Last Updated February 20, 2023
Eligible Renewable/Other Technologies:
Solar Photovoltaics, Wind (All), Hydroelectric (Small)
NOTE: In July 2020, the New York Public Service Commission adopted a net metering successor tariff for mass market net metering projects interconnected beginning on January 1, 2022. The successor tariff retains the same overall structure as the Phase One NEM tariff adopted in 2017, but adds a "Customer Benefit Contribution" (CBC) charge intended to cover the costs of state-funded programs. The CBC is based on installed DG capacity and differs by utility; it ranges from $0.69-$1.09 per kW per month.
New York's original net-metering law, enacted in 1997, applied only to residential photovoltaic (PV) systems up to 10 kilowatts (kW). Over the years, the law was expanded to include other forms of electric generation equipment including farm waste, wind, micro-hydro, fuel cell, and combined heat and power systems. Net metering is available on a first-come, first-served basis to customers of the state's major investor-owned utilities, subject to technology, system size and aggregate capacity limitations. Net metering allows the electric customers who own eligible electricity generation system to offset their utility electricity bill on a volumetric basis from the electricity generated by the system owned by the customer.
In 2015, the Public Service Commission (PSC) initiated the Reforming the Energy Vision (REV) proceeding with a vision towards a comprehensive reform in the state’s electric utility practice and regulatory paradigm. The REV initiative seeks to create a next generation of utility business models that are customer-centric and driven by technological innovation and private investments to provide resilient, affordable, and clean energy in the State. As a part of the REV proceeding, the PSC recognized the need for the development of a more accurate method of valuing distributed energy resources beyond net metering.
In March 2017, the PSC published an order on transiting from compensating distributed energy resources (DER) through net metering to the development of Value of Distributed Energy Resource (VDER) tariffs that more accurately reflect the costs and benefits of DERs on the grid. The PSC order provides a gradual transition process from net metering to VDERs over phases to avoid drastic changes in the market.
Grandfathering and the transition plan
All distributed energy projects that were interconnected prior to March 9, 2017 will be grandfathered and will continue to be compensated through net energy metering as before, unless the customer opts for the VDER tariff.
Phase One: Phase One of the transition includes two components- i) Phase One Net Energy Metering (NEM) and ii) Phase One Value Stack. Phase One NEM is identical to the previous net energy metering except the term limit of the contract is set to 20 years. Starting March 9, 2017, until January 1, 2022 all mass market DER projects interconnected to the grid will be compensated through Phase One NEM tariff (beginning on January 1, 2022, newly interconnected customers will be compensated using the successor tariff adopted in July 2020, which retains the structure of Phase One NEM but with an additional capacity-based Customer Benefits Contribution charge). Remote net metered customers, large on-site, and community distributed generation projects that have already paid 25% of interconnection costs, or have an executed Standard Interconnection Contract will be compensated through the Phase One NEM. Projects that don’t qualify for the Phase One NEM will be compensated based on Phase One Value Stack tariff.
Phase One Value Stack is only available to technologies and projects that were previously eligible for net metering. The Value Stack tariff will be based on monetary crediting for net hourly electricity exported to the grid. Excess credit will be eligible for carry over to subsequent billing and annual periods. Projects eligible for the Value Stack will have a term length of 25 years from their in-service date. The Value Stack for net hourly electricity exported to the grid will be calculated based on the value of:
- Energy Value based on Day Ahead hourly zonal locational-based marginal price (LBMP),
- Capacity Value based on retail capacity rate based on performance during the peak hour in the previous year
- Environmental value based on the higher of the Clean Energy Standard Tier 1 Renewable Energy Credit (REC) price or the Social Cost of Carbon (SCC)
- Demand Reduction Value (DRV) and Locational System Relief Value (LSRV) based on de-averaging of utility marginal cost of service studies
Community Distributed Generation (CDG) projects on the Phase One Value Stack Tariff will also receive Market Transition Credit (MTC) equal to the difference between the retail rate and the value stack. The MTC capacity for CDG is allocated into three Tranche buckets with decreasing values from the base rate
Phase Two: On May 2017, the PSC will commence the discussion on Phase Two of the transition process.
