Large scale battery energy storage systems do scale effectively across three critical dimensions: physical capacity, economic viability, and deployment speed. The industry has demonstrated this through rapid cost reductions-dropping 89% from 2010 to 2023-and an explosion in project sizes, with individual installations now reaching multi-gigawatt capacity. Global deployment of large scale battery energy storage systems grew 35% in 2025 alone, adding 94 GW of new capacity.
The Scalability Evidence: Three Dimensions of Growth
Large scale battery energy storage systems aren't scaling in just one way-they're expanding across multiple vectors simultaneously. Understanding this requires looking at physical capacity growth, cost economics, and operational capabilities as distinct but interconnected dimensions.
Physical capacity has scaled dramatically. A decade ago, a 40 MW battery project was considered large. Today, BYD is deploying a 12.5 GWh system across five sites in Saudi Arabia, while the Edwards & Sanborn facility in California operates 3,287 MWh of storage paired with 875 MW of solar generation. These aren't experimental prototypes-they're operational commercial facilities delivering grid services daily.
The United States added 10.4 GW of battery storage capacity in 2024, representing a 66% increase over the previous year. More significantly, developers have 19.6 GW scheduled for 2025, suggesting acceleration rather than plateau. California alone operates over 12.5 GW of installed capacity, while Texas follows with 8 GW. These concentrations demonstrate that grid-scale battery storage has moved beyond pilot programs into core infrastructure.
Economic scalability tells an equally compelling story. Lithium-ion battery costs plummeted from approximately $1,200 per kilowatt-hour in 2010 to between $137 and $150 per kWh by 2023-an 89% reduction. This follows a consistent pattern: costs halve every 4.1 years. Multiple forecasts project costs falling below $100 per kWh by 2025, crossing a threshold that makes storage economically competitive with traditional peaking power plants for many applications.
This cost reduction stems from classic economies of scale amplified by cross-sector synergies. The electric vehicle revolution drove massive investment in lithium-ion manufacturing capacity-from 242 GWh globally in 2020 to 822 GWh in 2024, with projections reaching 2,731 GWh by 2030. Stationary storage piggybacks on these EV-driven manufacturing advances, benefiting from production efficiencies it didn't have to finance directly.
How Economies of Scale Drive Battery Storage Growth
The economic transformation of battery storage represents one of energy technology's fastest cost declines. Between 2015 and 2018, utility-scale battery costs dropped 70%. From 2014 to 2024, the cost halving time averaged just 4.1 years. For context, solar PV took decades to achieve similar percentage reductions.
Manufacturing scale drives the primary cost reduction mechanism. When Contemporary Amperex Technology (CATL), BYD, and other major manufacturers build gigafactories, they spread fixed costs across massive production volumes. A factory producing 50 GWh annually achieves per-unit costs that would be impossible at 5 GWh scale. This effect compounds as multiple manufacturers compete globally, each racing to achieve greater efficiency.
The shift toward lithium iron phosphate (LFP) chemistry accelerates cost reductions. LFP batteries eliminate expensive cobalt and nickel, using abundant iron and phosphate instead. While slightly less energy-dense than nickel-manganese-cobalt (NMC) chemistries, LFP's lower material costs, longer cycle life, and superior safety characteristics make it ideal for stationary storage where weight matters less than in vehicles. LFP's market share in energy storage has risen to dominate the sector, with Chinese manufacturers leveraging their specialization in this chemistry.
Installation costs beyond the battery cells have also declined significantly. Balance-of-system costs-including power electronics, integration, and installation-comprised roughly 60% of total system costs in early deployments. Standardization and increased competition have driven these down. Tesla's Megapack ships fully assembled, reducing installation complexity and timelines. Each unit stores over 3.9 MWh and can be installed in weeks rather than months.
However, economic scalability faces headwinds. Lithium prices spiked in 2022 before declining sharply through 2024, creating volatility in input costs. Some recyclers struggled as falling lithium prices made recycled materials temporarily uncompetitive with mined supply. The broader commodity cycle for battery materials-lithium, nickel, cobalt-introduces uncertainty that pure manufacturing scale cannot eliminate.
Physical Scaling: From Megawatts to Gigawatts
Battery installations have grown from residential backup systems to grid-scale power plants. This physical scaling occurs in two distinct patterns: individual project size and aggregate capacity.
