Repurposing old batteries from electric vehicles in alternative energy storage applications – like at fast-charging stations or rooftop and microgrid storage systems – is one of the ways to extend EV battery lifespans and electrify the transportation sector in a more sustainable manner, according to a new report from the Natural Resources Defense Council.

Batteries in EVs contain minerals like lithium, nickel and cobalt that can be associated with mining processes that contaminate their surroundings and pose a health threat to communities, the report noted. Many other products also use these materials, but EVs “could serve as a catalyst to clean up the dirty mining industry’s act,” according to the report.

One way to do this is to repurpose old EV batteries on the grid. “There’s definitely some potential in the utility sector, especially in terms of grid back-up storage … even though [old EV batteries] have lost, say, 20% of their original capacity… when you’re talking about grid storage that can still be a perfectly usable battery for several more years,” Jordan Brinn, author of the report and an advocate with NRDC, said.

“Our petroleum-based economy is very unsustainable… and electric vehicles as well as clean electricity and renewables are all part of the solution to this issue,” Brinn said.

If policy-makers and others aren’t careful, “these new technologies could potentially mimic some of the harms of those fossil fuel systems. … So we need to be making sure that we’re producing the minerals we need for EV batteries, for grid storage batteries, in the best way possible,” Brinn added. 

The best way to reduce the impact of battery supply chains is to reduce the amount of materials needed for them, the report notes. This could be achieved by increasing material efficiency, as well as finding second-life applications for vehicle batteries and better recycling methods. 

There are two kinds of second-life uses for EV batteries – reusing them in EVs that don’t need very high ranges, like golf carts, or repurposing them as a different energy storage application, such as storage systems for rooftop solar and microgrids, according to the report. 

When a battery is recycled, 95% of the minerals in it can be reused in new batteries, whether that’s for EVs or grid storage systems, Brinn said. 

The process of repurposing EV batteries to be used on the grid is still in its infancy and most of the companies working on it are in the start-up or academic laboratory stage, she added. 

The process has some challenges – the report notes that “it is important to keep in mind that a battery cannot be taken out of a vehicle and put straight into a new application.” A battery would need to be assessed, and then potentially reassembled to fix issues or replace certain cells, before being given a second life. 

More broadly, there are two issues that policy-makers will need to figure out before EV batteries are repurposed on the grid at scale. The first is regulation around access to battery management systems, Brinn said. Many different companies make batteries, each with their own proprietary design. 

“Right now, there is not a clear set of standards for other folks beside the battery manufacturer [to be] able to access that information” about how they function, she said.

The second issue is making sure there’s a flexible liability framework in place for repurposed batteries. Some battery manufactures may want to maintain some oversight over how the batteries are used, Brinn said, while others may not.

“That can get pretty complicated, so making sure there’s some clear frameworks in place for setting up who’s responsible in these multiple stages of this new life that a EV battery might be living,” is important, she said. 

The Department of Energy announced July 12 that it will award a total of $5.1 million in cash prizes to contest participants who innovate technologies for recycling the fiber-reinforced composites and rare earth elements in wind turbines.

Around 85% to 90% of the mass of a wind turbine can already be commercially recycled, but the remaining components present a barrier to a circular economy for wind turbines, according to DOE.

“There is a financial risk involved” for the private sector when transitioning to a circular economy, said Tyler Christoffel, DOE’s technology manager for its Wind Energy Technologies Office, in an interview. DOE hopes the cash prizes will mitigate that risk, he said.

Submissions to participate in the contest’s first round opened July 12 and close Sept. 29. In the first round, competitors will provide a concept for wind material recycling in the hopes of securing a $75,000 cash prize and an invitation to the second phase of the competition.

In the second phase, competitors will develop prototypes of their innovations, with up to six teams receiving cash prizes of $500,000 and vouchers to work with DOE national laboratories. The competition is part of DOE’s American-Made program.

Christoffel said that barriers to a circular economy for wind turbines include a lack of cost-effective strategies for recycling fiber-reinforced composites and rare earth elements.

“A lot of the rare earth materials are surrounded by other metals that are recycled right now, and the amount of the rare earth element material is relatively low compared to the material around it,” he said. “So companies have found difficulty in justifying the extra work it takes to separate out that material and divert it.”

Improvements to end-of-life recycling techniques would “make it a lot easier for entities that are responsible for decommissioning to justify investing in diverting those materials into these more sustainable pathways,” said Christoffel.

This bid for innovations is part of the Biden administration’s overall push to bolster the domestic supply chain of rare earth minerals and break U.S. dependence on foreign sources of those materials, including China.

A 2022 White House release estimated that a global clean energy transition will result in demand for rare earth elements, as well as lithium and cobalt — which are needed for batteries, wind turbines and solar panels — to skyrocket by 400% to 600% over the next few decades. 

In addition to making it cheaper to build wind turbines themselves, Christoffel said that successful commercial recycling for every aspect of wind turbines would assist with overall decarbonization. 

“When material can be used for a second life, especially when you can minimize the intervention that has to happen between taking material from one life into another one, then you see twice the functionality of the material for a significantly reduced emissions impact,” he said.

For companies aiming to buy clean energy, the most effective and least expensive procurement strategy is “carbon matching,” according to a report by consulting firm Tabors Caramanis Rudkevich, or TCR.

With carbon matching, a company becomes carbon neutral by buying from anywhere more carbon-free electricity than they use in a year, according to TCR. The strategy is based on “locational marginal emission rates,” the amount of carbon emissions tied to specific nodes on the grid. Other approaches call for buying clean electricity to offset a company’s energy use without regard to the extent those purchases reduce overall emissions.

“If you want to do the best you can for the least money, then shift over and think about marginal emission rates as the metric to use,” said Richard Tabors, TCR president and one of the authors of the report.

