.S. transmission system.

“The power system’s heartbeat is a 60 Hertz, or cycles per second, current to which all generation on the grid must synchronize,” said NERC Senior Vice President and Chief Engineer Mark Lauby. “As long as variable renewables’ inverters synchronize their generation with that 60 Hertz heartbeat, they can deliver power into the system without concern about system faults,” 

But faults causing current fluctuations go uncorrected by today’s renewables’ limiting “grid-following” inverter capabilities, making deployment of GFM with new IBRs urgent, engineers agreed. 

The U.S. does not have unified comprehensive standards requiring grid following inverters, which took 20 years to develop in Europe, said Energy Systems Integration Group, or ESIG, Chief Engineer Julia Matevosyan. “And we don't have another 20 years to develop GFM standards to avoid reliability failures,” she added.

Fluctuations in the power system’s heartbeat that threaten reliability have been stabilized by traditional power plants, called synchronous machines, but they are retiring, engineers said.

To drive GFM deployment, pilots are needed to test GFM performance, engineers agree. Standards defining GFM requirements based on the pilot results must then be set by NERC and system operators, and market incentives for protecting reliability should be provided to reward those who deploy GFMs, the engineers said.

What GFMs do

Coal, natural gas, nuclear and hydropower plants are designed to drive spinning turbines that generate electricity at the heartbeat rate of 60 hertz, according to a National Renewable Energy Laboratory November 2020 GFM Roadmap. The “spinning mass” of those synchronized machines has a momentum, called inertia, that automatically corrects frequency fluctuations, it added.

As traditional synchronous machines with rotating mass like natural gas, coal and hydropower plants, are replaced with IBRs like wind and solar projects, system inertia is reduced, “making the risk of frequency swings higher,” NREL explained. IBRs using today’s grid following inverters do not significantly address those changes, but GFM detects them and adjusts power flow to limit them, NREL added.  

Without GFM, system operators can reliably integrate 30% to 75% IBRs by keeping synchronous generation online, ESIG’s Matevosyan told a Sept. 20 webinar. But keeping conventional generation online to protect reliability can lead to expensive renewables curtailments and a slower transition to IBRs, she added.

GFM can replace synchronous machines because it is “human programmed through power electronics, highly controllable and can provide very fast responses” to frequency fluctuations, Mahesh Morjaria, executive vice president, plant operational technology for utility-scale solar project developer Terabase Energy, told an RE+ renewables conference audience in September.

One key to the reliability provided by GFM is “frequency control,” to manage frequency fluctuations, the engineers said. Another is “voltage control,” to keep system voltage stable by increasing or lowering system output, they added.

GFM can also provide other system protections, called “stability services,” that detect “abnormal grid operating conditions,” and mitigate them through “disconnection of faulted parts,” NREL said.

“If the fault leads to a blackout, GFM can do a system ‘black start,’ by using IBR-supplied energy to restart generation and rebuild normal operations piece by piece,” Matevosyan said.

But including black start capabilities introduces design and operational challenges, said GridStor Senior Vice President of Engineering, Procurement, Construction and Technical Operations, Daniel Dedrick. And inverters designed for black start are 2% to 5% more expensive and require energy to drive the restart, he added.   

There are other questions about the cost of introducing GFM.

GFM economics

There may be increased costs for integrating GFM into IBRs but there may also be market opportunities that offset the costs, engineers and developers said.

New inverter capabilities “do not seem to be making IBRs more expensive now,” Terabase’s Morjaria said. And as market incentives emerge, IBRs with GFM “could provide lower cost reliability services that create additional revenues because they use zero cost fuel,” he added.

GFM are “basically inverter software,” and reprogramming could make GFM-equipped batteries “marginally more expensive by a few percent of the inverter’s cost,” Matevosyan said. It will, though, be significantly more cost-effective to equip new batteries with GFM before they are deployed instead of incurring administrative, engineering, and downtime costs for upgrading after deployment, she added.

“There is also a cost for inaction,” Matevosyan continued. Without GFM deployment, “there will be continued stability challenges, continued solar and wind curtailment, and the need for costly supplemental stabilizing equipment like new transmission,” she said.

