Regional spotlight: Grid modernization & storage in US — what's different and why it matters

The US interconnection queue held 2,600 GW of proposed generation and storage capacity at the end of 2025, more than double the entire installed generation fleet, yet only 14% of projects that entered the queue between 2015 and 2020 reached commercial operation (Lawrence Berkeley National Laboratory, 2025). That single statistic captures the central paradox of grid modernization in America: massive capital is chasing grid-scale storage and transmission upgrades, but structural bottlenecks in permitting, interconnection, and market design are throttling deployment rates in ways that have no direct parallel in Europe, China, or Australia. For investors evaluating grid infrastructure opportunities, understanding the US-specific dynamics is essential because global benchmarks systematically understate the timeline risk and overstate the addressable market.

Why It Matters

The US grid is not a single grid. It is three loosely connected synchronous interconnections (Eastern, Western, and ERCOT) operated by a patchwork of seven regional transmission organizations (RTOs), 35 independent balancing authorities, and more than 3,000 individual utilities. This fragmentation creates market conditions fundamentally different from the centrally planned grids of China or the harmonized regulatory frameworks of the European Union.

Federal policy has injected unprecedented capital into the system. The Inflation Reduction Act (IRA) of 2022 provides a standalone Investment Tax Credit (ITC) of 30% for energy storage systems and a Production Tax Credit (PTC) for clean electricity generation, with bonus adders for domestic content and energy communities. The Infrastructure Investment and Jobs Act (IIJA) allocated $65 billion for grid infrastructure, including $2.5 billion for the Transmission Facilitation Program and $10.5 billion for Grid Resilience and Innovation Partnerships (Department of Energy, 2025). Total federal support for grid modernization and storage exceeds $100 billion through 2032.

Yet deployment remains constrained. The US installed 8.7 GW of battery storage in 2025, up from 5.1 GW in 2024, but this represents less than 3% of the interconnection queue backlog (American Clean Power Association, 2026). Transmission buildout averaged 1,200 miles per year over the past decade, versus the 2,400 miles per year that the National Renewable Energy Laboratory (NREL) estimates is necessary to meet 2035 decarbonization targets (NREL, 2025). The gap between capital availability and physical deployment defines the US market opportunity and its risks.

Key Concepts

The Interconnection Queue Crisis

The Federal Energy Regulatory Commission (FERC) Order 2023, finalized in July 2023, represents the most significant reform to US interconnection processes in two decades. The order replaces the serial "first-come, first-served" study process with a "first-ready, first-served" cluster study approach, requires applicants to post site control documentation and increased financial deposits ($5,000/MW for projects up to 20 MW, rising to $4,000/MW for larger projects), and mandates completion of the interconnection study process within 150 days per phase.

Early results are mixed. PJM Interconnection, the largest RTO by capacity, cleared its transition cluster in late 2025 with 95 GW of capacity advancing to detailed study, down from 260 GW of speculative applications. The Midcontinent Independent System Operator (MISO) processed its first post-reform cycle with average study times of 180 days, an improvement from 3 to 5 years under the prior regime but still above FERC's 150-day target. The California Independent System Operator (CAISO) reported a 40% reduction in queue withdrawals, suggesting that higher financial commitments are filtering out non-viable projects (FERC, 2025).

For investors, the implication is that interconnection timelines will compress from 5 to 7 years to 3 to 4 years for well-positioned projects, but will not approach the 12 to 18 month timelines common in markets like Australia or Germany.

State-Level Storage Mandates

The US lacks a federal storage deployment target. Instead, storage policy is driven by state-level mandates that vary enormously in ambition and mechanism. California leads with a 52 GW clean energy target by 2045 under SB 100, supported by California Public Utilities Commission procurement orders that have directed the state's three investor-owned utilities to contract 11.5 GW of new storage capacity between 2021 and 2028. New York's Climate Leadership and Community Protection Act (CLCPA) targets 6 GW of storage by 2030 through the NY-SUN and NY-Best programs, with $280 million in direct incentive funding. Nevada mandated 1 GW of storage procurement by 2030 through SB 448, with cost recovery guaranteed through rate base treatment.

