Requires BPU to establish distributed energy storage incentive program.*

The bill changes from establishing a temporary 'pilot program' with separate upfront and performance incentives to a single 'distributed energy storage incentive program' structured as a fixed annual payment for 15 years (or another board-set period), expressed in dollars per rated kilowatt-hour of capacity per year, capped at 40 percent of total project cost over the term.

The tariff filing requirement for front-of-the-meter energy storage is broadened: the original applied only to systems 'not subject to a tariff from PJM,' while the substitute applies to all front-of-the-meter energy storage systems and adds a requirement to maximize common elements among utilities.

Removes the requirement that the BPU adopt rules establishing a permanent energy storage incentive program within three years of the effective date. The substitute only requires rules as necessary to implement the act.

The wholesale market provision is refined: it now specifically references the PJM capacity market and allows temporary restrictions on wholesale participation if needed to ensure peak load reduction value is reflected in PJM load forecasts before systems can act as capacity suppliers.

Removes the directive for the BPU to consider revising net-metering eligibility requirements to accommodate energy storage capacity and potential future electric vehicle capacity.

Removes the requirement that the BPU allocate at least $60 million per year from the societal benefits charge to fund upfront incentives for the duration of the program.

Adds a utility cost-recovery mechanism: each electric public utility may recover actual implementation and administration costs through a separate rate component, and the board may allow a rate of return (potentially below the utility's most recent base rate case) if the utility meets implementation benchmarks set by the board.

Adds specific capacity targets: at least 2,000 megawatts of installed capacity by 2030 through this program, a first-year goal of up to 350 megawatts on a first-come first-served basis, and a combined goal of 3,000 megawatts with other board-established programs.

Removes the refundable deposit requirement for applicants with 25 kilowatts or greater of nameplate capacity, along with the associated forfeiture mechanism for missed deadlines.

Adds a new requirement that the BPU establish minimum performance standards for incentivized systems, including capabilities for renewable hosting capacity, congestion relief, capacity value or peak load reduction, voltage control (Volt/Var and Volt/Watt), ramp rate control, and T&D investment deferral. The board may adjust incentive payments based on compliance after the first year.

Removes the 'gap analysis' methodology that required comparing all-in system costs against available revenue streams to determine incentive amounts, and removes the definition of 'all-in system cost.'

Reduces the reserved share of customer-sited incentives for low-to-moderate income customers and overburdened communities from at least one third to at least one quarter.

Extends project completion deadlines: customer-sited systems from 18 months to 30 months after application approval, and front-of-the-meter systems from 40 months to 42 months. Adds 'supply chain disruption' and 'permit authority' as recognized extenuating circumstances for extensions.

Changes reporting from a one-time report within one year of program establishment to annual reports beginning in 2027 and continuing until the first calendar year after cost recovery ends, directed to both the Governor and the Legislature.

Adds new definitions for 'accredited capacity,' 'critical community facility' (formally identified by state or local emergency management in a hazard mitigation plan), 'energy storage capacity,' 'incentive program,' 'installed capacity,' and 'public utility.' Adds 'hosted' as an ownership option for customer-sited systems alongside owned, leased, or operated.