Battery Storage’s Next Bottleneck Is Market Design

Battery storage is no longer a speculative answer to renewable intermittency. Robinson Meyer cited a projection that the United States would add 24 gigawatts of battery capacity in 2026, second only to roughly 40 gigawatts of solar. A decade earlier, storage was still largely a future solution: solar and wind were becoming cheaper, but batteries had not yet become a consequential part of power-system planning.

The constraint now is less basic technical viability than whether market and regulatory systems pay batteries for the services they provide: shifting electricity through time, providing capacity when the system is tight, relieving congestion, and making more use of existing grid infrastructure.

Jack Godshall said Jupiter Power, a wholesale developer, owner, and operator of storage projects, monitors roughly three million cells daily. Its systems charge from the grid, often during low-price hours when wind and solar generation is abundant, and discharge during higher-price periods, when thermal generation is more likely to be setting the marginal price. That pattern often means batteries absorb cheap, clean electricity and displace fossil generation at more constrained hours, Godshall said.

The operating decisions are made at short intervals. Jupiter uses forecasts of weather and expected price patterns to decide, in five-minute increments, whether to charge or discharge. Storage is therefore not simply an asset that holds renewable generation for later; it is an actively managed commercial and reliability resource inside a power market.

? chibueze-amanchukwu described why the technology is especially useful for the grid. Electricity has historically been generated and consumed essentially at the same moment. Batteries make it possible to store power for later use. They are also modular: adding units can increase capacity without requiring the particular geography needed for hydroelectric storage, such as a suitable body of water and elevation difference.

That modularity can also help a transmission-constrained grid. Meyer asked whether developers could place batteries near constrained transmission lines, charge them when demand is lower, and discharge them when the line would otherwise be heavily used. Godshall said Jupiter is doing that, though the commercial arrangement depends on the local market and customer. Storage, he said, is key to increasing the utilization of existing wires.

Godshall’s central policy argument was that falling capital costs make market reform more important, not less. Storage needs compensation for its full value to the system, he said. Energy-arbitrage revenues alone do not necessarily capture contributions to capacity, congestion management, and reliability. Whether those contributions can support a project depends heavily on jurisdiction-specific rules.

The gap between what batteries can do and what markets pay for was most concrete in the exchange about PJM, the regional electricity market serving 13 states and the District of Columbia.

Godshall pointed to PJM’s capacity-accreditation rules. Capacity means being available when the grid needs power, such as during extreme heat. Under the approach discussed onstage as ELCC, a storage project must provide 10 hours of duration to receive the full capacity payment.

Most batteries being deployed today are shorter-duration assets: commonly two, four, six, or eight hours, rather than 10. A battery can be valuable during periods of system stress and still receive less capacity revenue because it cannot meet the duration threshold for full payment.

Amanchukwu said lithium-ion systems can provide longer durations by adding more batteries. The limit is increasingly economic rather than a fixed engineering boundary: if cells are cheap enough, developers can stack enough of them to provide 10 hours or more. But a 10-hour requirement changes project cost and may not match the way storage is otherwise being deployed.

Kelly Speakes-Backman tied that market problem to the way states classify storage. In deregulated states, utilities generally cannot own generation. If a battery is treated as generation rather than as a grid asset, a utility may be unable to own or invest in storage even when it would help manage a distribution system. Where regulators have not addressed that distinction, she said, utilities have less reason to support storage interconnection or deployment.

Maryland is trying to create several paths for deployment. Speakes-Backman said the state’s Utility Relief Act included $100 million for grants and funding for Tier 1 resources—solar, wind, other non-emitting resources, and storage. Storage does not need to be paired with a clean-energy resource to qualify. The state also has a Public Service Commission procurement program with utility targets, alongside a statewide goal of 3,000 megawatts of energy storage by 2033.

Maryland imports about 40% of its energy, Speakes-Backman said, which makes extracting more value from each megawatt-hour especially important. Storage supports reliability and resilience, helps address capacity constraints on transmission and distribution systems, and can ultimately lower costs for consumers, she argued.

California was cited as a state doing well on storage. Godshall also named Maryland, Massachusetts, Illinois, Colorado, and California as states where leadership has helped bring regulation closer to what the technology can do. But he described the national picture as a patchwork of jurisdictions and rules.

Texas offers a different model. Speakes-Backman described it as effective at “being Texas”: high risk, with potentially higher rewards. Its energy-only market creates opportunities for operators to buy low and sell high. Godshall argued that open competition is itself a central policy tool. Rather than prescribing a preferred technology, markets should allow storage and other resources to compete.