Other states have adopted softer approaches. Texas has no storage mandate but ERCOT's energy-only market design, with wholesale prices regularly exceeding $5,000/MWh during scarcity events, provides strong merchant revenue signals that attracted 4.2 GW of battery storage investment through 2025 without any state subsidy. Illinois enacted the Climate and Equitable Jobs Act (CEJA) in 2021, which includes storage provisions but lacks specific GW targets, relying instead on Renewable Portfolio Standard (RPS) credit eligibility for paired storage systems.

The patchwork creates both opportunity and risk. Projects in mandate-driven states benefit from contracted revenue certainty, while projects in market-driven states like Texas offer higher potential returns with greater exposure to price volatility.

What's Working

ERCOT's Merchant Storage Boom

Texas has emerged as the fastest-growing battery storage market in the US, with 4.2 GW installed by end of 2025 and an additional 15 GW in active development. The ERCOT market's lack of a capacity market means storage operators earn revenue entirely through energy arbitrage and ancillary services, creating a direct linkage between battery deployment and grid reliability improvement.

The economics are compelling in periods of scarcity. During Winter Storm Elliott in December 2022, battery storage facilities in ERCOT earned $150,000 to $250,000 per MW over a four-day period (Modo Energy, 2025). The 300 MW/1,200 MWh Gamesa Energy Storage project in West Texas, developed by Plus Power and operational since early 2025, reported first-year revenues of $45/kW-year from energy arbitrage alone, exceeding its $38/kW-year debt service threshold by 18%.

However, revenue concentration risk is significant. Modo Energy analysis of 2025 ERCOT battery revenues shows that 60% of annual revenue was earned during just 120 hours of high-price events. Projects relying on merchant revenue must underwrite the full range of annual price distributions, including years with mild weather and lower volatility.

California's Procurement-Driven Buildout

California's approach of mandated procurement through long-term resource adequacy contracts has delivered reliable deployment at scale. The 2025 procurement cycle added 3.1 GW of contracted storage capacity, bringing the state's total contracted pipeline to 14.5 GW. Contract structures typically provide 10 to 15 year tolling agreements with fixed capacity payments of $8 to $12/kW-month, giving project developers bankable revenue certainty.

The Moss Landing Energy Storage Facility, operated by Vistra Energy at 750 MW/3,000 MWh, is the largest battery storage installation in the world. The facility demonstrated its grid reliability value during the September 2022 heat wave, discharging at full capacity for four consecutive hours during peak demand periods and displacing 750 MW of gas peaker generation. Vistra reported that the facility earned its annual capacity payment in contracted resource adequacy revenue while capturing an additional $12 million in wholesale energy margin during the event (Vistra Corp., 2025).

FERC Order 2222 and Distributed Energy Resources

FERC Order 2222, which requires RTOs and ISOs to allow distributed energy resource (DER) aggregations to participate in wholesale markets, is unlocking a new category of grid modernization investment. Aggregated rooftop solar, behind-the-meter batteries, smart thermostats, and EV chargers can now bid into wholesale energy, capacity, and ancillary service markets as a single resource.

Sunrun, the largest US residential solar installer, launched its first 50 MW virtual power plant (VPP) aggregation in PJM territory in 2025, combining 12,000 residential battery systems into a single dispatchable resource. The aggregation participates in PJM's frequency regulation market, earning homeowners $30 to $50 per month in wholesale market revenue while providing the grid with fast-response frequency support. The program has attracted 35,000 customer enrollments across PJM and ISO-NE territories as of early 2026 (Sunrun, 2026).

What's Not Working

Transmission Permitting Paralysis

The US built 20,000 miles of interstate highway in a decade during the 1950s and 1960s but has struggled to build major transmission lines in under 10 years. The 732-mile SunZia transmission project in New Mexico and Arizona, approved in 2015, broke ground in 2023 and expects energization in 2026: an 11-year timeline from approval to operation. The Grain Belt Express, a 780-mile HVDC line from Kansas to Indiana, received its first state permit in 2016 and remains under construction with a projected 2027 completion date.