Individual project scale has expanded rapidly. The Gambit Energy Storage Park in Texas operates 81 units providing 100 MW of capacity. Homer Electric's installation in Alaska delivers 46 MW. These represent standard commercial deployments, not exceptional projects. The largest operational single-site system, Edwards & Sanborn in California, combines 3,287 MWh of battery storage with solar generation, providing firm capacity that supplements variable solar output.
Under construction projects push boundaries further. Grenergy's Oasis de Atacama project in Chile will provide 11 GWh of storage capacity when completed. Sungrow's deployment across three Saudi Arabian sites will total 7.8 GWh. In Germany, ADS-TEC Energy announced plans for a 2 GWh facility-among Europe's largest-expected to generate €230 million in annual revenue through energy arbitrage and grid services.
Project developers achieve scale through modular design. Battery systems consist of shipping-container-sized units that can be deployed individually or in vast arrays. A 1 GW installation simply requires more containers, not fundamentally different technology. This modularity enables projects to start small and expand as financing and demand permit, reducing initial risk.
Geographic concentration reveals infrastructure dependencies. Texas leads planned battery capacity with approximately 60 GW in development, far exceeding California's 35 GW pipeline. This concentration reflects Texas's deregulated energy market, abundant renewable resources, and grid architecture that rewards fast-responding storage. Arizona, Nevada, and Oregon also host significant planned capacity, clustering where solar resources are strongest and electricity prices show high daily variation.
Yet physical scaling encounters real constraints. Siting large battery installations near urban load centers faces land availability and permitting challenges. Grid interconnection queues create bottlenecks-many proposed projects wait years for utility approval to connect. Transmission infrastructure built for centralized fossil generation doesn't always accommodate distributed storage optimally. Developers report that required grid upgrades sometimes make projects economically unviable, even when the battery system itself pencils out.
Duration and Discharge: The Scaling Challenge That Remains
Most utility-scale battery systems provide 2 to 4 hours of discharge at their rated power capacity. A 200 MW system with 800 MWh storage can deliver 200 MW for four hours before depleting. This characteristic shapes storage's role in the grid and represents the dimension where scaling faces the most significant technical barriers.
Four-hour duration suits many grid applications perfectly. Batteries excel at "peak shaving"-storing cheap overnight or midday solar power and discharging during evening demand peaks. They provide frequency regulation in milliseconds, far faster than gas turbines. They offer black start capability for grid restoration. These services generate substantial revenue with existing technology.
However, longer-duration storage remains challenging. Renewable energy advocates envision batteries replacing fossil fuel power plants entirely, providing multi-day backup during wind and solar lulls. Current lithium-ion economics don't support this use case. Each additional hour of storage requires more battery cells, linearly increasing costs. An 8-hour system costs roughly twice as much as a 4-hour system of the same power rating, but generates revenue from that extra capacity only occasionally.
Long-duration energy storage (LDES) requires different technologies. Vanadium redox flow batteries store energy in liquid electrolytes in external tanks, decoupling power and energy capacity. Rongke Power's 175 MW/700 MWh flow battery in China, operational in late 2024, represents the largest non-lithium battery storage system. Flow batteries' independently scalable duration makes them promising for extended storage, though their lower energy density and higher upfront costs limit near-term deployment.
Emerging chemistries target the duration gap. Iron-air batteries promise ultra-low costs for multi-day storage using abundant materials, though they remain in pilot stages. Sodium-ion batteries offer cheaper alternatives to lithium-ion with similar performance, though manufacturer enthusiasm has cooled as LFP prices continue declining. Solid-state batteries could eventually provide higher energy densities, but manufacturing complexity keeps them expensive.
The duration constraint shapes market structure. Research suggests that grids with less than 40% variable renewable penetration need only short-duration storage. At 80% renewables, medium-duration storage becomes essential. Beyond 90%, long-duration storage proves critical. Most grids remain well below these thresholds, meaning current 2-4 hour systems serve existing needs adequately while longer-duration technologies mature.
Safety at Scale: Managing Thermal Runaway Risk
Battery safety represents the non-cost challenge most likely to constrain scaling of large scale battery energy storage systems. Large-scale lithium-ion installations concentrate enormous energy in confined spaces, and failures can cascade catastrophically. Fire incidents in Arizona, Beijing, and South Korea have caused fatalities and forced temporary shutdowns of hundreds of systems.
