NYPSC’s distributed energy resources order brings big changes for net metered energy projects in New York

April 18, 2017

Energy Law Alert

Author(s): Peter C. Trimarchi

The New York Public Service Commission recently issued an order establishing a new means of compensating commercial and residential renewable energy projects connected to the state’s electric distribution system. This alert discusses the nuts and bolts of this important new change to the renewable energy landscape in New York.

On March 9, 2017, the New York Public Service Commission (PSC) issued a long-awaited order establishing a new means of compensating commercial and residential renewable energy projects connected to the state’s electric distribution system.[1] The order does away with the “net metering” system that has been a fixture of the renewable energy space in New York (and other states) for the last 10 years, and implements in its place a new scheme based on the value that the project provides to the state and the existing distribution system. Commonly referred to as the “Value of Distributed Energy Resources” (or VDER, or Value of DER), this new compensation scheme will, fairly quickly, change the landscape of solar and other commercial- and residential-scale renewable energy development, and the financing of such projects. This alert summarizes the new compensation scheme.

Existing net metering in New York

Since 1997, renewable energy projects located “behind the meter” have received net metering credits for the power they contributed to the grid in a fairly simple fashion. For most customers, their account receives a credit for each kilowatt-hour injected into the grid that is equal to the retail price for energy provided by the utility (including supply, delivery and other charges). Demand-billed customers and mandatory hourly pricing customers (generally non-residential customers with energy demand above a certain threshold) receive a similar credit, but do not receive a credit for the delivery charge portion of their bill.

Remote net metered customers similarly receive a credit based upon the energy injected onto the grid, but the value of that credit differs depending upon when the system met certain development milestones. For projects that reached the milestones by June 15, 2015, the credit was calculated by converting the kilowatt-hours of excess generation at the off-site property to a monetary credit based on the per-kilowatt hour charges applicable to the off-site property’s service class (referred to as “monetary crediting”). For projects that reached those development milestones after June 15, 2015, excess kilowatt-hours that are generated at the off-site location are transferred to the customer’s account on a kilowatt-hour-for-kilowatt-hour basis (referred to as “volumetric crediting”).[2]

Critics of this system argued that it causes those not participating in net metering to pay the cost of maintaining the energy delivery system (as net metering participants pay fewer delivery charges that are intended to help maintain the grid). Moreover, such a system is inconsistent with the state’s “Reforming the Energy Vision” (REV) proceeding, which seeks to modernize the electric grid and transform it into a distributed, integrated, transactive and increasingly clean system.[3] In REV, the PSC determined that compensation systems for Distributed Energy Resources (DER) should be value-based, rather than technology-based, and that DER projects should be compensated not based on a fixed formula, but instead on the value they provide to the grid. The PSC thus issued the order, significantly revising the compensation DER projects will receive from the utility for power injected onto the grid. The new system is far more complex and is based on a number of factors, including the type of system and the date it was installed. The following is a simplified summary of how the new system will be applied to different projects.

Projects remaining eligible for existing net metering compensation

  • Projects in service as of the date of the order: There will be no change to the compensation for these projects. They will continue to receive net metering compensation under existing tariffs.

  • Projects under construction as of the date of the order: These projects will also receive net metering compensation under existing rules if they provided a written notification of complete installation to the interconnecting utility by March 17, 2017.

Projects eligible for existing net metering compensation for 20 years under “Phase One NEM”

  • Residential/small commercial (“Mass Market”) projects: A project interconnected behind the meter of a customer within a utility’s residential or small commercial service class, and not billed based on peak demand and not remote net metered, will continue to receive existing net metering compensation as long as it is interconnected before January 1, 2020. However, the Commission has imposed a capacity limitation on such projects, which is specific to each utility.[4] The capacity limitation is not a hard cap on the amount of projects eligible for such compensation, but a marker, at which point the Commission must determine whether to increase the allocation or take some other course of action

  • Non-Mass Market projects interconnected after March 10, 2017: Projects otherwise eligible for net metering, but interconnected after the date of the order, will still receive net metering compensation just like projects in place as of the date of the order for a period of 20 years, but only if the developer or owner has either made a payment for 25% of the interconnection costs (or has its interconnection contract executed if no payment is required) within 90 business days of the date of the Order (July 17, 2017).