The barriers are primarily regulatory and political rather than technical or financial. Transmission lines must obtain permits from every county and state they cross, creating a serial approval process where a single local objection can delay or kill a multi-billion dollar project. The Fiscal Responsibility Act of 2023 included provisions for federal backstop permitting authority, but implementation has been slow and the Department of Energy's National Interest Electric Transmission Corridor (NIETC) designations remain legally contested.

For investors, transmission development carries timeline uncertainty that storage projects do not. Battery storage can be sited at existing substations with completed interconnection studies, avoiding the multi-jurisdiction permitting gauntlet entirely.

Capacity Market Design Flaws

PJM and ISO-NE operate forward capacity markets intended to ensure resource adequacy 3 years ahead. These markets have struggled to appropriately value storage's unique attributes. PJM's capacity market rules require resources to demonstrate a sustained output duration of at least 10 hours to receive full capacity credit, disadvantaging 4-hour battery systems that receive only 40 to 60% of the capacity value assigned to gas peakers. ISO-NE's pay-for-performance mechanism penalizes resources that cannot sustain output through multi-day winter cold snaps, effectively zeroing out the capacity value of short-duration batteries during the most critical reliability events.

These design choices are self-defeating: they suppress the economic signal for storage deployment while simultaneously highlighting the grid's dependence on aging gas peakers that face their own reliability challenges. FERC has signaled interest in reforming capacity market participation rules for storage, but formal rulemaking is not expected before 2027.

Interconnection Cost Allocation Disputes

Network upgrade costs assigned to interconnecting generators have become a major barrier to storage deployment. In MISO, a 200 MW battery project in northern Indiana received a $78 million network upgrade cost estimate, $390/kW, which exceeded the battery system's own capital cost. In PJM, aggregate network upgrade costs for projects in the 2023 transition cluster averaged $230/kW, roughly double the 2020 average (PJM Interconnection, 2025).

The core issue is that network upgrades benefit all grid users but costs are allocated primarily to the interconnecting generator. FERC has proposed reforms to allocate a portion of network upgrade costs to load-serving entities that benefit from increased transmission capacity, but utility opposition has delayed rulemaking.

Key Players

Established Companies

• Fluence Energy: joint venture of Siemens and AES, deployed 5.4 GW of storage in the US through 2025
• Vistra Corp.: operates the 750 MW Moss Landing facility and 3.2 GW of total US storage capacity
• NextEra Energy: largest US renewable developer with 2.8 GW of operational and contracted storage
• AES Corporation: pioneer in grid-scale storage with 4.1 GW globally, 2.3 GW in US markets

Startups and Growth-Stage Companies

• Plus Power: pure-play merchant storage developer with 1.5 GW in operation or construction across ERCOT and CAISO
• Form Energy: developing 100-hour iron-air batteries targeting $20/kWh for multi-day storage, 2025 pilot in Minnesota
• Eos Energy Enterprises: zinc-based aqueous battery manufacturer targeting 4 to 12 hour duration at utility scale

Investors and Financial Institutions

• BlackRock Infrastructure Partners: committed $3.2 billion to US grid storage through its Climate Infrastructure fund
• Brookfield Renewable Partners: acquired 2.1 GW of US storage development pipeline in 2025
• Goldman Sachs Asset Management: active in storage tax equity with $1.8 billion deployed since IRA enactment

Action Checklist

• Evaluate state-level storage mandates and procurement timelines in target markets before committing development capital
• Model merchant revenue scenarios across full weather and price distributions, not just average or P50 outcomes
• Assess interconnection queue position and estimated network upgrade costs before site acquisition
• Track FERC rulemaking on capacity market participation rules and interconnection cost allocation reform
• Stress-test project economics against IRA phase-down scenarios and potential legislative changes after 2032
• Evaluate co-location opportunities with existing substations and retiring thermal generation to reduce interconnection risk
• Monitor DER aggregation programs and virtual power plant platforms as complementary investment to utility-scale storage

