Regulatory tracker: Grid modernization & storage rules by jurisdiction — what's live, pending, and proposed

Grid-connected battery storage capacity in the United States surpassed 23 GW by the end of 2025, a 78% increase from 2024, yet fewer than half of states have enacted comprehensive regulatory frameworks governing interconnection, permitting, or market participation for these assets. This gap between deployment velocity and regulatory clarity creates material risks for developers, utilities, and investors navigating a patchwork of rules that vary not only by state but by utility territory and local jurisdiction.

Why It Matters

The regulatory environment for grid modernization and energy storage determines project economics, timeline feasibility, and market access. According to the American Clean Power Association, 2,600 GW of generation and storage capacity sat in US interconnection queues at the end of 2025, with average wait times stretching to 5.1 years. The Federal Energy Regulatory Commission (FERC) reported that interconnection delays and regulatory uncertainty contributed to the cancellation of approximately 40% of projects entering queues between 2019 and 2023.

For executives making capital allocation decisions, regulatory risk now rivals technology risk as the primary determinant of project success. A 2025 Wood Mackenzie analysis found that regulatory and permitting costs represent 18-25% of total installed costs for grid-scale storage projects in the United States, compared to 8-12% in markets with streamlined frameworks such as Australia and the United Kingdom. Understanding which jurisdictions have favorable rules, which are actively reforming, and which remain hostile to storage participation is essential for portfolio strategy.

The Inflation Reduction Act (IRA) established standalone energy storage as eligible for the Investment Tax Credit (ITC) at 30% (with potential adders to 50%+), but realizing these incentives depends on navigating state and local permitting, interconnection, and market rules that the federal framework does not preempt. The result is a complex regulatory mosaic where identical projects can face radically different timelines, costs, and revenue opportunities depending on where they are sited.

Federal Regulatory Framework

FERC Order 2222 (Live)

FERC Order 2222, finalized in 2020 and with compliance filings accepted through 2025, requires regional transmission organizations (RTOs) and independent system operators (ISOs) to allow distributed energy resource aggregations to participate in wholesale markets. Implementation has been uneven. PJM Interconnection filed its compliance plan in 2022, with full market participation features operational by Q3 2025. CAISO integrated aggregation rules into its Extended Day-Ahead Market (EDAM) framework. MISO's implementation remains partially delayed, with full compliance expected by mid-2026. SPP filed its compliance proposal in late 2024, awaiting FERC acceptance.

FERC Order 2023 (Live, Phased Implementation)

FERC Order 2023, effective November 2024, overhauls the interconnection process for all generation and storage resources connecting to the bulk power system. Key provisions include: first-ready, first-served cluster study processes replacing sequential queues; financial readiness requirements (study deposits of $5,000/MW for projects over 20 MW); penalties for withdrawal; and mandatory 150-day timelines for cluster studies. RTOs are implementing these reforms on staggered schedules through 2026. CAISO's track record with cluster-based studies since 2008 positions it favorably, while PJM and MISO are restructuring their processes substantially.

Inflation Reduction Act Storage Provisions (Live)

The IRA's Section 48 ITC for standalone storage (effective January 2023) provides 30% base credit, with 10% domestic content bonus, 10% energy community bonus, and potential 10-20% adder for projects under 5 MW in low-income communities. Section 48E extends these credits through 2032 with technology-neutral clean electricity provisions. The Treasury Department finalized guidance on domestic content requirements in May 2025, establishing that 40% of manufactured components (rising to 55% by 2027) must be US-sourced to qualify for the bonus credit.

State-by-State Tracker

Live and Enforced

Jurisdiction	Key Regulation	Storage Target/Mandate	Effective Date
California	AB 2514, SB 100, CPUC decisions	52 GW clean energy by 2045; 15 GW storage target	Active since 2013, updated 2024
New York	CLCPA, PSC 18-E-0130	6 GW storage by 2030; 70% renewable by 2030	Active since 2019, updated 2025
Massachusetts	Clean Energy Standard, DPU 20-75	1.5 GW storage by 2030 (expanded from 1 GW)	Active since 2018, updated 2024
New Jersey	EMP, BPU Storage Program	2 GW storage by 2030	Active since 2021
Virginia	VCEA	3.1 GW storage by 2035	Active since 2020
Oregon	HB 2021, PUC Storage Investigation	100% clean electricity by 2040	Active since 2021
Nevada	SB 448	1 GW storage by 2030; grid modernization mandates	Active since 2021
Illinois	CEJA	40 GW storage and renewables combined by 2045	Active since 2021