The probability of an individual battery cell failing under normal operation is approximately one in ten million. However, thermal runaway in one cell can trigger adjacent cells in a cascading failure. With millions of cells in a large installation, overall system failure probability becomes more significant. South Korea experienced 28 energy storage fires between 2017 and 2019, leading regulators to shut down 522 installations-35% of all systems-pending investigation.
Battery manufacturers and operators have responded with multiple safety layers. Modern systems employ advanced battery management systems that monitor each cell's voltage, current, and temperature in real-time, isolating problematic cells before failure propagates. Physical barriers between battery modules contain potential fires. Sophisticated fire suppression systems-often using inert gases rather than water-activate automatically when sensors detect thermal anomalies.
The shift toward LFP chemistry improves inherent safety. LFP batteries exhibit significantly greater thermal stability than nickel-based alternatives, making thermal runaway less likely and less severe when it occurs. LFP's lower energy density disadvantage matters little for stationary storage, making it the dominant chemistry for new utility-scale projects.
Regulatory evolution reflects growing operational experience. Fire codes increasingly specify spacing requirements, suppression system standards, and monitoring capabilities for battery installations. Jurisdictions with substantial storage deployment, including California and Texas, have developed detailed safety protocols based on incident investigations and engineering studies. Insurance markets have matured, with specialized underwriters developing risk models for battery storage that enable competitive premiums for well-designed systems.
Yet safety concerns appropriately limit deployment density in populated areas. A gigawatt-hour storage facility requires significant buffer zones from residential neighborhoods and critical infrastructure. This spatial requirement conflicts with the grid's need for storage near urban load centers. Some optimal locations from a grid perspective prove impractical from a safety and siting perspective.
Supply Chains and Material Availability
Scaling large scale battery energy storage systems to terawatt-hour levels tests global supply chains for critical minerals. Lithium, nickel, cobalt, and manganese face demand growth from both electric vehicles and stationary storage. While overall reserves appear adequate for foreseeable demand, mining capacity, refining capability, and geopolitical concentration create potential bottlenecks.
Lithium supply has expanded rapidly but faced temporary constraints. New mining projects in Australia, Chile, and Argentina have brought additional capacity online, while direct lithium extraction techniques promise to unlock previously uneconomical brine deposits. Forecasters debate whether supply will pace demand smoothly or through cycles of shortage and glut. Price volatility reflects this uncertainty-lithium carbonate prices spiked above $80,000 per ton in 2022 before falling below $15,000 by late 2024.
Cobalt presents more acute concerns. The Democratic Republic of Congo supplies roughly 70% of global production, raising questions about supply security and ethical sourcing. Battery manufacturers have responded by reducing cobalt content in cathode chemistries and shifting toward cobalt-free LFP. NMC batteries that once contained 20% cobalt now use 5% or less. LFP's rise effectively eliminates cobalt from most utility storage applications.
China dominates battery supply chains beyond raw materials. Chinese companies control 70-80% of global battery cell manufacturing capacity, 80% of cathode production, and 95% of anode manufacturing. Contemporary Amperex Technology (CATL), BYD, EVE Energy, and CALB have built massive production complexes that achieve costs other regions struggle to match. This concentration creates strategic vulnerabilities for countries seeking domestic battery industries.
Western governments have responded with industrial policy. The U.S. Inflation Reduction Act includes $369 billion for clean energy, with substantial support for domestic battery manufacturing. European Union initiatives similarly aim to build regional capacity. However, catching China's decade-long head start requires sustained investment and technical development. New factories take years to build and longer to achieve competitive yields and costs.
Material recycling could eventually alleviate primary supply pressures. By 2035, according to International Energy Agency projections, retired electric vehicle batteries will become a major source of materials, potentially reducing primary lithium, nickel, and cobalt demand by 25%, 25%, and 40% respectively by 2050. However, current recycling rates remain below 5% in the U.S. and European Union, and scaling recycling infrastructure to match projected battery retirements presents its own challenges.
The Recycling Challenge: Closing the Loop at Scale
Battery recycling represents the sustainability dimension where scaling lags most significantly behind deployment. While installation capacity grows 30-40% annually, recycling infrastructure develops far more slowly, creating a looming mismatch as early installations reach end-of-life.
