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In New Hampshire parties filed comments on scoping document initial data points. 

Joint Participants, including ReVision, recommends amending “the current net metering [NEM] and distributed energy generation [DG] regulatory scheme” by: (i) “providing a fixed legacy period tied to the date that a customer generator begins operating”; (ii) “enabling larger facilities to receive compensation consistent with their value to the grid are critical to enabling New Hampshire to benefit from broader deployment of DER”; and (iii) creating “a market structure that compensates customer-sited storage for excess electricity that is discharged onto the grid, irrespective of whether the storage is paired with” DG, possibly by establishing “time-varying rates for customer-sited storage”

Joint Parties and Community Power Coalition of New Hampshire (CPCNH) supported adjustments to time of use (TOU) rates “to shift electricity production and consumption (potentially also through storage) to periods of high demand and solar output,” noting that “any system coupled with storage may optimize the timing of discharge to the grid of surplus behind-the-meter (BTM) production to maximize value”; (3) CPCNH said that a benefit that “the VDER Study not consider that should be included in the quantification of the benefits provided by” DG is BTM solar’s “contribution to peak load reduction at the hour of monthly system peak,” and Joint Parties said unidentified benefits include: (i) “System upgrades funded by customer-generators”; and (ii) NEM credit and REC price suppression.

In response to a question concerning utilities ensuring “any costs associated with [NEM and DER] are adequately accounted for in determining compensation for customer-generators,” CPCNH said that “[a] more efficient way to do this would be to enable the competitive market to compete with regulated utility net metering to offer the most cost-effective programs and offer compensation structures desirable to customers with DERs based on temporal price signals and corresponding rates that reflect the full value stack of benefits produced.” 

Joint Parties said that “Implementation of a TOU rate may require increased utility investment in metering and billing infrastructure,” noting that NHPUC previously rejected as too expensive to implement Eversource proposals for “a three-period commercial… and a two-period residential EV TOU rate,” and CPCNH said that “To optimize the value of storage, implementation of a 3-part time of use rate and corresponding metering is likely the minimum change needed… [and] To achieve greater value hourly or even 5-minute interval metering and dynamic [discharge and charging rates] with avoided capacity and transmission credits based on actual discharge at hours of monthly and annual coincident peak demand could be most effective,” additionally noting that “Such energy and energy capacity value might best be offered by competitive suppliers… assuming load settlement was reformed to account for such export interval data.”

Eversource Comments – In responding to question as to whether it is possible and/or practical to implement the changes contemplated in RSA 362-A:9, XXI(a) given the current process for estimating and settling load in New England?  The utility stated that “It is not currently possible to implement these changes, and making it possible would be terribly impractical, costly, and of little to no benefit to anyone, particularly not customers, as it would only increase energy costs without adding any tangible customer benefit. Energy exports of individual customers are not currently assigned to specific suppliers of energy to reduce their load obligation, and that is not how load is currently settled anywhere in New England. Because exports are currently allocated to suppliers in a different manner, they are already receiving the benefit of those exports. To change how customer exports would be applied to supplier load obligations would be costly and onerous, and the only possible benefit to anyone is that a supplier of energy, if that supplier were to somehow capture an extremely large percentage of customer exports in a given utility’s service territory, would see its load reduced more, although how much more is unclear. What is clear is that while that one supplier would benefit, all other suppliers would have to pick up the load obligation of the supplier whose load was reduced. And no benefits flow through directly to customers, yet customers would be paying more for their energy due to the costly changes necessary to implement modifications to load settlement. Simply put, modifying load settlement in this way is a pure cost shift – there are no net benefits realized, and no benefits of any kind flow through to end-use customers.”

Unitil  – “The Company is not aware of any specific limitations of the current net metering and distributed energy generation regulatory schemes, beyond the eligibility requirements established.”

“Energy exports of individual customers are not currently assigned to specific suppliers of energy to reduce their load obligation, and that is not how load is currently settled anywhere in New England. Because exports are currently allocated to suppliers in a different manner, they are already receiving the benefit of those exports. To change how customer exports would be applied to supplier load obligations would be costly and onerous, and the only possible benefit to anyone is that a supplier of energy, if that supplier were to somehow capture an extremely large percentage of customer exports in a given utility’s service territory, would see its load reduced more, although how much more is unclear. While that one supplier would benefit, all other suppliers would have to pick up the load obligation of the supplier whose load was reduced. And no benefits flow through directly to customers, yet customers would be paying more for their energy due to the costly changes necessary to implement modifications to load settlement. Simply put, modifying load settlement in this way is a pure cost shift; there are no net benefits realized, and no benefits of any kind flow through to end-use customers.”

Next Steps:

• Replies to comments on scoping document initial data points due by November 3, 2025.
• Preliminary technical session scheduled for 9:00 a.m. ET on November 18, 2025.

IR 25-031
(Investigation Into Distributed Generation and Net Metering in New Hampshire)