S3399

An Act concerning electric energy supply and distribution and supplementing Title 48 of the Revised Statutes.

Be It Enacted by the Senate and General Assembly of the State of New Jersey:

1. a. The Legislature finds and declares that:

(1) virtual power plants are dynamic load management and energy supply resources that support grid operations, reduce ratepayer costs, and achieve other important public policy goals;

(2) virtual power plants can reduce demand for grid supplied electricity during peak periods, shift electricity consumption out of peak periods, make renewable energy generated during off-peak periods available for use during on-peak periods, supply energy to the grid at desired times, provide frequency regulation, voltage support, and other ancillary services, improve system resiliency and reliability, and provide other grid services;

(3) virtual power plants facilitate and optimize the utilization of electrical generation from variable sources such as wind and solar energy to help utilities increase hosting capacity and integrate more renewable energy resources;

(4) virtual power plants reduce costs to ratepayers by utilizing customer-sited resources to provide grid services, avoiding or reducing reliance on fossil-fuel fired peaker plants, avoiding or deferring the need to construct new and more costly grid-scale resources, optimizing the use of existing assets, and avoiding or deferring distribution and transmission system upgrades and other grid investments;

(5) virtual power plants promote equity by reducing costs for all ratepayers and providing other important co-benefits, including reduction in greenhouse gases and other pollutants, especially in overburdened communities and other disadvantaged communities that host fossil fuel generation plants; and

(6) the United States Department of Energy estimates that the United States could deploy 80 to 160 gigawatts of virtual power plants by 2030, a tripling of current levels, which could provide ratepayer savings on the order of $10 billion annually.

b. The Legislature therefore determines that the deployment of virtual power plants can provide energy cost savings and other benefits to the citizens of New Jersey, and that it is in the public interest to direct the Board of Public Utilities to establish a virtual power plant program in collaboration with electric public utilities and distributed energy resource aggregators.

2. As used in this act:

“Board” means the Board of Public Utilities.

“Distributed energy resource” or “DER” means an electricity-producing resource, energy storage system, bidirectional electric vehicle charger, or controllable load, including a controllable unidirectional electric vehicle charger, that is connected to an electric public utility’s distribution infrastructure.

“Distributed energy resource aggregator” or “DER aggregator” means a third-party business entity that is authorized to enroll, operate, and compensate a virtually integrated and coordinated set of interconnected DERs which deliver services under the PJM tariff as filed in compliance with FERC Order 2222.

“Electric public utility” means the same as the term is defined in section 3 of P.L.1999, c.23 (C.48:3-51).

“Federal Energy Regulatory Commission” or “FERC” means the same as the term is defined in section 3 of P.L.1999, c.23 (C.48:3-51).

“Overburdened community” means the same as the term is defined in section 2 of P.L.2020, c.92 (C.13:1D-158).

“Virtual power plant” means an aggregation of distributed energy resources, enrolled either directly with an electric public utility or indirectly through a DER aggregator, that are operated in coordination to provide one or more grid services.

3. a. The board shall establish, by board order, a demand optimization program for electric public utilities to optimize demand, reduce system peak demand, increase resource adequacy, reduce or defer the need for costly distribution system infrastructure upgrades, and help maintain grid reliability through virtual power plant services provided by distributed energy resource aggregators in the State. The program shall be designed with a target for peak demand reduction of 500 megawatts by 2030.

b. No later than 12 months after the effective date of this act, the board shall establish minimum requirements for the demand optimization program, including, but not limited to:

(1) the allocation of the system peak demand reduction target that must be achieved by each electric public utility;

(2) grid flexibility services provided by the demand optimization program, which shall include, at a minimum, contribution toward system wide peak load reduction, and may also include local peak demand reduction, locational value, the avoidance or deferral of transmission or distribution upgrades for expanding integration capacity expansion, voltage support or other ancillary services, and such other functions and grid flexibility service opportunities that the board determines are supportive of efficient planning and utilization of the electric distribution grid;