Hybrid Energy systems: In December 2018, the PSC issued an order accepting the Hybrid Tariff for distributed energy systems that include battery storage (hybrid facilities). These tariff will govern the compensation of for hybrid facilities. The interconnection of hybrid facilities was approved by the PSC order in April 2018. The tariff designed provides that the energy injected through storage medium does not received the Environmental Value (E), and the MTC credit under the value stack. The tariff includes four options. Option A and Option B offer E, MTC and Capacity Value for all injections by ensuring that only renewable energy injected. Option C uses multiple meters to determine whether injections are from renewable energy or not, and Option D uses monthly netting. The tariff is effective January 1, 2019.
The eligible technologies and the system size limits remain the same for the Phase One of the net metering transition process. Publicly-owned utilities are not obligated to offer net metering; however, PSEG Long Island offers net metering on terms similar to those in the state law. Below is listing of the system size limitations, organized by technology and eligible sector.
- Solar: 25 kW for residential, 100 kW for farms, 2 MW for non-residential
- Wind: 25 kW for residential, 500 kW for farm-based, and 2 MW for non-residential
- Fuel Cells: 10 kW for residential, 2 MW for non-residential
- Micro-hydroelectric: 25 kW for residential, 2 MW for non-residential
- Biogas: 2 MW (farm-based only)
- Micro-CHP: 10 kW (residential only)
Energy Storage projects paired with eligible DER will be eligible for compensation under Phase One NEM or Value Stack tariff for mass market on-site projects. Community Distribution Generation (CDG) and Remote Net metered (RNM) projects, or large on-site systems will be compensated at Value of Stack tariff.
The total amount of net metering available in the state is capped at aggregate limit determined by the Public Service Commission (PSC). The aggregate limit was previously set at 1.0%, which was tripled to 3% by PSC in October 2012, and doubled again in 2014 to 6% of the utility’s 2005 electric demand. In 2015, the PSC in response to utilities reaching the 6% aggregate capacity limit, allowed the aggregate capacity to float until the successor to net metering policy was developed.
The March 2017 PSC order on the net metering transition plan eliminated the previous aggregate cap based on a peak load calculation. The PSC instead provided that all the projects interconnected after March 9, 2017 should not impact more than 2% of each utility’s incremental net annual revenue. The provision is put in place to limit the impact of VDER tariff on non-participants.
As a way of monitoring the impacts of the DERs the PSC requires the utilities to report when they hit 85% of the recommended capacity size allocations for each of the utilities. This will provide the PSC time to determine the subsequent action if necessary.
|85% capacity (MW)||25.50||21.25||85.00||17.00||76.50||4.25|
Net Excess Generation
For most types of systems, customer net excess generation (NEG) in a given month is credited to the customer's next bill at the utility's retail rate. However, for residential micro-CHP and fuel cell systems NEG is credited at the utility's avoided cost rate. A slightly different methodology using a monetary credit ($ as opposed to kWh/volumetric) is used for customers on demand meters. At the end of each annual billing cycle, most customers (i.e., residential PV and wind and farm-based wind and biogas systems) will be paid at the utility's avoided-cost rate for any unused NEG. Compensation for unused NEG produced by non-residential wind and solar systems is not addressed by the statute, however, the New York Public Service Commission (PSC) determined in its February 2009 order that unused NEG for such systems should be carried forward from one year to the next. Likewise, residential micro-CHP and fuel cell customer-generators are not permitted to monetize NEG after a year or any other period, but may carry forward unused credits indefinitely. Recently enacted S.B. 1149 did not identify a specific annual reconciliation protocol for micro-hydroelectric facilities, but the recently approved utility tariffs provide for indefinite carryover.
In May 2011 the PSC issued an order addressing two aspects of the NEG crediting process for customer generators. First, the order requires utilities to adopt consistent NEG credit calculations that include all kWh-based customer charges beginning June 1, 2011. Prior to this, some utilities did not include certain charges (e.g., the System Benefits Charge (SBC) and Renewables Portfolio Standards (RPS) surcharge) in the calculation of NEG credits. Second, the order also requires utilities to allow customers eligible for an annual cash-out of unused NEG at avoided cost, such as residential solar customers, to make a one-time selection of the annual period in question. This provision will apply to both existing and new net metering customers and is intended to avoid circumstances where the time period used for the annual cash-out is disadvantageous for some customers (i.e., large amounts of NEG being cashed-out at a lower rate). Several utilities already permitted customer-generators to make such an election.
Any excess credit from VDER Phase One tariff can be carried over to next monthly billing period, including over the end of the annual period, however at the end of the contract these unused credits will be forfeited.
