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NY regulators make larger distributed renewables eligible for compensation

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NY regulators make larger distributed renewables eligible for compensation

New York state regulators have increased from 2 MW to 5 MW the maximum size of distributed renewable energy resources eligible for special compensation rates and have approved an innovative plan to facilitate the expansion of battery storage systems in the service territory of Consolidated Edison Co. of New York Inc.

The New York State Public Service Commission on Feb. 22 voted to expand the capacity size cap on participating renewable projects under the value of distributed energy resources, or VDER, compensation system that was adopted in March 2017 with the aim of moving beyond the decade-old net-metering pay scheme. Under the VDER system, intermittent renewables and other distributed energy resources are compensated for the electricity they unload on to the grid and other benefits they offer as well.

As part of New York's ambitious Reforming the Energy Vision strategy, the VDER mechanism is intended to be more accurate in determining the value that the distributed energy resources bring to the grid, including — for the first time — locational and environmental benefits. This "value stack" compensation seeks to significantly reduce costs through economies of scale, especially for distributed generation projects such as community solar.

That enhanced compensation now is available for units with a capacity of 5 MW or below using any technology eligible for the rate. As was the case with net metering, the only combined heat and power, or CHP, eligible for VDER-based compensation is residential units with a rated capacity of 10 kW or below.

State regulators separately are considering whether to extend VDER-based compensation to larger CHP after a lobbying group urged that CHP resources be included in the new compensation method.

The PSC acknowledged in a news release that sufficiently upgrading the distributed system to handle one or multiple 5-MW projects "may be impractical or even impossible" in some areas. The agency also noted that existing interconnection rules require that reviews regarding technical impact be conducted for such projects and that the applicants pay for any necessary system upgrades to ensure that the integration of larger projects will not create reliability issues or costs for utilities and nonparticipating ratepayers.

The commission also unanimously approved a plan by Con Edison that will significantly increase the ability of energy storage technologies to export power to the utility's primary and secondary voltage distribution systems while maintaining power quality and safe and reliable operations. These first steps will help New York meet its new goal of deploying 1,500 MW of energy storage by 2025.

"It will now be much more straightforward for owners of private energy storage systems to export the electricity they produce to Con Edison's electric distribution systems, fulfilling another component of Gov. Andrew M. Cuomo's [Reforming the Energy Vision] strategy," PSC Chairman John Rhodes said. "Expanding the smart use of energy storage is key to creating the electricity grid of the future, one that is cleaner, more resilient and more affordable."

The proposal that the PSC approved for Consolidated Edison Inc.'s New York subsidiary specifically amends tariffs applicable to batteries, such as the optional exemption from the standby rate for designated technologies, and expands that eligibility to energy storage technologies such as flow batteries, flywheels and compressed air storage systems. The order also expands the ability of energy storage systems to participate in any nonwire alternative project instead of being limited to specific nonwire alternative projects such as the Brooklyn-Queens Demand Management Program.

Con Edison will also allow energy storage systems to export to the distribution system as part of their participation in demand response programs. Energy storage technologies equipped with inverters will be allowed to export to either the secondary or primary voltage distribution system, whereas non-inverter-based technologies will be allowed to export only to the primary voltage system.

The order further excludes stand-alone energy storage systems from earning the reliability credits applicable to standby service customers as the credit is designed to compensate customers for offsetting their native load, something stand-alone energy storage systems cannot do.

Finally, Con Edison stated that excluding stand-alone energy storage systems from receiving the credits would eliminate cost shifts to other standby service customers, since the stand-alone systems would be able to avoid all delivery charges if the reliability credits were available to them, the order noted.