Current recycling rates tell a sobering story. Less than 5% of lithium-ion batteries are recycled in the United States and European Union, with Australia managing just 2-3%. This isn't primarily a technical limitation-batteries can be recycled-but rather an economic and logistical challenge. Collection networks remain underdeveloped, processing costs exceed material recovery value at current commodity prices, and diverse battery designs complicate automated disassembly.
Three main recycling pathways exist, each with distinct economics and environmental profiles. Pyrometallurgy involves smelting batteries at high temperatures to recover metals, but loses lithium and graphite while consuming substantial energy. Hydrometallurgy uses chemical processes to selectively extract materials, achieving higher recovery rates but generating chemical waste streams. Direct recycling repairs and reconstitutes cathode materials without breaking them down, potentially offering the best economics and lowest environmental impact, but requires sorting batteries by chemistry and remains largely at laboratory scale.
Several recycling startups raised billions in venture capital based on breakthrough promises, but 2024 brought setbacks. Lithium and nickel price collapses made recycled materials temporarily uncompetitive with mined supply, undermining business models predicated on selling recovered commodities. Aqua Metals faced financing difficulties when lithium prices dropped during due diligence for a commercial facility. SK Ecoplant sold its stake in Ascend Elements, refocusing away from battery recycling.
Yet some recyclers achieved meaningful scale. Redwood Materials, founded by former Tesla CTO JB Straubel, processes 20 GWh of batteries annually-60,000 metric tons of material. The company generated nearly $200 million in 2024 revenue selling recovered copper, aluminum, and battery precursors. This demonstrates that well-capitalized recyclers with integrated business models can operate profitably even during commodity price volatility.
Regulatory frameworks are evolving to mandate recycling. European Union battery regulations require minimum recycled content in new batteries and collection targets for end-of-life batteries. California and other U.S. states are developing extended producer responsibility policies that make battery manufacturers financially responsible for end-of-life management. These regulations should drive recycling infrastructure investment, though their effectiveness depends on enforcement and international coordination.
The recycling challenge intensifies with scale. By 2030, an estimated 318 GWh of lithium-ion batteries will reach end-of-life, roughly half from electric vehicles. Stationary storage installations from the early 2020s will begin retiring in the 2030s, adding to this stream. Recycling capacity must increase by approximately 50 times over the next decade to handle projected volumes, requiring unprecedented investment in collection networks, sorting facilities, and processing plants.
Grid Integration: Infrastructure Scaling Barriers
Battery storage doesn't scale in isolation-it must integrate with existing grid infrastructure designed around centralized generation. This integration presents challenges distinct from manufacturing or siting individual installations.
Grid interconnection queues have become a critical bottleneck. In the United States, over 600 GW of battery storage sits in interconnection queues awaiting utility approval to connect. The review process often takes 3-5 years, during which project economics can deteriorate as costs change and revenue opportunities shift. Many projects withdraw from queues after studies reveal required transmission upgrades that make them uneconomical.
Transmission infrastructure limits where storage can effectively deploy. Adding battery capacity in areas with transmission constraints can worsen congestion by adding to charging load. Some projects deemed promising from a site perspective fail because local grid infrastructure cannot support them without expensive upgrades that fall on the developer. This creates a catch-22: storage could relieve transmission constraints, but can't be built where it's most needed due to those same constraints.
Market structures in some regions haven't adapted to storage's unique characteristics. Batteries simultaneously consume and generate electricity, fitting neither traditional generation nor load categories cleanly. Wholesale market rules written for fossil generators may not properly compensate storage for the full range of services it provides-frequency regulation, voltage support, congestion relief-beyond simple energy arbitrage. Federal Energy Regulatory Commission orders in the United States have pushed markets to reform, but implementation varies by region.
Geographic concentration of storage in California and Texas partly reflects markets that reward storage effectively. California's "duck curve"-the sharp evening ramp-up needed as solar generation fades-creates strong price signals for 4-hour storage. Texas's energy-only market design allows storage to capture extremely high prices during tight supply conditions, sometimes exceeding $1,000 per MWh. Other regions with less dramatic price variation or capacity payment schemes designed for traditional generators see slower storage adoption regardless of technical suitability.
Software and controls present both challenges and opportunities. As battery penetration increases, managing thousands of distributed storage assets requires sophisticated coordination. Grid operators need visibility into storage state-of-charge, availability, and dispatch capabilities in real-time. Battery management systems must respond to grid signals in milliseconds for frequency regulation while optimizing long-term revenue across multiple value streams. Companies like Tesla and Fluence have developed SCADA systems and optimization software that treat storage fleets as virtual power plants, but integrating these into utility control systems requires standards development and institutional change.