Pending Implementation

Jurisdiction	Proposed Regulation	Status	Expected Timeline
Texas (ERCOT)	Reliability-based storage rules, PUC Docket 55980	Rule drafting complete, public comment phase	Q3 2026
Pennsylvania	Alternative Energy Portfolio Standard update (SB 230)	Passed Senate, House committee review	Late 2026
Michigan	MI Clean Energy Future Act storage provisions	Signed into law 2024, rulemaking underway	Rules final Q2 2026
Colorado	HB 25-1032 Grid Modernization Act	Introduced January 2025, committee hearings	2026 legislative session
Minnesota	Commerce Department storage targets rulemaking	Initiated November 2024, stakeholder workshops	Proposed rule Q4 2026

Proposed or Under Discussion

Jurisdiction	Proposal	Current Stage
Georgia	PSC Staff Report on storage market participation	Study phase, no formal docket
Florida	HB 487 (Distributed Storage Interconnection Reform)	Filed January 2026, committee referral pending
Ohio	PUCO Staff Investigation on storage as transmission asset	Staff report expected Q3 2026
North Carolina	HB 951 Implementation (storage allocation in IRP)	Utility IRP filings under review, contested proceedings
Arizona	ACC Grid Modernization Docket (E-00000A-24-0350)	Workshops held Q4 2025, proposed decision pending

Key Regulatory Dimensions

Interconnection Reform

Interconnection timelines represent the most critical regulatory bottleneck. Lawrence Berkeley National Laboratory data shows that average interconnection study completion times grew from 2.1 years in 2018 to 4.8 years in 2024 for projects in PJM, MISO, and SPP territories. California's cluster study approach, while imperfect, achieves median completion in 2.3 years. New York's standardized interconnection requirements (SIR) for projects under 5 MW offer streamlined 60-business-day timelines that have enabled distributed storage deployment at scale.

States with the most effective interconnection processes share common features: standardized technical requirements, defined cost allocation methodologies, and penalty mechanisms for utility study delays. Massachusetts' "Schedule Z" interconnection tariff provides transparent cost estimates within 15 business days for projects under 1 MW. Nevada's SB 448 mandated utility interconnection process reforms with 90-day completion targets and financial penalties for delays exceeding 120 days.

Market Participation Rules

Revenue stacking, the ability of storage assets to participate in multiple market products simultaneously, determines financial viability. CAISO allows storage to provide energy arbitrage, ancillary services (regulation up/down, spinning reserves), and resource adequacy capacity in the same delivery period. PJM's capacity market reforms (effective 2025/2026 delivery year) established capacity accreditation based on effective load-carrying capability (ELCC), reducing storage capacity values from 100% to 50-70% of nameplate for 4-hour systems. NYISO's buyer-side mitigation reforms allow storage to participate in capacity markets without offer floor restrictions for resources receiving state subsidies.

ISO-NE remains the most restrictive market for storage participation. Its minimum offer price rule (MOPR) application to state-subsidized resources effectively excludes many storage projects from capacity market revenues. Ongoing stakeholder processes may resolve this by 2027, but near-term project economics in New England depend heavily on state incentive programs rather than wholesale market revenues.

Permitting and Siting

Local permitting represents an underappreciated regulatory risk. The National Renewable Energy Laboratory documented that local permitting adds 6-18 months to project timelines in jurisdictions without pre-established frameworks for battery storage facilities. Fire code compliance (NFPA 855, adopted in 39 states as of 2025) provides baseline safety standards, but local fire marshals frequently impose additional requirements that vary by county.

California's AB 525 and New York's 94-c process provide state-level siting authority for large energy projects, bypassing local opposition. Arizona and Texas rely primarily on county-level permitting, creating inconsistent requirements across project sites. Florida's preemption of local solar restrictions (SB 386, 2024) does not extend to battery storage, leaving storage-specific permitting to individual municipalities.

Compliance Considerations by Asset Type

Utility-Scale Storage (>50 MW)

Projects of this scale interact primarily with FERC-jurisdictional interconnection processes, RTO/ISO market rules, and state integrated resource plan (IRP) requirements. The key compliance risks are interconnection queue delays, capacity market accreditation changes, and evolving cost allocation methodologies. Developers should monitor FERC Order 2023 implementation timelines in their target RTO and ensure financial readiness deposits are structured to preserve queue positions.

Commercial and Industrial (1-10 MW)

C&I storage faces a dual regulatory environment: state-level interconnection requirements for distribution-connected resources and local building/fire codes. The most favorable jurisdictions offer net metering or successor tariff structures that compensate storage exports at retail or near-retail rates. California's NEM 3.0 (effective April 2023) significantly increased the value of paired solar-plus-storage by shifting export compensation to time-of-use rates that align with storage dispatch. New York's Value of Distributed Energy Resources (VDER) tariff provides location-specific compensation that can exceed retail rates in constrained distribution areas.