  • Community Distributed Generation (CDG) projects interconnected after March 10, 2017: These projects will also receive net metering compensation under existing rules for a period of 20 years, as long as they have either paid 25% of their interconnection costs (or have their interconnection contract executed if no payment is required) by July 17, 2017. However, the order places a cap on the total rated generating capacity of CDG projects eligible for this compensation. The caps are established by utility territory and range from 23 MW for Orange and Rockland Utilities, Inc. to 137 MW for Consolidated Edison Company of New York, Inc.[5]

  • Remote net metered projects eligible for “monetary crediting” under previous commission orders: These projects will still be eligible to retain their monetary crediting, but, like other projects, must pay the 25% of their interconnection costs (or have their interconnection contract executed if no payment is required) by July 17, 2017 to maintain their eligibility for such crediting. For consistency with previous Commission orders, these projects will be allowed to maintain monetary crediting for a period of 25 years.

  • Wind turbines eligible for net metering: The above restrictions will not apply to wind turbines until the 0.3% cap for net metering established under § 66-l of the Public Service Law has been reached.

VDER Phase One

Projects that do not fall within any of the categories described above will be subject to the new compensation system established by the order, referred to in the order as the “VDER Phase One Tariff.” This compensation system will be based primarily on calculations of specific values applied to hourly net injections at a utility meter. When taken together, those values comprise the “Value Stack,” with each value serving as a component of the stack.[6] The values are as follows:

  • Energy Value: This value will be based on the day ahead hourly zonal locational-based marginal price, calculated at the time of generation.

  • Capacity Value: The amount of this value will differ depending upon the nature of the resource. For intermittent resources (solar, wind, etc.), the value will be based on the capacity portion of the supply charge for the service class with a load profile closest to the solar generation profile throughout the year. Such projects could, however, opt for different calculations based on summer output or based on peak performance in the peak hour in the previous year (the capacity tag method). For dispatchable resources, the capacity value will be based on the capacity tag method.

  • Environmental Value: This value will be based on the higher of either (a) the social cost of carbon or (b) the latest Tier 1 REC procurement price established by NYSERDA. The value will be fixed for the term of compensation for the projects, and shall only be calculated for the net hourly injections made by the system. The customer can opt out of this calculation by choosing to instead collect RECs generated by the project.

  • Demand Reduction Value and Locational System Relief Value: The order did not establish a basis for calculating these figures, although it did establish that the Demand Reduction Value will be fixed for three-year periods, and the Locational System Relief Value, once established, will be fixed for a period of ten years. The order requires the utilities to submit additional information to the Commission in order to assist in setting this value by summer 2017.

  • Market Transition Credit: CDG projects, and mass market customers that opt-in to the value stack, are eligible for an additional Market Transition Credit (MTC). The Commission created this credit due to the fact that CDG projects are likely to fare substantially worse under the new compensation scheme than they would have under traditional net metering. Simply stated, the amount of the credit is determined by subtracting the Value Stack for such projects from the Base Retail Rate applicable to power from such projects (including delivery, supply and other charges). The MTC for each project is set at the time of payment of 25% of interconnection costs (or execution of the Interconnection Agreement if no such payment is required), and then lasts for 25 years. The value of the MTC will step down as certain capacity allocations are reached within each utility.[7] The order requires the utilities to publish the final calculations for the MTC by May 1, 2017, for both residential and small commercial customers.

Projects qualifying for (or opting-into) the Value Stack will be eligible for Value Stack compensation (as continually revised based on energy prices and DMV/LSRV) applicable to a project for a term of 25 years from the in-service date.

Treatment of environmental attributes

The environmental attributes generated by DER projects are of much greater relevance following the revisions to New York’s Clean Energy Standard in 2016 that created a compliance obligation on Load Serving Entities. DER projects’ eligibility for transferable renewable energy credits (RECs) is set forth in the order as follows:

  • Projects utilizing existing net metering: Behind the meter projects that were previously eligible to bid in the Renewable Portfolio Standard Main Tier solicitations, were interconnected before March 9, 2017 and are actually enrolled in net metering are eligible to participate in Main Tier solicitations. However, no other behind the meter projects will be eligible to bid in RES Tier 1 solicitations conducted by NYSERDA going forward.

