The United States is on track to double its operational battery energy storage capacity by 2028 as developers move 54 gigawatts of projects through advanced stages of construction and permitting, according to the latest EIA inventory. That volume – equivalent to the entire US fleet built over the previous decade – will reshape wholesale market economics, alter capacity accreditation rules, and test whether supply chains and interconnection processes can absorb a deployment wave of this speed and concentration.
From Gigawatt Additions to a Structural Grid Resource
EIA’s January 2025 Preliminary Monthly Electric Generator Inventory identifies 54 GW of battery projects with planned commercial operation dates between January 2025 and June 2028. The agency classifies these as “planned” – meaning they have secured major approvals, financing, or construction contracts – rather than speculative proposals. For context, total US utility-scale battery capacity stood at roughly 21 GW at year-end 2024, up from less than 1 GW in 2019. The projected addition rate of roughly 22 GW per year through mid-2028 would sustain the exponential growth curve the sector has followed since the Inflation Reduction Act (IRA) introduced standalone storage investment tax credits in 2022.
The geographic concentration is notable. Texas (ERCOT) and California (CAISO) together account for approximately 60 percent of the pipeline, consistent with their roles as early adopters where high solar penetration creates predictable daily arbitrage windows. However, the pipeline now extends into the Southeast (Georgia, Florida), the Midwest (MISO footprint), and the Mid-Atlantic (PJM), reflecting a shift from pure energy arbitrage plays toward capacity value, ancillary services, and transmission deferral. EIA data shows over 15 GW of the planned capacity is sited outside the traditional Western and Texas strongholds, a threshold that signals storage is becoming a national grid asset class rather than a regional niche.
Project durations are also lengthening. While the 2020-2023 vintage was dominated by two-hour systems optimized for solar shifting, developers report that four-hour configurations now represent the majority of new interconnection requests in PJM and MISO, where capacity accreditation rules reward longer duration. Eight-hour and longer-duration projects remain a small fraction of the pipeline but are appearing in utility integrated resource plans (IRPs) as replacements for peaking gas turbines. That points to a technology maturation: storage is no longer just a solar enabler but a firm capacity resource in its own right.
Interconnection Reform and Supply Chain as the Real Bottlenecks
The 54 GW figure represents projects that have largely cleared the interconnection queue gauntlet – but the queue behind them is far larger. As of late 2024, FERC-jurisdictional queues held over 1,200 GW of storage and hybrid projects awaiting interconnection studies, with median wait times exceeding three years in PJM and MISO. FERC Order 2023, which mandates cluster studies, financial milestones, and readiness requirements, aims to clear inactive projects and accelerate viable ones. If Order 2023 implementation proceeds on schedule, the conversion rate from queue entry to commercial operation could rise from the historical 15-20 percent to 30-40 percent. That would make the current 54 GW pipeline a leading indicator of a much larger build-out through the early 2030s.
Supply chain dynamics present a parallel constraint. Global lithium-ion cell production capacity exceeded 2 TWh annually in 2024, comfortably above the roughly 300 GWh implied by 54 GW of four-hour systems. However, US domestic content requirements under IRA Section 45X and 48C – coupled with Treasury guidance restricting critical mineral sourcing from “foreign entities of concern” – create a de facto preference for cells and modules assembled in North America or free-trade partners. Current US module assembly capacity is on the order of 30-40 GWh per year and expanding, but cell manufacturing remains heavily concentrated in Korea, Japan, and China. Developers I’ve spoken with report 12-18 month lead times for major equipment (inverters, transformers, switchgear) and are locking in EPC contracts 24 months ahead of COD to secure slots. If the 22 GW/year installation pace materializes, it will consume a significant share of global power conversion equipment output, potentially raising balance-of-system costs 5-10 percent above 2023 lows.
That points to a cost inflection. After three years of declining $/kWh installed costs driven by falling lithium carbonate prices (from $80/kg in late 2022 to under $10/kg in 2024), the non-cell portion of the bill of materials – steel, civil works, labor, transformers – is now the dominant cost driver and is inflating. My estimate, based on recent developer disclosures and EPC bids, is that all-in installed costs for four-hour standalone systems have bottomed around $1,100-$1,300/kWh and may tick upward in 2025-2026 unless cell price declines resume. That matters for power purchase agreement (PPA) pricing: standalone storage PPAs in ERCOT and CAISO have been signed in the $15-$25/kW-month range for capacity payments plus energy arbitrage upside; a 10 percent cost increase could push developers to seek longer contract terms or higher capacity payments to maintain returns.