(3) a process for allowing customers to combine load modification behavior with battery storage, non-battery storage, electric vehicle technologies, and other distributed energy resources that offer generation or load profile modification to enroll such devices in the program;

(4) the specific distributed energy resources that should be included, which shall include, but need not be limited to, battery energy storage systems, managed electric vehicle charging, bidirectional electric vehicle operation, smart thermostat demand response, smart inverter voltage support, grid-interactive water heaters, and commercial and industrial automated demand response;

(5) technical requirements for the development of a distributed energy resource registry, a distributed energy resource management system, and other data infrastructure and technology platforms developed to enable the demand optimization program, prioritizing open standards and interoperability for data, devices, and controls that are orchestrated through grid edge distributed energy resource management systems under market development;

(6) standards for electric public utility technology that are compatible with a competitive market for third-party aggregations participating in PJM wholesale markets in compliance with FERC Order 2222;

(7) standards for electric public utility selection of developers and vendors, including use of competitive procurement processes where practicable;

(8) performance terms for customers participating in the program, including measurement and verification, compensation levels, and non-performance penalties;

(9) requirements to ensure that low- and moderate-income customers and customers in overburdened communities are included in and benefit from the program;

(10) any categories of costs associated with the electric public utilities’ implementation of the program that may be recovered from ratepayers; and

(11) a prohibition on an electric public utility directly controlling any virtual power plant or other demand response system that modifies the electrical usage or energy storage of a customer, and a requirement that any such system be controlled by a third-party DER aggregator.

c. After the board issues minimum filing requirements, each electric public utility shall file an implementation and reporting plan with the board for its proposed demand optimization program. The board shall review each plan for cost effectiveness, conformance with program requirements, and conformance to the utility’s filed grid modernization plan, and may request changes to the submitted plan prior to board action. The board may approve, approve in part, or deny each submitted plan, and shall determine the appropriate level of spending for each electric public utility’s demand optimization program and establish an appropriate rate of return on equity, which may be less than the rate of return established in the electric public utility’s most recent base rate case. In determining whether to approve a plan and the appropriate level of spending, the board shall consider impacts on electric customer bills and shall ensure that the program results in cost savings to ratepayers, taking into account potential capacity market savings, avoided system costs, reduced peak demand and deferred distribution system upgrades, and the level of system integration capacity anticipated.

d. Each electric public utility shall file an annual report with the board to demonstrate compliance with its approved implementation plan and the board’s minimum requirements. If the electric public utility fails to achieve required program metrics, including, but not limited to, required peak demand reduction, integration capacity expansion, customer enrollment, and avoided energy system cost, the board may disallow recovery of all or some costs, unless such failure is due to factors beyond the electric public utility’s control and reasonable ability to predict.

4. The board shall, in accordance with the "Administrative Procedure Act," P.L.1968, c.410 (C.52:14B-1 et seq.), adopt rules and regulations as necessary to implement this act.

5. This act shall take effect immediately.

STATEMENT

This bill would require the Board of Public Utilities (BPU) to establish, by board order, a virtual power plant program to reduce peak demand for electric energy and provide other services to electric customers.

As defined by the bill, “virtual power plant” means an aggregation of distributed energy resources, e.g., residential solar systems, behind-the-meter energy storage systems, or electric vehicle charging systems, enrolled either directly with an electric public utility or indirectly through a distributed energy resource (DER) aggregator, that are operated in coordination to provide one or more grid services. The purpose of the program would be to reduce system peak demand, increase resource adequacy, reduce or defer the need for costly distribution system infrastructure upgrades, and help maintain grid reliability through virtual power plant services provided by DER aggregators in the State.

The program would be required to be designed with a target for peak demand reduction of 500 megawatts by 2030. The bill would require the BPU to establish minimum requirements for the program, but electric public utilities would be responsible for the program’s implementation. However, the bill would require that any direct control of electricity customers’ electricity usage or storage would be by third-party DER aggregators, rather than by electric utilities. Under the bill, each electric public utility would be required to file an implementation and reporting plan with the BPU, as well as an annual report.