Under the carbon matching approach, companies buy emissions-free power in areas with high carbon emissions from power plants, such as in the Southwest Power Pool and parts of the upper Midwest, without considering how close those sources are to where the electricity is being used, he said.

Sourcing renewable electricity from those areas will displace more carbon than, for example, purchases from California, which already has a high amount of emissions-free resources, he said.

The TCR study was supported by a grant from Meta Platforms, a leading clean energy corporate user. Meta is part of the Emissions First Partnership, which supports carbon matching. Companies in the group, launched in December, include Amazon, General Motors and Intel.

TCR assessed four clean energy procurement strategies, including the industry standard — annual energy matching under which a customer matches their load with clean energy on a yearly basis.

Besides carbon matching, the firm also considered local energy matching, where clean power is procured from the balancing area where it is used, and hourly energy matching, with clean electricity procurement lining up with the hour it is used from resources within the load’s balancing area. Google in 2020 set a goal of hourly energy matching.

The report looked at two load profiles: one representing stand-alone commercial retail buildings and the other representing data centers or industrial customers.

It studied those loads in five areas for geographic and regulatory diversity: the California Independent System Operator; the PJM Interconnection; Duke Energy Carolinas; Portland General Electric; and the Los Angeles Department of Water and Power.

“We found that carbon matching was the only annual matching strategy to consistently achieve carbon neutrality, regardless of customer load profile and location,” Tabors and the other authors said in the report.

The study found that local, hourly energy matching is the least efficient strategy for cutting carbon emissions. It fails to achieve carbon neutrality on an hourly basis and only achieves annual carbon neutrality, at a high cost, by buying more than twice as much electricity as needed, according to the report.

In PJM, it would cost a commercial retail company $113/MWh under an hourly energy matching strategy compared to $6.30/MWh under a carbon matching approach, the TCR analysts found.

Solar projects in the Electric Reliability Council of Texas footprint offer the lowest-cost clean energy projects and photovoltaic projects in southern SPP were the most cost-effective at displacing carbon emissions, according to the report. 

Corporate clean energy buying surges

The report comes amid a surge in corporate clean power procurement.

In the United States, 326 companies had contracted for 77.4 GW of clean energy as of the end of 2022, up from about 10 GW five years earlier, according to a report from the American Clean Power Association, known as ACP. The capacity includes about 45,050 MW of solar, 28,830 MW of land-based wind and 975 MW of battery storage.

The 36 GW of operating clean power for corporate buyers makes up 16% of all operating clean power in the U.S., according to the trade group.

The top 10 corporate clean energy purchasers account for 54% of all U.S. corporate procurements with 41.8 GW of contracted capacity, ACP said.

Carbon matching is part of an ongoing effort to expand options for companies that want to buy clean energy, according to Doug Miller, director of market and policy innovation for the Clean Energy Buyers Institute, or CEBI, until late last month.

“We don't necessarily need more wind in Texas or solar in California, so the idea is how do we be a bit more strategic with deploying energy so we actually shave off those locations and times that are not yet carbon-free,” he said.

Lifting procurement barriers

CEBI, affiliated with the Clean Energy Buyers Association, last year started the Next Generation Carbon-Free Electricity Procurement Initiative to develop a framework for new procurement options, including carbon matching.

“We want to see hourly solutions, we want to see carbon match solutions, we want to see solutions for small businesses,” Miller said. “We think you need an all the above approach in terms of what's available, and then let the market, let the customers decide which best matches what they want.”

In its procurement initiative, CEBI identified roadblocks to new clean energy procurement options, including a need for “energy attribute certificates” to contain more data on electricity sources, he said. Additional data on the certificates, such as hourly and sub-hourly time stamps and carbon intensity snapshots, would support new types of clean energy purchases, he said.

Locational marginal emission rates are not widely available, placing hurdles to the carbon matching approach, according to Tabors. PJM has published real-time locational marginal emission rates since late 2021 and ISO New England has started reporting marginal emission rates, he said.

The Federal Energy Regulatory Commission should direct grid operators to report the information in real-time, according to Tabors. The Infrastructure Investment and Jobs Act calls for the U.S. Energy Information Administration to report hourly locational marginal greenhouse gas emission rates, the report noted.

Agrivoltaics, or the dual use of land for agriculture and solar energy generation, is experiencing increased adoption thanks in part to increased awareness about the associated benefits coming during a time of accelerated farm transitions, said BlueWave Solar Director of Sustainable Solar Development Jesse Robertson-Dubois.

This trend could continue, Robertson-Dubois said, as “a lot of land is changing hands over the next 10, 15, 20 years,” and as the Inflation Reduction Act’s tax credits for renewables projects bolster the industry.

There has been a “rapid increase in interest in agrivoltaics” across the U.S. for a variety of reasons, said Jordan Macknick, lead energy-water-land analyst for the National Renewable Energy Laboratory. 

“State governments, solar developers, farmers, and landowners are recognizing, and more importantly seeing first-hand, the multiple potential benefits that are possible with agrivoltaic projects,” Macknick said. “In some areas this is driven by land constraints, in other areas this is driven more by local perceptions of solar development, and in other regions farm economics are a major contributing factor.”

Legislative efforts on the federal level, as well as in states like Massachusetts and Colorado, “could spark further and more rapid change,” he said.

In May, Colorado enacted a law authorizing the state’s Agricultural Drought and Climate Resilience Office to award grants for new or ongoing research on the use of agrivoltaics. Previous bills to fund agrivoltaics in the state were “primarily sponsored” by Democrats, the Colorado Sun reported in January, but this bill won key support from Republican Sen. Cleave Simpson, who said he became interested in the practice as a result of economic problems he experienced while running his family’s 800-acre alfalfa farm.