Who This Affects
- Utility resource planners: The 54 GW pipeline represents firm capacity that can be credited in IRPs at 50-80 percent nameplate (depending on duration and regional accreditation rules), potentially deferring 20-30 GW of new combustion turbine builds. Planners should model storage as a capacity resource with declining marginal ELCC (effective load carrying capability) as penetration exceeds 10-15 percent of peak load, and evaluate multi-day duration options for winter reliability events.
- Storage and hybrid developers: The pipeline’s shift toward four-hour and longer durations raises the bar for revenue stacking. Developers must now underwrite not just energy arbitrage but capacity market revenues (where they exist), frequency regulation, voltage support, and increasingly, transmission congestion relief contracts. Projects in non-RTO regions (Southeast, Mountain West) face merchant risk without organized capacity markets and should pursue utility RFPs or bilateral resource adequacy contracts.
- Grid operators (ISOs/RTOs): ERCOT, CAISO, PJM, and MISO will each integrate 5-15 GW of new storage by 2028. Operators must update state-of-charge modeling in security-constrained economic dispatch, refine capacity accreditation methodologies for duration-limited resources, and address the “cliff effect” where large storage fleets simultaneously charge during midday solar peaks and discharge at net-load peaks, potentially creating new ramping challenges.
- Investors and tax equity providers: The IRA’s standalone ITC (30 percent base, up to 50 percent with domestic content and energy community bonuses) has made storage a tax-equity-eligible asset class comparable to wind and solar. The 54 GW pipeline implies $60-70 billion in capital deployment through 2028, requiring expanded tax equity appetite. Investors should scrutinize offtake structures: merchant-heavy projects in ERCOT carry higher IRR potential but greater revenue volatility than contracted assets in regulated jurisdictions.
- Policy analysts and state regulators: The pipeline’s expansion into Southeast and Midwest states without RTO markets (e.g., Georgia Power, Duke Energy territories) will test whether vertically integrated utilities procure storage competitively or self-build. Regulators should require all-source solicitations with standardized storage bid evaluation frameworks to ensure ratepayers capture the cost declines evident in competitive markets.
What to Watch Next
- FERC Order 2023 implementation milestones: Track each RTO’s compliance filing (due mid-2025) and the first cluster study cycles under new rules (late 2025-2026). The rate at which “zombie” projects are withdrawn and viable projects receive executed interconnection agreements will determine whether the 54 GW pipeline expands to 80-100 GW by 2030.
- Domestic cell manufacturing ramp: Monitor commissioning of US cell factories (e.g., Panasonic/Tesla in Kansas, LG Energy Solution in Arizona, SK On in Kentucky). Combined target capacity is roughly 150 GWh/year by 2027; actual output versus nameplate will dictate how much of the 2028 pipeline qualifies for full 45X/48C bonuses versus imported-cell fallback.
- Capacity accreditation reforms in PJM and MISO: Both RTOs are revising ELCC curves for storage in 2025-2026 stakeholder processes. A shift from static four-hour accreditation to duration-adjusted, saturation-aware curves could reduce per-MW capacity revenue for new entrants by 15-25 percent, altering project finance underwriting.
- Long-duration storage demonstration outcomes: DOE’s Long Duration Storage Shot targets and the first commercial deployments of iron-air (Form Energy), flow battery (ESS Inc, Invinity), and thermal storage (Antora, Rondo) systems in 2025-2026 will indicate whether the 8+ hour segment can achieve sub-$100/kWh installed costs – the threshold for widespread peaker replacement.
- ERCOT ancillary service market saturation: With 10+ GW of storage already online and another 15+ GW planned by 2028, ERCOT’s regulation and responsive reserve markets are showing price compression. Watch for protocol changes (e.g., ERCOT NPRR 1120 on state-of-charge management) and the emergence of firm capacity products (e.g., ERCOT’s proposed dispatchable reliability service) as new revenue pillars.
Bottom line: The 54 GW pipeline confirmed by EIA is not a forecast – it is a committed capital deployment schedule that will make storage the second-largest source of new US generating capacity after solar through 2028. The sector’s next challenge is not demand but execution: clearing interconnection queues, securing domestic supply chains, and designing market rules that value storage’s full flexibility without over-crediting its duration-limited firm capacity.
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Note: facts and figures attributed above to Energy Storage News reflect that outlet's original reporting. Broader context, cross-sector connections, and forward-looking scenarios reflect independent analysis by our editorial team.
About this article: Drafted by Energy Ai with AI-assisted research and writing based on public reporting, then reviewed under our editorial process before publication.
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