State targets, grants, and procurement offer one route to deployment; Godshall emphasized market openness and compensation for services. Both approaches rest on the same premise: falling battery costs alone will not determine deployment if the market does not recognize the resource being sold.

Lithium-ion dominates today’s electric-vehicle and grid-storage markets, but it is not one uniform technology.

Amanchukwu said foundational lithium-ion research dates to the mid-1970s, when one of the eventual Nobel Prize winners was working at Exxon. Sony commercialized the first product in 1991, roughly two decades later. The batteries being deployed today reflect further changes in materials and manufacturing since that first commercialization.

Within the lithium-ion family, different cathode chemistries make different tradeoffs. Lithium iron phosphate, or LFP, is a lower-cost version of lithium-ion. Nickel manganese cobalt, or NMC, and nickel cobalt aluminum, or NCA, have different cost and performance profiles.

Tesla illustrates the segmentation already taking place within lithium-ion, Amanchukwu said. Its Model S and Model X use more expensive NMC- or NCA-based batteries, while the Model 3 uses LFP as a lower-cost product. Different applications can select a chemistry based on cost, performance, and material requirements rather than relying on a single universal battery.

For stationary storage, lithium-ion’s industrial scale is a formidable advantage. Godshall said Jupiter’s current projects use LFP, which he described as having a good cost profile, abundant supply, and no conflict materials. In Jupiter’s early years, storage developers sought small allocations from manufacturing lines built primarily for Tesla and other electric-vehicle makers. In some cases, he said, the relationship has begun to reverse, with automotive manufacturers converting manufacturing toward stationary storage.

Godshall compared the trajectory to solar photovoltaics. A decade or more ago, solar thermal and other approaches had promising applications. Solar PV reached scale, however, and continued to improve. Lithium-ion may benefit from the same dynamic: deployment brings manufacturing volume and incremental improvement before a competing technology reaches commercial scale.

Battery costs are still trending downward, Godshall said, even if tariffs, trade policy, and domestic-manufacturing requirements make reported figures bumpier. Storage remains commercially competitive in most of the places where Jupiter operates.

That success raises the bar for technologies built specifically for long-duration storage. If low-cost lithium-ion cells can simply be added to provide more hours of output, alternative chemistries must beat a moving target. Amanchukwu noted the tension for researchers: lower prices expand grid applications, but commodity-level pricing can reduce margins and the appetite for new technologies.

Amanchukwu’s research group works on next-generation batteries made from earth-abundant materials. The objective is to lower cost and improve safety without sacrificing too much energy density—the amount of energy a battery can store.

The principal alternative raised was sodium-ion. Sodium-based batteries may have a lower material-cost floor than lithium-based systems, Amanchukwu said. Depending on the chemistry, a battery’s materials can include lithium, nickel, and cobalt, creating cost and supply-chain concerns.

Safety is the other major driver. Current lithium-ion batteries can still present significant fire hazards in both grid installations and electric vehicles. Amanchukwu’s research asks whether batteries can be made intrinsically safer, reducing the underlying hazard rather than relying only on external systems to manage it.

Cost is also a question of access, Amanchukwu argued. Born and raised in Nigeria, he put the issue in personal terms: would someone in Nigeria be able to afford a battery built from more expensive materials? Earth-abundant chemistries could make battery technology accessible in markets that cannot support the cost structure of today’s higher-density products.

He expects a more diversified battery landscape rather than an outright winner-take-all outcome. India is investing heavily in sodium-ion batteries, he said, and vehicles there could become more sodium-ion dependent. As newer battery chemistries emerge around locally available resources, different regions and vehicle categories may settle on different battery systems.

His group has used AI and machine learning for roughly six years to accelerate materials discovery. The aim is to shorten the path from a laboratory idea to a deployable product. Lithium-ion’s progression from mid-1970s research to Sony’s first commercial product in 1991 shows why that matters. Better computation does not eliminate manufacturing and commercialization challenges, but it could reduce the time needed to identify promising materials.

Battery supply chains are an industrial-policy issue, but they are also a national-security issue.

Lindsey Griffith asked whether batteries’ roles in drones and military technology, particularly in light of the war in Ukraine, could strengthen the political case for manufacturing and research investment. Amanchukwu said dependence on a potential adversary for battery supply would create a serious disadvantage in a conflict.