The Learning Curve Continues
Battery storage's scalability ultimately depends on sustaining learning rates-the pace at which costs decline with each doubling of cumulative deployment. Historical data suggests lithium-ion batteries achieve roughly 20% cost reductions with each doubling of installed capacity, matching or exceeding learning rates of mature technologies like solar PV.
Several factors support continued learning. Manufacturing processes still have room for optimization. Cell production yields improve as factories gain experience. Automation reduces labor content. Material utilization becomes more efficient, reducing waste. These incremental improvements accumulate into significant cost reductions over deployment cycles.
Chemistry evolution drives step-change improvements. Current lithium-ion technology represents decades of incremental refinement, but hasn't exhausted improvement possibilities. Silicon-based anodes could increase energy density by 20-30%, reducing cell counts for given capacity. Solid-state electrolytes might enable denser, safer batteries, though manufacturing challenges have repeatedly delayed commercialization. Dry electrode coating techniques, pioneered by Maxwell Technologies and now scaling at Tesla, could reduce manufacturing energy and cost by 10-15%.
Cross-sector learning continues benefiting stationary storage. Every improvement in electric vehicle batteries-and EVs continue growing at 30-40% annually-translates to better, cheaper stationary storage with minimal additional development cost. This synergy seems likely to persist through the 2020s as EVs remain the battery industry's largest market by volume and investment.
However, learning rates can decelerate. As technologies mature, easy improvements get exhausted and harder problems remain. Solar PV experienced this in the mid-2010s, when cost reductions slowed after years of rapid decline before manufacturing scale and new cell designs resumed progress. Battery storage might face similar plateau periods, particularly if raw material constraints emerge or if the industry shifts to fundamentally different chemistries that restart learning curves.
Market saturation in some applications could slow deployment growth. Once renewables plus storage fully address evening peaks in favorable markets like California and Texas, growth may depend on displacing baseload generation-a more demanding application requiring longer duration storage at costs not yet achieved. Regulatory barriers, safety concerns, or public opposition could limit deployment in some regions, fragmenting markets and limiting scale economies.
Regional Variations in Scaling Success
Battery storage scales unevenly across different markets, revealing how policy, market design, and resource endowments shape deployment patterns. Understanding these variations provides insight into scaling enablers and barriers.
China dominates global battery storage deployment, accounting for over 55% of total capacity. This reflects China's position as both the world's largest renewable energy developer and dominant battery manufacturer. Provincial governments mandate that wind and solar projects include storage-often 10-20% of generation capacity with 2-hour duration-accelerating deployment. However, recent policy changes aim to shift from mandates toward more market-based mechanisms, potentially slowing near-term growth while improving project economics over time.
The United States saw extraordinary growth in 2024, adding over 12 GW of capacity-more than doubling installed base. The Inflation Reduction Act's investment tax credits for standalone storage, not just solar-plus-storage, removed a major barrier. California and Texas together account for 70-80% of U.S. capacity, though other states are emerging. Arizona, Nevada, and New York show significant planned capacity. This geographic diversity reduces reliance on single-state policies and spreads scaling learning across regions.
Europe lags somewhat despite ambitious renewable targets. Germany, the Netherlands, and the United Kingdom lead European deployment, but overall capacity remains well behind the U.S. and China. Higher electricity prices and less dramatic daily price variation reduce arbitrage opportunities, though grid services markets provide revenue. The European Union's "Green Deal" and battery manufacturing initiatives aim to accelerate deployment and build domestic supply chains, though success remains uncertain.
Emerging markets present significant scaling opportunities with distinct challenges. India, Southeast Asia, and parts of Latin America and Africa have rapidly growing electricity demand, substantial renewable resources, and electricity grids that could benefit from storage. However, financing costs, policy uncertainty, and less-developed market structures slow deployment. Some countries lack wholesale electricity markets entirely, making it unclear how storage would generate revenue. International development finance and technology partnerships could unlock these markets, but progress has been gradual.
What Scalability Means for Energy Transition
The evidence demonstrates that large scale battery energy storage systems do scale across multiple critical dimensions. Physical capacity has grown from megawatts to gigawatts in single installations, with the largest projects now exceeding 10 GWh. Costs have declined 89% over 13 years through manufacturing scale and learning-by-doing. Global deployment accelerates at 30-40% annually, with over 140 GW in project pipelines through 2030.