  • Projects in Phase One NEM: Any project that is eligible for Phase One NEM will be ineligible to bid in RES Tier 1 solicitations conducted by NYSERDA or to receive any tradable RECs. However, the power generated by CDG projects will count toward the interconnecting LSE’s RES compliance mandates, unless the customers make a joint non-revocable election at the time of interconnection to opt out and retain the credits themselves (which will be non-transferrable).

  • Projects in the Value Stack: Any project that enrolls in Value Stack compensation will also be ineligible to bid in RES Tier 1 solicitations conducted by NYSERDA or to receive any transferrable RECs. This is based on the fact that the DER generator is being compensated for the environmental value as part of the value stack, and therefore the LSE that pays for that value should receive credit for it. The LSEs will be able to count the environmental attributes from the project toward their RES obligations; however, the customers can also choose to retain the attributes. If they do so, they would need to return the value of the portion of the Value Stack that accounts for the environmental attributes of the project to the utility.

Miscellaneous rulings:

The order contained a few additional important items tucked in among its 157 pages. They are as follows:

  • The order allows mass market projects with an energy storage component to qualify for existing net metering or Phase One NEM compensation, but requires CDG, RNM or large on-site systems paired with energy storage to be compensated based on the Value Stack. The Commission also directed staff to work with NYSERDA and market participants to develop an Energy Storage Roadmap for further deployment of energy storage in New York.

  • The order requires NYSERDA to relinquish all rights to any environmental claims, certificates, attributes or other claims to energy produced by any system to which it provided financial incentives under the customer sited tier or the NY-Sun program.

  • The order requires that, to be eligible for the VDER Phase One Tariff—including Phase One NEM—all RNM, CDG and all on-site projects must be equipped with utility metering with hourly recording capabilities. Mass Market projects are not required to have such meters installed, but will need them if they choose to opt into Value Stack compensation.

  • The Order determined that, for projects compensated under the VDER Phase One Tariff, unused credits may be carried over to the next monthly billing period, including over the end of annual periods, but that any unused credits will be forfeited at the end of the project’s compensation term. For CDG projects, the order determined that CDG sponsors can only retain credits during a two-year grace period, after all extra credits have been distributed to customers. At the end of the two-year period, the sponsor will forfeit a number of credits equal to the smallest number of credits in its account at any point during the grace period.

The net effect of the changes on the New York distributed energy markets remains to be seen. Although proponents of the REV proceeding and value-driven pricing may see this as a step in the right direction, the variability in pricing in the Value Stack adds uncertainty to projects’ revenue streams, which could make projects more difficult to finance. The full impact of this proceeding will not be seen until the MTC values and the DRV/LSRVs are set over the next couple of weeks.

  1. Cases 15-E-0751 et al., Order on Net Energy Metering Transition, Phase One of Value of Distributed Energy Resources, and Related Matters, (March 9, 2017).
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  2. See Cases 14-E-0151 et al., Petition of Hudson Valley Clean Energy, Inc. for an Increase to the Net Metering Minimum Limitation at Central Hudson Gas & Electric Corporation, Order Raising Net Metering Minimum Caps, Requiring Tariff Revisions, Making Other Findings, and Establishing Further Procedures (issued December 15, 2014)
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  3. Order, at 19.
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  4. The amounts are: Central Hudson—30 MW, Orange & Rockland—25 MW, National Grid—100 MW, NYSEG—20 MW, ConEd—90 MW, and RG&E—5 MW
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  5. The caps are as follows: Central Hudson—39 MW, ConEd—137 MW, NYSEG—56 MW, National Grid—119 MW, O&R—23 MW, and RG&E—28 MW.
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  6. Order, at 94.
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  7. See Table 4 on page 131 of the order for the capacity limitations applicable to each utility.
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The foregoing has been prepared for the general information of clients and friends of the firm. It is not meant to provide legal advice with respect to any specific matter and should not be acted upon without professional counsel. If you have any questions or require any further information regarding these or other related matters, please contact your regular Nixon Peabody LLP representative. This material may be considered advertising under certain rules of professional conduct.

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