Residential and Community (<1 MW)

Residential storage regulation centers on interconnection standards (IEEE 1547-2018 adoption), safety codes (UL 9540, NFPA 855), and rate design. States with time-of-use rates and demand charges create stronger economic signals for residential storage adoption. Vehicle-to-home (V2H) and vehicle-to-grid (V2G) regulations remain nascent, with only California, New Jersey, and Maryland having established pilot programs with defined interconnection procedures by early 2026.

Regulatory Risk KPIs by Jurisdiction

Metric	California	New York	Texas	PJM States	ISO-NE States
Interconnection Timeline (avg)	2.3 years	1.8 years	3.1 years	4.8 years	3.5 years
Market Revenue Streams Available	5+	4-5	3-4	3-4	2-3
Permitting Complexity (1-5)	3	2	4	3-5 varies	3-4
Policy Stability (1-5)	4	4	2	3	3
Storage Incentive Programs	Yes	Yes	Limited	Varies	Yes

Action Checklist

• Map target project jurisdictions against interconnection reform timelines and FERC Order 2023 implementation schedules
• Evaluate revenue stacking potential across energy, capacity, and ancillary service markets in each target RTO/ISO
• Assess local permitting requirements including NFPA 855 adoption status and additional fire marshal conditions
• Monitor state IRP proceedings for storage procurement mandates that create offtake certainty
• Structure ITC claims to maximize domestic content and energy community bonus credits under current Treasury guidance
• Track FERC Order 2222 compliance filings for distributed storage aggregation market access
• Evaluate capacity market accreditation methodologies (ELCC vs. nameplate) and their impact on project revenues
• Engage in state-level stakeholder proceedings for pending storage regulations before rules are finalized

FAQ

Q: Which US states offer the most favorable regulatory environment for grid-scale storage development? A: California, New York, and Nevada currently provide the most comprehensive frameworks combining storage mandates, streamlined interconnection, multiple market revenue streams, and state incentive programs. California's 15 GW storage target, well-developed CAISO market products, and state siting authority make it the benchmark. New York's VDER tariff and 6 GW target create strong economics for distributed and utility-scale projects. Nevada's SB 448 interconnection reforms and 1 GW mandate have attracted significant developer interest since 2022.

Q: How does FERC Order 2023 change the interconnection process for storage projects? A: Order 2023 replaces first-come, first-served serial study processes with cluster-based studies, imposes financial readiness requirements ($5,000/MW deposits for projects over 20 MW), and establishes 150-day study completion targets with penalties for delays. The intent is to reduce speculative queue entries and accelerate processing of viable projects. Developers should expect 12-24 months of transition-period disruption as RTOs implement new procedures through 2026.

Q: What are the biggest regulatory risks for storage projects in deregulated markets like Texas? A: ERCOT projects face unique risks including: absence of capacity market payments (energy-only market), evolving performance credit mechanism (PCM) implementation, limited ancillary services market depth, and county-level permitting variability. The lack of state storage mandates means deployment is driven entirely by merchant economics. PUC Docket 55980 may establish reliability-based storage requirements, but final rules are not expected before Q3 2026.

Q: How do state-level net metering and successor tariff policies affect commercial storage economics? A: Tariff design directly determines behind-the-meter storage ROI. California's NEM 3.0 increased storage value by shifting solar export compensation to time-of-use rates, making storage essential for economic solar installations. New York's VDER provides location-specific compensation. States with flat net metering rates and no demand charges (increasingly rare) offer weaker storage economics. The trend across major markets is toward time-varying rates that improve storage dispatch value.

Sources

• Federal Energy Regulatory Commission. (2025). Order 2023 Implementation Status Report: Interconnection Reform Progress. Washington, DC: FERC.
• Lawrence Berkeley National Laboratory. (2025). Queued Up: Characteristics of Power Plants Seeking Transmission Interconnection, 2025 Edition. Berkeley, CA: LBNL.
• American Clean Power Association. (2025). Clean Energy Market Report: Q4 2025. Washington, DC: ACP.
• Wood Mackenzie. (2025). US Energy Storage Monitor: Annual Review and Outlook 2026. Edinburgh: Wood Mackenzie.
• National Renewable Energy Laboratory. (2025). Storage Futures Study: Regulatory and Market Barriers Analysis. Golden, CO: NREL.
• US Department of the Treasury. (2025). Final Rule: Domestic Content Bonus Credit Requirements under Sections 45 and 48. Washington, DC: Treasury.
• California Public Utilities Commission. (2025). Decision on Energy Storage Procurement Targets. San Francisco, CA: CPUC.