Yet scalability isn't uniform or unlimited. Duration remains constrained at 2-4 hours for lithium-ion systems, limiting roles in grids with very high renewable penetration. Safety concerns appropriately restrict deployment density near populations. Material supply chains face potential bottlenecks, though chemistry shifts toward abundant materials mitigate this. Recycling infrastructure lags dangerously behind deployment, creating sustainability concerns. Grid integration challenges slow projects even where batteries themselves work well.
These constraints shouldn't obscure the fundamental success story. Battery storage has scaled from niche applications to mainstream grid infrastructure in roughly a decade. Projects that would have been impossible or uneconomic in 2015 are routine in 2025. Learning rates suggest costs will continue declining, expanding the range of economic applications. Multiple companies now operate at gigawatt-hour manufacturing and deployment scales, with established supply chains, proven designs, and understood operational practices.
The next decade will test whether scaling continues at current rates or encounters harder limits. Material constraints may tighten. Safety incidents could trigger restrictive regulations. Easier applications may be exhausted, leaving harder ones. Recycling must scale dramatically or create environmental crises. Long-duration storage technologies must emerge for deep renewable penetration.
These challenges appear surmountable rather than fundamental. The battery storage industry has repeatedly overcome predictions of constraints, from lithium scarcity to safety concerns to economic viability. Manufacturing capacity continues expanding. New chemistries emerge regularly. Recycling technologies advance even as near-term economics fluctuate. Policy support strengthens globally as benefits become evident.
Battery storage's scaling success matters enormously for climate and energy policy. Intermittent renewables like wind and solar provide the cheapest new electricity generation in most markets, but need storage to deliver firm capacity. Every dollar decline in storage costs makes higher renewable penetration more economical. Every gigawatt of storage deployed builds confidence in renewable-dominant grids. The question isn't whether storage can scale-it demonstrably has-but how quickly and how far, which will largely determine the pace of energy transition this century.
Frequently Asked Questions
What is the largest battery storage system currently operating?
The Edwards & Sanborn project in California currently holds the record for operational capacity at 3,287 MWh, paired with 875 MW of solar generation. However, even larger projects are under construction, including BYD's 12.5 GWh deployment across five sites in Saudi Arabia and Grenergy's 11 GWh Oasis de Atacama project in Chile.
How much have battery storage costs decreased?
Lithium-ion battery costs have decreased approximately 89-90% from 2010 to 2023, falling from around $1,200 per kilowatt-hour to $137-150 per kWh. This represents a cost halving time of roughly 4.1 years, with projections suggesting costs will drop below $100 per kWh by 2025.
Why are most battery systems limited to 2-4 hours of duration?
The duration limitation reflects economics rather than technical impossibility. Each additional hour of storage requires more battery cells, linearly increasing costs. Four-hour systems suit most current grid applications-peak shifting, frequency regulation-at attractive economics. Longer duration requires different technologies like flow batteries or fundamentally new approaches that are still developing.
Are battery fires a major risk for large-scale storage?
Battery fires represent a manageable but non-trivial risk. While individual cell failure probability is extremely low (one in ten million), cascading failures can occur in large installations. The industry has responded with improved battery management systems, physical containment, fire suppression, and the shift toward inherently safer LFP chemistry. Regulatory frameworks have evolved based on incident investigations, establishing safety standards that reduce risk substantially.
What happens to batteries when they reach end-of-life?
Currently, less than 5% of lithium-ion batteries are recycled in the U.S. and Europe. Multiple recycling pathways exist-pyrometallurgy, hydrometallurgy, and direct recycling-each with different economics and environmental impacts. Recycling capacity must scale dramatically over the next decade to handle projected battery retirements. Policy frameworks increasingly mandate recycling and set targets for recycled content in new batteries.
Can battery storage replace fossil fuel power plants entirely?
Battery storage can replace fossil fuel "peaker" plants that operate during demand peaks, and indeed is already doing so in many markets. However, replacing baseload fossil generation requires longer-duration storage (days rather than hours) at costs not yet achieved. Grids with less than 40% variable renewables need only short-duration storage. Beyond 80-90% renewables, long-duration storage becomes essential, requiring technologies still in development or early commercialization.