That is one rationale for investment in earth-abundant materials. The United States has some of the world’s largest soda-ash reserves, Amanchukwu said, raising the strategic question of whether the country could lead a domestic sodium-ion ecosystem. He described continued Department of Energy and Department of Defense support for next-generation materials as important.

Large stationary systems create a security concern of their own. A megawatt-scale battery installation can become a target, Amanchukwu said; an adversary could attack the battery system directly rather than individual soldiers or devices.

Godshall described domestic manufacturing as real and expanding. Federal manufacturing tax credits have helped, he said, and Jupiter has used supply agreements intended to bring manufacturing to the United States. He expected domestically manufactured equipment to be operating within the following 12 months.

But China’s manufacturing and logistics scale remains difficult to match. Building a domestic industry requires more than final assembly: the whole supply chain has to work together at sufficient scale. Godshall supported domestic manufacturing and the jobs that come with it, particularly in the Midwest, but argued that protectionism alone is unlikely to achieve the desired result.

Trade barriers can raise final costs for consumers, he said. That matters as electricity-demand forecasts rise and affordability becomes politically decisive. The recent expansion of data-center demand has intensified attention to the cost of new capacity and how quickly it can be deployed.

Godshall resisted the idea that data centers caused the storage boom. Storage was expanding before the recent data-center buildout, he said, because the grid already needed capacity, reliability, and affordable power while battery costs were falling. Data centers have added urgency over the past 18 to 24 months. They have also increased the value of a resource that can be deployed quickly: where capacity is needed fast, Godshall said, storage can be built faster than thermal generation.

The same modularity that makes batteries useful at power-plant scale makes them candidates for distributed deployment. Home batteries, office systems, electric vehicles, and other devices can potentially be aggregated into virtual power plants, creating a coordinated resource during periods of high demand.

Godshall said storage is “eminently distributed,” even though Jupiter operates predominantly in wholesale markets. The opportunity extends to homes, offices, and vehicles. But regulation has lagged the technology, he said: simply creating a virtual-power-plant concept has taken years.

Speakes-Backman tied the opportunity to FERC Order 2222, intended to enable aggregated distributed energy resources to participate in wholesale markets. Aggregation is the key step. A single household battery is small; a managed fleet can offer capacity at a meaningful scale.

Maryland is working to aggregate existing distributed energy resources, add storage to those fleets, and ensure that new projects can participate later. Speakes-Backman said distributed-energy projects receiving grants from the Maryland Energy Administration should be at least “VPP ready.” The state sees potential for virtual power plants to help offset peak demand associated with data centers in its region.

The assets may already be installed, but participation requires more than ownership. Existing systems need additional hardware, controls, and program support to become usable in a virtual power plant, Speakes-Backman said. That costs money, and Maryland is considering how its programs can help build that readiness.

Whether virtual power plants can offset data-center demand at gigawatt scale remains unresolved. Speakes-Backman said the distributed resources exist, but their readiness to operate in coordinated programs is not assured.

A battery system does not end when its first owner is finished with it. Amanchukwu estimated that less than 10% of batteries are being recycled today. One possible path is a second life: a battery that no longer meets an electric vehicle’s performance requirements could still be useful in stationary storage.

The obstacle is knowing with confidence how much useful life remains. Second-life deployment requires software and hardware that can predict battery performance. After that, recycling remains both a technical and economic problem. Recyclers can recover valuable materials such as nickel, manganese, and cobalt, but the economics are less obvious for lower-cost LFP batteries that lack the same mix of high-value materials.

Amanchukwu said companies and researchers are considering models in which customers pay an amount at purchase that supports eventual recycling. The technical objective is to recover materials including lithium, nickel, manganese, and cobalt while keeping batteries in productive second or third uses for as long as possible.

The labor requirement is another operating constraint. Tony Henderson raised the financing consequence directly: battery systems need trained technicians for installation, repair, and maintenance. If required maintenance is not performed, warranties can be voided; if warranties fail, the capital structure behind a project can be impaired.

Godshall called skilled labor, especially workers with electrical experience, a critical need across the energy industry. He pointed to job training, university partnerships, community-college programs, and local apprenticeships as ways to build a workforce pipeline. Domestic manufacturing can add jobs, he said, but the workforce problem remains unsolved.

Speakes-Backman said the issue has been developing for decades as the utility workforce ages. The scale of expected electricity-system growth makes it more acute. She noted that the Biden-Harris administration had supported workforce-development programs through the Department of Energy, though she was uncertain about their current status and redesign.