by Mike DeBlasi | August 6, 2019 11:30 am
New Hampshire, like the rest of the nation, is seeing increased deployment of distributed energy resources (DER). DER are electricity resources or controllable loads that are directly connected to the local distribution system (i.e., the poles and wires that deliver electricity to customers). These resources are typically smaller in scale than traditional generation facilities such as nuclear or fossil fuel-fired power plants and include solar panels, combined heat and power plants, battery storage units and small natural gas-fired generators. As more DERs are deployed, there is a heightened need for modernizing the electric grid to accommodate them.
The New Hampshire Public Utilities Commission (PUC) has been investigating grid modernization since 2015. In March of 2017, a PUC working group issued a report entitled “Grid Modernization in New Hampshire” which presented consensus recommendations on many issues but did not specify next steps. Thereafter, PUC Staff continued to conduct research and participated in training and discussions on a methodology for the development of a grid modernization framework that aligns utility investment plans with grid modernization objectives. Based on those efforts, Staff issued a comprehensive white paper on January 31, 2019 identifying grid modernization objectives that include: improving the reliability, resiliency, and operational efficiency of the distribution system; facilitating integration of DER; keeping New Hampshire technologically innovative, economically competitive and in step with the region; and reducing environmental impacts.
One of Staff’s key recommendations is that as part of their least-cost integrated resource plans (LCIRPs), utilities should submit integrated distribution plans (IDPs) containing 5-and 10-year road maps for integrating DERs at varying levels while ensuring system reliability, resiliency, and safety. Utility LCIRPs are not new – they have been mandated by NH RSA 378:38 since 1990. LCIRPs must be submitted to the PUC biennially and must include, among other things: a demand forecast; a supply assessment (including renewable energy and DER); and an assessment of distribution and transmission requirements (including costs and benefits of “smart grid” technologies and programs designed to ensure a reliable and resilient grid to prevent or minimize power outages). Thus, this long-standing statutory LCIRP requirement provides the PUC with an appropriate mechanism for assuring that utilities address improvements needed for accommodating anticipated DER growth and new technologies, in addition to the traditional supply and demand activities that typically impact the distribution system.
The PUC has not yet determined the process for evaluating grid modernization issues but has indicated that it may be open to non-adjudicative processes such as alternative dispute resolution, paper submissions, and any other processes that will lead to efficient presentation and resolution of disputed issues.
About the Author: Susan Geiger[1]
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