Remote Net Metering
In June 2011 the state enacted legislation (A.B. 6270) allowing eligible farm-based and non-residential customer-generators to engage in "remote" net metering of solar, wind, and farm-based biogas systems. Micro-hydroelectric facilities were added as eligible for this arrangement in August 2012. The law permits eligible customer-generators to designate net metering credits from equipment located on property which they own or lease to any other meter that is located on property owned or leased by the customer, and is within the same utility territory and load zone as the net metered facility. Credits will accrue to the highest use meter first, and as with standard net metering, excess credits may be carried forward from month to month. Revised utility tariffs incorporating this change for solar, wind, and farm-based biogas systems became effective December 1, 2011. The August 2012 extension to micro-hydroelectric customer-generators will require further tariff revisions.
In October 2015, the PSC issued an order requiring the utilities to i) allow customers to assign credits from multiple host accounts to one satellite account such that the sum of all the credits do not exceed 2MW per satellite account; and ii) permit the satellite accounts with less than 2MW in host account credits to be interconnected on site generation.
The legislation and subsequent PSC orders also establish rules relating to customer responsibility for interconnection costs (e.g., new meters, transformers, or other equipment) and limitations on such costs. Cost treatments vary by customer type and system size (see § 66-j and 66-l for details).
In July 2015 the NY Public Service Commission (PSC) issued an order that established a Community Net-metering in the State. The community net-metering allows multiple customers subscribe and receive credits to the electricity produced from off-site renewable generation facility. This policy makes it possible for renters, low-income residents, and homeowners to receive credits for renewable energy who previously could not install renewable generation facility in their homes.
In general a community energy project requires a minimum of 10 members. In March 2017, the commission allowed a waiver for a minimum ten member requirement for community distributed generation projects that are located on the site of a property serving multiple residential or non-residential customers. The group may include a single individual subscriber that has demand greater than 25kW, who will be limited to 40% of the total facility’s output. Other subscribers will be limited to individual demand less than 25kW, and their total energy use must aggregate to at least 60% of the facility’s output. The maximum size of the community energy system is limited to 2 MW. Any single entity, including facility developer, ESCO, municipal entity, business, non-profit, LLC, partnership, or other form of business or civic association can be the sponsor of the community energy facility. The sponsor will be responsible for building and operating the facility.
Implementation of the program is divided into two phases. First phase of the program will last till April 30, 2016, during which the community net metering will serve as an introductory phase. During this period, the projects will be limited to siting distributed generation in areas where it provides greatest locational benefits to the larger grid, and in areas that promote low-income customer participation. The second phase will begin in May 1st 2016 when the community net metering projects will fully implemented throughout the other utility service territories.
New York Generation Attribute Tracking System (NYGATS) tracks the attributes of electricity generated in or imported into the State and eligible to create and certify Renewable Energy Credits (REC). 1 REC represents the environmental attributes of 1 MWh of electricity generated through a qualifying renewable energy source. REC can be traded as commodities to demonstrate compliance to the State’s Tier I Renewable Energy Standard requirement or retired voluntarily to claim the environmental attribute of renewable energy generation.
Under previous net metering and Renewable Portfolio Standard (RPS) policy, the issue of RECs generated by net metering customers was not addressed as New York did not have a standard REC market. The current Clean Energy Standard in New York includes a Renewable Energy Standard (RES) that requires the utilities comply with the requirements via purchase or RECs or through compliance payment.
Behind the meter projects that were previously eligible to bid into Renewable Portfolio Standard (RPS) Main Tier solicitations will not be eligible to bid into Tier 1 solicitation by NYSERDA (exemptions apply). No behind the meter projects will be eligible to bid into Tier 1 solicitation conducted by NYSERDA. The RECs from these projects will be provided to the system owners for voluntary retirement, they cannot be traded or exchanged. These RECs will not be eligible for compliance for Tier 1 RES requirement, however they will be counted towards overall Statewide 50% by 2030 renewable resource goal.
DER project enrolled in the Phase One NEM including on-site mass market, small wind projects, RNM, and on-site large projects will be ineligible to bid into RES Tier 1 solicitation and will not count towards the utility’s compliance mandate, it will instead be retired on customer’s account. RECs from Community Distributed Generation projects will be counted by default towards the Utility’s Tier 1 obligation unless the customer choose to opt out.
All the RECs from the customers interconnected on the Value Stack tariff will be transferred by default to the utility for compliance for Tier I for exchange of environmental value component. The customer may choose to retain the RECs however and forgo the credit from environmental value on the tariff.