Robertson-Dubois, who has a background in farming, said one of the things that drew him to agrivoltaics was driving past a solar array in Massachusetts and noticing that grass underneath the panels was getting green earlier in the season and staying green later. 

“I realized, ‘Hey, there’s a microclimate in there,’” he said. “It was my agricultural brain as a hay producer, and as a grazer managing sheep and cattle, that looked at that and said, ‘Oh, you could use that, that’s something you could manage for.’”

The aging population of current farmers means that generational farm transitions will soon increase, with “a lot of land changing hands” over the next 20 years, Robertson-Dubois said. He believes solar has an opportunity to offer additional benefits to new farm management, as agrivoltaic adoption is easiest when agricultural landowners are at a “point of transition.”

“I think we're hitting a watershed moment where people are starting to realize that there really are opportunities with agrivoltaics to help farmers diversify not only their revenue streams, but the types of agriculture that they're taking on,” Robertson-Dubois said.

However, the nature of agrivoltaic expansion requires finding agricultural land that is also well-suited to hosting a solar farm and can attract a farmer interested in innovating their operations – which can be a challenge. Transmission and grid connection capacity are the “major roadblocks” in terms of being able to site solar projects, he said, and even more so when it comes to agrivoltaics. 

“We can design a good agrivoltaic solar array, but we still need a person who lives within reasonable distance of it who wants to farm inside there,” said Robertson-Dubois. “So more capacity would be very helpful in terms of being able to reach more farmers that are interested in innovating in this way.”

Imagine, for a moment, that it’s the year 2050 and the energy transition is essentially complete. You live in a suburban cul-de-sac, and every vehicle you and your neighbors own is electric. Each house has rooftop solar panels, and a battery in the garage. Electricity flows in both directions — to customers, and from customers. And the last thing you want to happen, according to Alice Jackson, senior vice president and chief planning officer at Xcel Energy, is to bring your new EV home only to hear from your utility company that you can’t plug it in on certain days of the year.

“We have to envision that day, and think that the infrastructure we’re installing today has a high probability of [still] being there,” Jackson said in an interview last November. “But the world of 2050 is different from where we sit today. So how do we make sure the infrastructure we put in today meets the needs of 2050?”

At Xcel, the answer has been to create a whole new division dedicated to envisioning and planning for the utility systems of the future. Generation, transmission, distribution, and even natural gas service will be planned from within the same department, called the Integrated System Planning department, beginning this year.

In recent history, planning functions at utilities have become somewhat static, with projections based on slow, incremental growth or no growth at all, said Cristin Lyons, partner and energy practice leader at consulting firm ScottMadden. On top of this, regulators created incentives in the early 2000s for utilities that sectioned transmission planning and resource planning into separate fields, contributing to today’s structure where planning is often carried out by teams dedicated to a particular function such as distribution or generation, Lyons said.

Regulators have already done an about-face and increasingly require utilities to complete integrated resource plans that consider both power generation and demand. Today’s circumstances, however, may require an additional step of adding transmission, transportation, the transition from fossil fuels, and maybe even weather forecasting to the mix. And beyond this, Lyons said, is the question of speed — utilities need to share data and adapt their long-term plans much faster than they have done in the past.

This is where the idea of integrated planning systems comes into play. Going beyond merging multiple considerations into a single document, some utilities are now consolidating the company’s planners and modelers into unified teams in hopes of enhancing organizational innovation and flexibility.

New year, new planning team

At Xcel Energy, Jackson said in November, distributing the company’s planning functions across divisions dedicated to gas, electric and other services led to “incrementalism.” It wasn’t clear that the company had a unified, big-picture vision for the energy transition it had pledged to make.

“The concern was that we would end up rebuilding systems multiple times, or put something in place that would work for five years when they’re not typically five-year assets,” Jackson said.”We had to shift the question of, what do we need to solve today’s immediate problems, to how do we get to 2050, and what needs to change to get here.”

To do this, company leaders concluded they needed to move planning functions from resource-specific silos into a centralized division. The first 30 employees made the move late last year, and the rest of the team will join them by the end of this month. There will be no reduction in headcount, Jackson said — in fact, Xcel has determined they will need to hire additional staff to fill positions created within the new division.

In addition to the company’s transmission, distribution, generation and natural gas planning teams, the company is also moving standards functions from across the company into the planning division.

“We are deliberately creating a natural tension in moving the standards team that writes standards for construction, maintenance and design into the integrated planning,” division, Jackson said. “There has to be a close connection between planning and integrated operations. They are going to have to come back and give us feedback and say hey that grid forming inverter didn’t do what we thought so we have to modify the design.... This is why combining standards and planning is important. You no longer put in one size of cable, you put in a bigger size cable.”

This kind of re-organization may well make sense for a company like Xcel, which has strong net zero ambitions and offers both gas and electric services, according to Greg Litra, partner and head of energy, clean tech, and sustainability research at ScottMadden. At some point an integrated utility like Xcel will have to ask the question, do we expand the gas line or add more electric generation? he said. And they will need to have consistency and collaboration across the organization. 

But adopting a more holistic planning process might look different at a company where collaboration requires a walk across the hall, Lyons said. And Xcel isn’t the only utility reconsidering its approach to planning — Jackson cited work by Salt River Project in Arizona as part of the inspiration for their recent reorganization.

The operational solution

Although SRP has also created what it calls an integrated systems planning team, it hasn’t moved employees from or to any new divisions within the company. Rather, designated employees from within existing divisions now meet to coordinate planning functions across the company.

The process started in 2019 as part of a project to evaluate how SRP could navigate the energy transition while maintaining reliability and affordability, Angie Bond-Simpson, director of integrated system planning and support at SRP, said in a November interview. They formally kicked off their new integrated system planning process in November 2021.

