Still sizing batteries like it’s 2018?

That’s the grid equivalent of showing up to a data center with a flip phone. AI is blowing past legacy assumptions about load growth, and battery energy storage is stepping in with bigger, longer, and cheaper systems to keep the lights (and GPUs) on.

The problem

AI-driven data center demand is rising fast, concentrating around already-constrained substations and transmission corridors. The International Energy Agency estimates global data center electricity use could roughly double by 2026, with AI as a primary driver, pushing total consumption toward 620 to 1,050 TWh as capacity scales and inference workloads spread across industries, as detailed in this IEA analysis.

In the U.S., grid connection queues are swelling, even as utility-scale battery installations accelerate. The U.S. Energy Information Administration noted battery storage capacity was set to grow by about 89 percent in 2024, with multi-gigawatt additions continuing into 2025, per EIA’s Today in Energy and its ongoing battery storage study. The backlog and clustering of large loads means many sites face multi-year interconnection timelines, which Berkeley Lab has tracked across markets in this interconnection queue report.

The solution

Grid-scale batteries are increasingly being deployed as near-term capacity and flexibility at substations and along congested feeders. Developers and utilities are standardizing around 4-hour systems for capacity accreditation in many markets, while moving to 6–8-hour durations where resilience, peak-shaving, or long-duration adequacy is required. California’s Resource Adequacy framework counts batteries based on qualifying capacity with a 4-hour discharge profile, per CAISO’s QC methodology. The California Public Utilities Commission separately directed procurement of long-duration storage, including 8-hour resources by mid-decade, in Decision 21-06-035. NYISO’s capacity manual also reflects 4-hour requirements for storage capacity accreditation, detailed in NYISO’s ICAP Manual.

On the ground, these rules translate to practical deployments near constrained nodes. California’s Moss Landing complex has scaled to one of the world’s largest battery sites and operates with 4-hour capacity for peak support and renewable integration, as noted by Vistra in this project update.

Evidence: costs and supply chains

• Battery pack prices: BloombergNEF reports average lithium-ion pack prices fell to about $115/kWh in 2024, driven largely by lower materials prices and growing LFP adoption, in this survey. System-level costs continue to drop as integrators streamline hardware, software, and construction.
• Installations: EIA data shows strong utility-scale growth continuing through 2025, with batteries increasingly sited in California and Texas where congestion and renewable curtailment are most acute. See EIA’s 2024 outlook.
• Domestic manufacturing: U.S. policy is catalyzing more local production of battery modules, enclosures, and balance-of-system components. Standalone storage now qualifies for the Investment Tax Credit, summarized by SEIA here, and Treasury’s guidance on direct pay and transferability is easing financing for non-tax equity buyers, per this Treasury release. Integrators also continue to expand footprint, including new e-Storage capacity announced by Canadian Solar in Mesquite, Texas in this update.

Interconnection in 2026: faster, but not instant

FERC Order No. 2023 is reshaping the interconnection process with standardized, cluster-based studies, more stringent readiness requirements, and clearer modeling rules for hybrid resources. The goal is to speed approvals and reduce speculative queues. See FERC’s order. Expect 2026 to reflect more predictable timelines in markets that have completed initial compliance and transitioned to cluster studies, though high-demand nodes will remain capacity constrained.

Financing and flexibility services

With standalone storage ITC in force, plus transferability and, for some public entities, direct pay, the 2026 financing stack looks cleaner and cheaper. Developers should plan to monetize revenue across:

• Capacity accreditation and resource adequacy payments (typically with 4-hour minimums in many markets) as described by CAISO and NYISO.
• Ancillary services and fast-response reserves.
• Congestion relief and renewable firming near constrained substations, with site-specific value influenced by queue status and local planning processes. Berkeley Lab’s interconnection study provides context on where queues are heaviest.

2026 expectations: developers and buyers

• Costs: Continued moderation from 2024 levels, with LFP supply keeping pressure on prices, as noted by BNEF.
• Durations: A clear shift from 2-hour toward 4-hour as a baseline for capacity, with 6–8-hour systems gaining traction in markets seeking long-duration adequacy, supported by CPUC directives.
• Grid connections: Faster, more transparent cluster studies under FERC Order 2023, but hotspot substations will remain tight amid AI data center growth identified by the IEA.
• Procurement: More co-location near renewables, plus strategic siting at load pockets. Utility-owned and merchant models will grow side by side.
• Revenue stacking: Capacity + ancillary + congestion relief will dominate; arbitrage value depends on local price spreads and curtailment patterns.

Bottom line

AI is the load spike that is forcing a faster battery future. Expect cheaper LFP-led systems, more 4–8-hour durations, and tighter land and interconnection competition near data center corridors. The winners in 2026 will pair smart siting with flexible financing and a portfolio approach to market revenues.