FAQ

Q: How does the US storage market compare to China's in terms of deployment pace? A: China installed 23 GW of new battery storage in 2025, roughly 2.6 times the US volume, driven by centralized grid planning and provincial storage mandates tied to renewable project approvals. However, Chinese storage projects face lower utilization rates (averaging 15 to 20% capacity factor versus 25 to 35% in US markets) because provincial mandates often require storage as a condition of solar or wind approval without corresponding market signals for dispatch. US projects generally achieve higher per-MW revenue but face longer development timelines. The US advantage lies in market-driven revenue optimization; the Chinese advantage lies in speed of permitting and construction.

Q: What is the realistic payback period for utility-scale battery storage in the US? A: Payback periods vary significantly by market and revenue structure. Contracted projects in California with 10 to 15 year tolling agreements achieve 7 to 10 year simple paybacks at current capacity payment levels ($8 to $12/kW-month). Merchant projects in ERCOT have demonstrated 4 to 6 year paybacks in high-volatility years but face the risk of 12 to 15 year paybacks in low-volatility years. IRA tax credits (30% ITC with potential 10% domestic content bonus and 10% energy community bonus) effectively reduce equity investment by 30 to 50%, compressing payback periods by a proportional amount.

Q: Will long-duration energy storage change the investment thesis for grid modernization? A: Long-duration energy storage (LDES) technologies capable of 10 to 100+ hours of discharge, including iron-air (Form Energy), zinc-based (Eos Energy), and compressed air systems, are targeting cost points of $10 to $25/kWh that would make multi-day storage economically viable by 2028 to 2030. If achieved, LDES would address the seasonal and multi-day reliability gaps that short-duration lithium-ion batteries cannot fill, potentially displacing the need for 50 to 100 GW of gas peaker capacity nationwide. However, LDES technologies remain at pilot scale in the US, and investors should treat 2028 commercial availability claims with caution given the sector's history of timeline slippage.

Q: How does permitting reform affect the investment outlook for transmission versus storage? A: The Fiscal Responsibility Act's permitting provisions and proposed NIETC designations could reduce transmission development timelines from 10 to 12 years to 6 to 8 years for nationally significant projects. Even with reform, transmission remains a longer-duration, higher-uncertainty investment than storage. Storage benefits from modular deployment (100 MW increments at existing substations versus 500+ mile linear infrastructure), shorter construction timelines (12 to 18 months versus 3 to 5 years), and simpler permitting (single site versus multi-jurisdiction). Investors seeking near-term grid modernization exposure generally favor storage; those with 10+ year horizons and tolerance for regulatory risk may find transmission offers superior risk-adjusted returns at scale.

Sources

• Lawrence Berkeley National Laboratory. (2025). Queued Up: Characteristics of Power Plants Seeking Transmission Interconnection, 2025 Edition. Berkeley, CA: LBNL.
• Department of Energy. (2025). Building a Better Grid Initiative: Progress Report on IIJA Grid Infrastructure Programs. Washington, DC: US DOE.
• American Clean Power Association. (2026). Clean Power Annual Market Report 2025. Washington, DC: ACP.
• National Renewable Energy Laboratory. (2025). Transmission Expansion Requirements for a Decarbonized US Grid. Golden, CO: NREL.
• Federal Energy Regulatory Commission. (2025). Order 2023 Implementation: First-Year Assessment of Interconnection Process Reforms. Washington, DC: FERC.
• Modo Energy. (2025). US Battery Storage Revenue Tracker: ERCOT Market Analysis 2025. London: Modo Energy Ltd.
• Vistra Corp. (2025). Moss Landing Energy Storage Facility: Operational Performance and Market Participation Report. Irving, TX: Vistra Corp.
• Sunrun. (2026). Virtual Power Plant Program: Residential DER Aggregation Performance Report. San Francisco, CA: Sunrun Inc.
• PJM Interconnection. (2025). 2023 Transition Cluster: Network Upgrade Cost Summary and Analysis. Norristown, PA: PJM Interconnection LLC.