Beyond coordinating internal planning functions, the integrated system planning team also coordinates with a 22-member community advisory group that includes representatives from local environmental groups, tribal interests, low- and fixed-income communities and even public schools.

Between November 2021 and November 2022, the SRP planning team created roughly 40 different system plans evaluating how the electric system could evolve across 12 different case scenarios. In 2023, SRP plans to take these models back to the community advisory team for input and analysis.

While this is the current process, integrated system planning could look different in the future, Bond-Simpson said.

“This is the first time that we are doing integrated system planning — we’re on the leading edge of that,” Bond-Simpson said. “The first cycle of this is to create a strong foundation, understanding how additional programs above and beyond what we are currently doing might benefit customer value. But if you think about 2035, if we are relying on customer programs for a greater share of reliability and system needs, we need to understand those behaviors.”

Planning considerations

Xcel, SRP, and a handful of other utilities that have created dedicated planning teams are among the “early adopters” of this internal integration concept, Lyons said. But they aren’t the only utilities considering it. Lauren Shwisberg, carbon-free electricity principal at RMI, believes that a majority of major utilities have at least thought about integrating some of their internal planning teams.

“There’s still a lot of utilities that have not started to tackle this question,” she said. “If I had to draw an S curve of adoption, the line has started bending upward, but not to the tipping point where the majority of utilities have started integrated planning.”

Shwisberg believes all utilities will — or could — benefit from exploring more integrated planning teams. As the energy transition continues, she says, these teams will be a key tool to maintain affordable energy rates.

“We are coming to a point where if we don’t plan in an integrated fashion, we could find ourselves in a pathway that is significantly less affordable for customers,” she said. “We’re moving toward a future where information will need to flow across planning practices.”

But this doesn’t mean that integrated planning teams are a panacea, Shwisberg said. With just a handful of utilities still in the early stages of creating integrated teams, it’s still too early to say whether they’ll deliver the desired results for the companies that create them, Lyons said. And Shwisberg said she could envision some potential drawbacks — the perfect could become the enemy of the good within planning teams, with planners iterating the same plans over and over but taking far too long to come to a final conclusion on any one matter or question.

“The two risks are that you’re not going to meet all the different needs, or that you are creating a process that is quite unwieldy and therefore slow and unable to provide timely information,” Shwisberg said. “Those are the risks that an integrated planning department would have to manage.”

For most utilities, solving that particular problem might be a way off. So while the first generation of early integrated system planning adopters sort out the kinks, Shwisberg said other utilities can get the ball rolling by focusing on the first key questions — what benefits they hope to gain from integrated planning, and whether there are gaps in their current planning processes that an integrated team could fill.

“The purpose of planning is to accurately represent the cost, capabilities, impact and value of options that might be available in the timing horizon,” she said. “Striving toward a process or team that can do that is going to be really essential to moving as fast as we can while making investments that will result in an affordable electric system going forward.”

The energy transition’s new resources, technologies and voices require the utility integrated resource plan, or IRP, to be better, many planners and analysts say.

An IRP is the strategy a utility submits to its regulators every one to three years in most states for investing in reliable affordable power and meeting its policy goals and obligations. But new approaches, like those being explored by Arizona Public Service, or APS, and Duke Energy Indiana, are needed to meet upward pressures on rates, stakeholder calls for clean energy options and equity, and federal and state policies, many regulators and stakeholders agree.   

“Market forces are shaping utility resource portfolios,” acknowledged Commissioner Pat O’Connell of the New Mexico Public Regulation Commission. “But this moment of change is an opportunity to go big on high-level IRP reforms with more analysis of more factors,” he added.

For APS, “the changing landscape requires transparency with stakeholders in the IRP process,” said APS Vice President of Resource Management Justin Joiner. “That means coming to planning sessions with stakeholders without answers, because two heads are better than one, and decisions about affordability, reliability and clean energy can best be reached with diverse stakeholder viewpoints,” he added.

Reform efforts to introduce best practices like all-source solicitations, distribution system planning, and engaging new voices could add more work for already overburdened utility planners and regulators, some said. But developing integrated system planning with state-of-the-art modeling that optimizes solutions to today’s reliability and affordability challenges will be easier than undoing bad planning decisions, others responded.

A “reimagining” opportunity

Utility “planning processes are being stretched and challenged” to meet the power system’s emerging dynamics, according to a new report from independent analyst RMI. But utilities, regulators and stakeholders can “shape the future electricity system” by “reimagining” IRP “rules and guidelines,” to make planning more comprehensive, transparent, and aligned with policy, RMI said.

Through 2025, “utilities serving at least 40% of U.S. total electricity sales and over 90 million customers” will file IRPs with “over $300 billion” in proposed system investments, the report said. That is an opportunity “over the next 10 to 30 years” to integrate new operations, resources, and technologies to meet projected demands “at least cost, while mitigating risk and meeting policy objectives,” the report added.

The RMI report expands on and confirms a wide-ranging 2021 call by regulators from 15 states and Puerto Rico for planning “to evolve to meet new technologies, changing costs and stakeholder demand,” said National Association of Regulatory Utility Commissioners Senior Director, Center for Partnerships & Innovation, Danielle Sass Byrnett.

State policy “should be part of planning,” stakeholder engagement is “vital,” and utility regulators should “establish rules for the IRP at the outset of the planning process,” the Task Force on Comprehensive Electricity Planning report from members of NARUC and the National Association of State Energy Officials, or NASEO, said.

Proposals for improved planning will differ by state regulatory regime and state policy, the NARUC-NASEO paper said. They will also differ by the proposed reforms’ complexity, enforcement provisions, and requirements for stakeholder engagement, it added.