“It does not appear that the costs associated with integrating GFM will take solar, wind, and batteries out of the market,” Lauby agreed. And GFM can enable the transition away from legacy synchronous machines to IBRs, he added.

The challenge is to cost-effectively introduce IBRs with GFM to meet the growing incidences of events that threaten reliability, Lauby, Matevosyan and others agreed. NERC documented three reliability-threatening events associated with high IBR penetrations in 2022 alone, following five between 2017 and 2021.

One key solution — GFM-equipped batteries — is gaining attention.

Batteries to lead GFM deployment

The growing momentum to deploy utility-scale batteries offers a unique opportunity to take advantage of the policy-driven clean energy build-out and enable GFM at scale, engineers and analysts said.

“DOE is investing tens of millions of dollars and making GFM a huge priority and the industry needs to adopt it,” Department of Energy Director, Solar Energy Technologies Office, Becca Jones-Albertus told the September RE+ audience.

And deploying GFM in batteries “is a low-hanging fruit solution,” Matevosyan’s March 2023 ESIG paper on GFM and utility-scale batteries reported. GFM can be integrated with the over 400 GW of battery capacity in U.S. interconnection queues, enabling wind and solar growth “cheaper and faster than adding new transmission to mitigate stability issues,” she said.

Energy is immediately available in charged batteries to power reliability services, Matevosyan added in a September ESIG webinar. Solar and wind might not be producing when the energy is needed or might not be able to forego generation revenues, and services from wind might cause turbines mechanical stress, she added.

The Electric Reliability Council of Texas, or ERCOT, will finalize performance requirements for GFM-equipped batteries by the second quarter of 2024, Matevosyan reported. ERCOT will use the requirements to develop market incentives to drive adoption of GFM-equipped batteries at “weak grid” areas with high IBR penetrations, she said.

There is “a unique window of opportunity to procure, test and gain experience with GFM technology” while IBR levels are moderate and synchronous machines are still providing reliability services, Matevosyan said. And with well-designed policy and market incentives, IBRs with GFM could offset costs with revenues from new or existing stability services markets, Matevosyan added.

“It is recommended to start requiring and enabling GFM in all future Battery Energy Storage System projects,” a September NERC paper on GFM-enabled utility-scale battery systems concluded. It can be added to new battery systems “at a relatively low incremental controller and hardware cost” and “may only require controls changes,” it added.

Pilots, studies and standards

Simulations and pilots are needed to test GFM performance at scale, followed by multi-stakeholder processes to develop standards for GFM based on studies of the pilot results, NERC, ESIG and NREL agree.

NERC’s 2021 white paper and its September paper on GFM with battery systems both called for those next important steps to get beyond current limited experience with large-scale GFM penetrations, NERC’s Lauby said.

“Pilots are also needed to learn to manage sets of large, asynchronous generation while synchronous machines are retiring and load is growing,” Lauby continued. It is “very complicated engineering that could lead to using artificial intelligence, and it should be thoroughly modeled and simulated to understand the coordination and control implications,” he said.

“We need to have the same confidence with a system that has many grid following and grid forming inverters as we do with a system with synchronous machines,” Lauby added. But, Matevosyan responded, “everybody wants somebody else to adopt grid-forming capabilities first.”

“System operators need to think about operating the grid differently,” which is why DOE is funding 15 demonstrations of solar and wind projects providing grid services and reliability, DOE’s Jones-Albertus told the RE+ audience.  

Following research, development and field trials of GFM, standards can be established to allow synchronous machines to be replaced completely by IBRs with GFM over the following 10 years to 30 years, NREL’s roadmap said. But for “the next decade and beyond,” the power system will have both synchronous machines and GFM-enabled IBRs, it added.

Demonstrations in California in 2016 and 2017 provided reliability services, and a small Michigan installation built in 2014 continues to stabilize a “weak grid,” Matevosyan reported. Hawaii’s Kauai Island Utility Cooperative will soon pilot GFM-enabled batteries, and Florida Power and Light will use a 2,000 MW battery deployment over the next decade to assess “the performance and benefits of GFM,” other engineers added.

“But the learning from pilots needs to come faster because wind and solar penetrations are rising and synchronous machines are retiring,” Matevosyan cautioned.