IRP reforms should move toward transparent utility data, thorough regulatory review, and greater stakeholder participation, the RMI paper said. Reforms must also align with traditional utility priorities like reliability, affordability, and safety while meeting new state and federal policies and customer calls for reduced emissions and increased equity, it added.

The burden that major IRP scope, rules, and participation reforms could add to already time and cost-constrained regulators and utilities is “the single biggest pushback to the paper,” RMI Principal, Carbon-free Electricity Practice, and paper co-author Lauren Shwisberg said. But “taking on that burden now can significantly reduce future planning burdens” like the complexities of sophisticated computer modeling, she added.

IRP reforms like new planning frameworks that include new technologies, resources, and improved stakeholder engagement have produced significant ratepayer savings and policy compliance, Shwisberg added.

Stakeholder input challenging the need of a natural gas plant in Xcel Energy’s 2016–2030 Upper Midwest Resource Plan led to Xcel’s revised 2020–2034 IRP, RMI said. The resulting lower-cost plan could save ratepayers $372 million over the planning period, it reported.

From 2016 to 2022, the Georgia Public Service Commission has developed a robust stakeholder ecosystem, “with nearly 20 parties engaged” in recent three-year planning cycles, RMI reported. Over that period, Georgia Power’s proposed natural gas additions dropped and its renewable resources had “a 200% increase,” the paper said.

“That is an example of how a commission can use leverage, if the IRP rules support it,” said Southern Renewable Energy Association Executive Director Simon Mahan. “The RMI report shows many ways good commissioners can develop new IRP rules that will create a legacy of protection for ratepayers that outlast them.”

“We are planning an electricity system with new and different needs, options and goals,” RMI’s Shwisberg said. “But almost half of utilities still are not required to do — or don't do — fully transparent, aligned and comprehensive planning, even though it will make the IRP process more useful to all participants, and this paper is a challenge to regulators and utilities to update planning,” she said.

Policymakers’ planning innovations

A few states have essentially no IRP requirement and others limit IRP requirements to some utilities, like those that are investor- or publicly-owned, RMI reported. In many of the states leading in innovations, like Minnesota, Washington, Colorado and South Carolina, regulators and legislators require IRPs from most or all electricity providers, it added.

State legislators can influence critical parts of planning rules like regulatory review and use of stakeholder input to approve, provisionally approve, or call for adjudication of a plan before accepting or rejecting it, RMI said. Even progressive commissions like those in Oregon and Washington use policy mandates as guidance, it observed.

Oregon’s House Bill 2021 requires that utility IRPs submitted to the commission provide a Clean Energy Plan for achieving the bill’s mandated clean energy and emissions reductions, said Oregon Public Utilities Commission Spokesperson Kandi Young. In response, Oregon regulators approved an order that provides “guidance for what’s to be included” in the utility plans, she added.

Washington state’s 2019 Clean Energy Transformation Act (Senate Bill 5116) similarly led to the ongoing guidance from Washington state regulators. New rules define compliance with 100% clean electricity and require it by SB 5116’s 2045 target date. They also guide implementation of requirements for affordability, reliability, equity, emissions reductions, and more transparent electricity markets.

“Planning has evolved,” and once hypothetical best practices conceived to avoid bad outcomes, like nuclear investments with severe cost overruns or time delays, now can put “all possible resources on a level playing field,” said Regulatory Assistance Project Senior Associate Elaine Prause, a former Oregon commission staffer and PacifiCorp senior planning manager.

“It probably is not possible to quantify the value of planning, but without a shared vision unwise investments are more likely,” Prause said. Having worked with Oregon’s commission and at PacifiCorp, “it is clear both utilities and regulators are facing change and need new processes to achieve those better outcomes,” she added.

“With new processes and stakeholders, things may take longer, but more and different perspectives allow the commission to build the best and most comprehensive record,” she said. That is not the same as paralysis of decision-making, because the best decision-making takes time and these new processes are necessary, Prause said.

“The utility owns the IRP, regulators and policymakers inform it,” and “affected stakeholders” must be engaged, said New Mexico Commissioner O’Connell. But current reliability and affordability planning scenarios in many utility planning processes “are too vague” and lack a specific “destination” like “being carbon-free by a certain date or always having sufficient capacity to enable economic development,” he said.

“One of the facts of the regulatory world is that all participants have limited resources, and planning reforms could add complexity," O’Connell recognized. “But today’s technologies make new things possible and that means there may not be a choice except to reimagine planning for those new possibilities,” he added.

More stakeholder input “can lead to conflicts when utility data does not support a stakeholder’s assumed outcomes,” O’Connell acknowledged. But the RMI report shows “this is a moment of big change that will require working hard to understand those challenges, even if it means doubling the number of people working on planning and tripling the computing power,” he added. 

Utilities and stakeholders in planning

Some utilities are working closely with policymakers and regulators to rethink planning.

Avista Utilities’ developed its IRP to comply with the Clean Energy Transformation Act and the commission’s implementation rules, and has found “the new rules set requirements that help facilitate the plan,” said Avista Spokesperson Mary Tyrie. Like Avista, Puget Sound Energy’s IRP is focused on implementing state policy “in the most efficient and equitable way possible,” said PSE spokesperson Andrew Padula.

But many utilities still pursue integrated resource planning independently and that has left some stakeholders dissatisfied with utility efforts to integrate clean energy and reduce fossil fuel dependence.

“Generally, it is still up to individual Southeastern utilities to follow IRP best practices and unfortunately many have not been cooperative partners,” said Southern Renewable Energy Association’s Mahan, who has worked in IRP processes across the region.

“Better rules can require utilities to adhere to their filed plans and allow commissions to order utilities to redo plans deficient in justifying information,” Mahan said. Reforms can also allow regulators to require utilities to issue competitive all-source solicitations “which essentially replaces modeling with a market test that shows exactly what the least cost resources are,” he added.

Conclusions in such reformed IRP processes do not guarantee their proposed resource investments in General Rate Cases will be approved, but can help, RMI said. Few states approve reimbursement for capital investments through rates based on IRPs, requiring instead that utilities show investments are reasonable and prudent in the rate case, it added.

A commission-endorsed IRP strategy built with greater stakeholder engagement that includes a more diversified resource mix “can give the utility some confidence in its proposed investments” when it goes to the rate case, said Duke Energy Vice President, Integrated System Planning, Mark Oliver.

Duke Energy Indiana avoided overbuilding natural gas generation and emissions growth by 2021 stakeholder-driven changes to its 2019 preferred resource portfolio that substituted solar and storage additions for natural gas plants, RMI reported. “Indiana stakeholders made their voices heard and influenced planning” and that kind of participation has allowed Duke to approach planning “in a broader and more integrated way,” Oliver said.

Federal and state policies are key planning factors, but “Duke has learned the value of customer-owned resources, storage, and transmission through scenarios run by its new Encompass modeling tool,” Oliver added.

“Most widely used modeling tools are not up to the new IRP complexities,” but Duke’s relatively new EnCompass tool “points in the right direction” by modeling the broadest portfolio of solutions,” said Strategen Consulting Director Erin Childs.

And there are ways to narrow the complexity of planning, Oliver said. “Go after demand-side opportunities for flexibility first, procure clean resources wherever possible, always protect reliability and affordability, and use an all-of-the-above approach to clean resource procurements to hedge against uncertainty and reduce risk, especially for beyond 2030,” he added.

Though not highlighted by RMI, Arizona has had “strong planning rules” since 2010 that have allowed its utilities to consider distributed energy resources, and air quality, report co-author Shwisberg said. Their stakeholder engagement “processes have become even more transparent over time,” she added.

“We continue to look for every opportunity to improve the IRP process,” added APS’s Joiner. The utility expanded its transparency by providing access to its Aurora modeling tool to several participants in its Resource Planning Advisory Council and “allow them to see and evaluate all our planning inputs and suggest changes or run their own hypotheticals,” he added.

Reviewing multiple modeling scenarios “is a significant time and staffing” commitment, but “it ensures the planning process is doing what it is intended to do,” Joiner, who previously worked in planning at Indiana and Illinois utilities, added.

“In the other states, the best efforts were used to find the best solutions, but too often decisions were made without stakeholder input, and did not produce dialogue and planning development,” Joiner said. “When stakeholders are engaged early and often and if planning begins without any assumed answers, the outcome is more likely to be transparent, trusted, and comprehensive,” he added.

The solar industry is about to have an escalating amount of defunct panels on its hands, and companies like Solarycle are positioning themselves to turn those panels into profit.

A study from the National Renewable Energy Laboratory in 2021 found that the total amount of defunct panels in the U.S. could reach 1 million metric tons in 2030 and 10 million metric tons by 2050.

Sensing that influx of materials, some recyclers are beginning to scale up their own solutions for panels that have reached the end of their useful life. One such startup is Solarycle, which received a $1.5 million U.S. Department of Energy grant this week to partner with NREL to explore ways to extract higher-quality materials from recycled solar panels.

That follows a $30 million series A funding round that closed last month, led by investors Fifth Wall and HG Ventures.

Suvi Sharma is Solarcycle’s CEO and a co-founder of the company, along with former Sierra Club National Program Director Jesse Simons and photovoltaic recycling expert Pablo Ribeiro Dias. Sharma recently spoke with Waste Dive about how the new funding will allow the company to double its capacity. He also said the solar industry is keen on finding paths to circularity, and he noted the public and private financing alike that’s backing companies willing to try.

The following interview has been edited for length and clarity.

WASTE DIVE: Let's start with your investment. You recently received a series A investment round totaling $30 million that was led by Fifth Wall and HG Ventures. Tell me what that investment will enable Solarcycle to do.

SUVI SHARMA: There's two key things that it will enable us to do. One is scale up our recycling operations — we've set up our first facility in Odessa, Texas, that's a very advanced solar recycling facility. We have a lot of R&D that's gone into that: new equipment, technology. Right now we have a capacity to be able to recycle 500,000 solar panels there and we're going to double that to a million panels per year, and also investing in some further downstream metal separation processing equipment and technologies there.

[The series A funding] allows us to expand and vertically integrate the entire soup-to-nuts recycling and extraction process for solar panels, and then also gives us capital as we need to expand additional facilities on an as-needed basis as the market for recycling solar panels expands. 

Thing two is it enables us to double down and triple down on R&D. We are very focused on not only scaling recycling for solar, but developing the advanced technologies and processes and equipments that are needed to have a very cost-effective and a very efficient recycling process for the increasing number of solar products that need to be recycled.

So we're investing more in R&D, and that ranges from higher-throughput recycling and extraction processes to also starting to invest in some remanufacturing technologies. Not only are we extracting the materials out of the solar panel, but we are also purifying and remanufacturing some new materials from those so we enter those back into the solar supply chain.

How much of your end product is sold back to solar panel manufacturers at present?

Today it's zero, because what we do is we extract the raw materials. The solar panel manufacturers, what they do is they buy finished materials such as specialized solar glass or specialized frames. Today we supply into the raw material market, and then those materials get remanufactured into a final product that could go into the solar industry. 

But as we evolve, we will be remanufacturing some of those products ourselves, and that will enable us then to supply those finished materials and products directly back to the solar panel manufacturers and the solar supply chain.

What's the motivation behind investing in that remanufacturing process? 

Well, there's really two distinct benefits or rationales for it. The first is, as a company and for Solarcycle, we can build a more valuable and larger business. The recycling and extraction process is one value piece of the equation, but there's a lot more value as we can convert those raw materials into finished products. As you can probably imagine, as you start to add value to the materials and make finished products, there's just more value that we can get — more revenue, more margins and so on. 

Rationale number two is that it's really the right thing to do. What I mean by that is the solar materials that we're getting and extracting, they're highly specialized solar materials. For example, the glass solar panels, depending on the type of panel it is, by weight or mass is 70% to 90% glass. That glass is highly specialized, and when we extract that glass and sell it back into the glass recycling market, it just ends up getting used for making bottles, for example. That is a waste of a very particular high-quality glass, so the right thing to do from an environmental standpoint, and just a supply chain standpoint, is to remanufacture those materials into finished products.

The reality that we fit in today is the infrastructure for remanufacturing those just doesn't exist in the United States. All of it is done overseas. So as we start to build a domestic solar industry here again with solar panel manufacturing, we need to make these products here domestically, because currently they're all being imported from Asia.

Your co-founder, Jesse Simons, had previously said that you would be able to sell back glass to new solar panel manufacturers once you reach an appropriate volume. How far are you from achieving the volume?

If we talk about using 100% glass that we get to make, we are realistically anywhere between three to five years — and probably closer to five years — away, because of the scale and size you need for running an efficient glass factory. But if we blend and make blended glass, meaning using recycled feedstock that we're getting with some virgin materials, we are only a couple years away from being able to do that in meaningful volumes.

So is the plan that you're going to use blended glass? 

To start with, yes, and then over time increase that toward that 100% recycled goal. Typically, for running a basic glass factory you need about 200 tons per day for 100% recycled as the baseline. We're just starting and ramping up our volumes right now, but in the next 12 months we will be getting approximately a third of that.

You charge about $18 per panel for recycling. A study from the National Renewable Energy Laboratory found that anecdotally, recycling solar panels costs anywhere from $15 to $45. How are you keeping costs at the low end of that scale?

Just to be clear, that $18 on average we charge, that includes our freight costs. We charge a single price to the customer, and we handle all the freight and logistics. The way that we are able to [keep prices low] is really twofold.

The first is, the traditional way that people “recycle” solar panels is they're using standard e-waste or electronics recycling equipment and putting solar panels through there. That is a very expensive thing to do, and very non-optimal, because solar panels are big. If you think about a solar panel versus a cell phone that's going through those shredders and the machines and all of that, it's very expensive.

We've designed a very unique set of recycling lines that's optimized and cost-optimized for specifically just solar panels, so it allows us to achieve a level of cost efficiency through that process. As part of that, it's a volume game. The more volumes we can get, the lower the cost of the recycling. We're running only solar panels through and nothing else, so it allows us to achieve an economy of scale that reduces costs.

Thing two is, we're getting way more value out of the panel than any traditional recycler that's doing it today that NREL is looking at. Those recyclers are not extracting and getting any value from the glass, they're not getting the metals out, like silver, because those are challenging to get. That's what our technology does. So we're able to extract more value and get more value in the marketplace so we don't have to charge as much for that takeback handling fee.

Your prices can still be higher than just landfilling a panel. Are you concerned that could exclude you from competing in the market?

What we are working on is that you will not see us charging that same takeback fee five years from now. Our plan, and what we've communicated to customers, is we will be reducing that. The way we will be reducing that is doing two things. One is, obviously, just getting costs down through engineering and scale. And second is getting more and more value extracted out of the panels so we can keep reducing that takeback fee.

Our goal is over the next decade, as these volumes grow, we will be at or near the cost of landfilling. Most of our customers, who are these big solar asset owners, they recognize that today they are paying a premium to recycle with us versus landfilling. But if they work with us and give us the volumes, that's going to allow us to lower the cost.

By the time there are larger volumes of panels, where they're decommissioning and repowering old solar power plants, we will have a very cost-effective recycling process that can compete with landfilling costs, which are only going to go up over the next decade.

A strategy that has succeeded in increasing solar panel recycling rates in Europe, per NREL’s 2021 report, is extended producer responsibility laws. Would you support EPR legislation at the state or federal level for solar panels in the U.S.?

Generally we don't, and a lot of people are surprised by that. As a recycling company, you would think we would want EPR that would force recycling. I think there could be a place and time for it; I don't think now is the time and place for it.

Because what happened in Europe is, if you look at the details of it, all that's required is you need to recycle 85% by weight of the panel. In order to comply with the EU regulation, you have to basically strip off the aluminum frame, which is relatively easy to recycle, and you can strip off some copper cables, and you can shred and crush the rest and use it for asphalt filler. That's what recycling in Europe today is. It's low-value recycling, and because it started that way and the pricing of recycling was set that way and because you can comply, it has killed all innovation.

Today, Solarcycle is a one-year-and-three-month-old company, and we're doing way more advanced recycling for solar than anywhere in Europe today. [EPR] stifles innovation, so it became a victim of its own success. Over time, it is important to recycle these panels. There may need to be laws that come in over the next few years. But we're actually working with the industry, with the asset owners, with the manufacturers to do it in a way that can promote advanced recycling, as opposed to low-value recycling, which oftentimes happens in the EPR situation.

There's a lot of funding for the solar industry coming from some of the big climate bills that we've seen of late, including the Inflation Reduction Act most recently. Do those laws present any opportunity for the work that you do and for solar panel recycling in general?

Absolutely, there are some direct benefits that we're getting. In fact, the Department of Energy just announced some R&D grants, of which we were one of the recipients — about $1.5 million to further develop our recycling technology. There are also tax credits for manufacturing and recycling in the bill, which we will be able to take advantage of to reduce some of the costs of recycling and remanufacturing the materials, because those can get capital intensive.

The real big strategic move in that is the incentives they have for domestic manufacturing of solar cells and solar panels. That's accelerating and spurring a solar manufacturing industry and ecosystem in the United States. That ecosystem is going to need materials, and it's going to need glass and aluminum frames, so the materials that we're getting from the recycling process become more and more valuable and pertinent for that scale-up in infrastructure and domestic manufacturing. It really sets a great stage for these materials and putting them back into the supply chain here in the U.S.

Nearly 30% of utilities responding to a survey said they have increased their carbon-free energy supply by 10 percentage points or more from 2018 to 2021, with most companies reporting they’ve expanded emissions reduction targets, according to a recent industry report.

The Smart Electric Power Alliance’s “2023 Utility Transformation Profile” said 66% of utilities that responded reported an increase in carbon-free retail supply since 2018. No change in carbon-free supply was reported by 19% of respondents and 18% said they’re supplying less carbon-free energy.

“The utility industry’s transition to carbon-free energy is uneven,” the report said.

SEPA said 63 utilities, representing about one-third of electric customers in 29 states, completed the survey. When including partially completed surveys, the number rose to 118, representing 51% of electric customers in 41 states. Most of the 118 utilities are investor-owned, with public power utilities and distribution cooperatives also participating.

Utilities have set different carbon-reduction targets that include net-zero, carbon-neutral, carbon-free, greenhouse gas-free and relative emissions reduction. The target type indicates what a utility will do to decarbonize. For example, a 100% renewable energy target does not include nuclear energy and a net-zero target will use offsetting, such as carbon sequestration or carbon credit trading, the report said.

The study said 62% of respondents have developed a publicly available action plan to support a carbon-reduction target and 65% have incorporated at least one interim target in their goals.

In addition, three-quarters of U.S. electric customer accounts are served by a utility with a 100% carbon reduction target or by a utility owned by a parent company that has set that target.

But just 59% of respondents have established a plan to facilitate electric vehicle deployment, according to the report. 

Utilities are assessing the impact of climate change on their operations, adapting to a changing climate to minimize harmful effects and developing climate-resilience strategies to specify investment needs, according to the study.

Many elements of the energy transition “put upward pressure on rates,” the report said. With sharply higher costs for energy, utilities can provide affordable energy by using a combination of short-term bill assistance and management programs that are offered by 87% of utilities participating in the survey, the report said.

In addition, 64% of utilities in the survey offer energy-efficiency programs.

To reach an “equitable, carbon-free energy system” utilities must assess and promote equity in planning for the transition. However, 58% of respondents said they have not assessed energy equity as part of generation, transmission or distribution planning.

Utilities also report interconnection and transmission bottlenecks on new renewable energy projects. As more renewable and storage systems are interconnected, the U.S. will need to double or triple transmission capacity to accommodate those resources and provide 100% clean electricity by 2035, the report said.

To help reach that goal, the Inflation Reduction Act will provide nearly $3 billion in federal funding for transmission projects.

The clean energy industry is booming, but the labor supply remains low. Partnering with community colleges to offer pathways to employment could help the industry meet its increasing demand for workers, said a workforce development official with the Foundation for California Community Colleges. He was speaking at a workforce development session at Intersolar North America on Feb. 14.

Community colleges are a source of “untapped talent” and are “built to be nimble” in a way that other sources of higher education may not be, Tim Aldinger, executive director of workforce development for the FCCC, said at the event.

“For the last year and a half, we've had more jobs posted than people looking for them. And we are also in a decade-long process where people [nationwide] are opting out of the labor market,” Aldinger said. “And this is particularly prevalent, actually, among working-age men, particularly in jobs that were called ‘blue-collar’ work.”

Though the renewable energy sector has become a significant generator of new jobs, and the Inflation Reduction Act bolstered this growth with tax credits that incentivized new projects and registered apprenticeship programs, the wind energy industry reported difficulty finding qualified applicants in a November report.

A pair of studies from the National Renewable Energy Laboratory said that 68% of wind energy employers had faced “some or great difficulty” finding qualified applicants, while 83% of the potential wind energy workforce has had “some or great difficulty” finding job opportunities.

When asked in an interview if renewable energy industries will have to adjust their approach to recruitment and hiring to meet labor demands at a time of falling participation in the workforce, Aldinger said that seems likely.

“I do think that probably every institutional group has to look in the mirror and make some changes, and I think that includes industry,” he said. “Another aspect is, how do these careers become places that people want to work? Wage is part of it, but is it a place you feel comfortable in? Is there a worker voice? Is there reliable scheduling? All those pieces have to get chipped away at.”

There aren’t enough registered apprentices on the market to meet the demands of renewable energy developers who need to hire a certain number of them to take advantage of certain tax incentives in the IRA, Bernice Diaz, a labor and employment attorney with Sheppard, Mullin, Richter & Hampton, said during the session.

“There will likely be a shortage of apprentices, especially if this generation continues to steer away from skilled trade jobs,” she said. “While the IRA created a surge of demand for apprenticeship, I think it did little to really address [the shortage].”

It’s unclear whether the Department of Labor will be able to “keep up with” approving registered apprenticeship programs for the occupations that need them, including for energy projects in the geographical areas where they’re needed, Diaz said.

Community colleges can help fill several gaps in the labor market, Aldinger said, by providing specialized training programs, embedding larger shifts in the industry into their curriculums, and helping industry receive funding that is earmarked for companies that partner with community colleges or public workforce agencies.

“If you're a business, generally speaking, a workforce board or community college is going to be very excited to talk with you,” he said. “They want to have a place to get strategic directions, understand where the market is going, understand what your needs are, and also have a place for students to go and learn and potentially become employees.”

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

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

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

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

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

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

Paths to 100%

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

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

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

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

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

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

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

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

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

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

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

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

Molecules or electrons?

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

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

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

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

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

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

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

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

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

Planning for land

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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