Hawaii Solicits Input on Utility’s Proffered Strategy

The Hawaii Public Utilities Commission has released for comment a report submitted by the Hawaiian Electric Companies (HEC) in which they detail their proposed grid modernization plan. The commission said the 114-page report describes the scope, purpose, and estimated cost of the work the companies view as necessary for updating their energy networks over the next six years. The utility group asserted that the improvements will help the five islands served by the companies achieve a level of 48% renewable energy by 2020, as required by state law. Because state energy policy now also sets forth a renewable portfolio standard (RPS) of 100% reliance on clean, green resources by 2045, HEC maintained that it was critical to start modernizing its power grid now, as attainment of the state's RPS goal depends on a combination of resources, both customer-owned distributed resources and larger grid-scale resources.

In the report, the companies state that their plan envisions use of advanced technologies to modernize the existing grid into a state-of-the-art "cyber-physical" platform that will enable the integration and optimal utilization of customer-installed systems through existing and new distributed energy resource (DER) and demand response (DR) programs, at a cost 32% lower than a more traditional "wires alternative." As one example of how a phased cost/benefit approach might be used to balance both short- and long-term ratepayer interests, the utilities pointed to systemwide deployment of smart meters. 

The utility group noted that systemwide deployment produces economies of scale for purposes of installation costs but also assures ongoing operational savings due to reduced manual meter reading expenses. At the same time, though, they cautioned that such economies of scale are not always sufficient to yield benefits that exceed the cost of the system. 

Citing recent changes in state energy policy, HEC related that there already has been significant growth in customer-premised DERs, accounting for approximately 600 megawatts across the companies' service areas. Such facilities have resulted in overall system and individual circuit penetration levels higher than those experienced in any other part of the world, the companies said. Indeed, they averred that the rate of growth has outpaced their ability to properly address technical and operational issues at all levels of the grid: bulk generation, transmission, and distribution. They therefore warned that rapid changes in the operating characteristics of the power system is challenging the operational capability of the system to provide essential services and maintain the safety and reliability of electric supply in Hawaii. 

According to the report, nearly 80,000 privately owned rooftop solar systems deliver electricity to the grid for delivery to other customers. That extensive level of customer participation in DER has transformed what was traditionally a steady, one-way flow of electricity into a dynamic, two-way stream of power, shifting back and forth between the customer and the utility. 

The utilities concluded that without real-time data, visibility, and control, operators can only estimate how much power such rooftop solar systems are feeding into the grid. Consequently, HEC stated, the utilities have very little ability to assist in identifying and averting situations that can affect the safe and reliable delivery of power to all customers. 

The strategy presented in the report involves a multi-level, phased approach to modernization, with an ultimate objective of assuring that the growing amount of distributed generation can always be accommodated. To that end, the utilities identified various cost/benefit tests through which to address the pace and prioritization of investments on both a neartime basis and for the long term. 

The cost of the first phase was pegged at about $205 million over six years, with the focus of that near-term work being on the following: 

1. Reliance on advanced inverter technology to enable greater private rooftop solar adoption; 
2. Expanded use of voltage management tools, especially on circuits with heavy solar penetration; 
3. Strategic distribution of advanced meters rather than systemwide deployment, primarily for enhanced sensing and monitoring purposes; 
4. Expanded use of sensors at other points on the grid and automated controls at the substation and neighborhood circuit levels; 
5. Expansion of a communication network enabling greater operational visibility; and 
6. Enhanced outage management and notification technology. 

Of the cost models considered, the utilities determined that the "lowest reasonable cost" method would be the most practical means for assessing investments to build the core modern distribution platform. The companies related that they anticipate using evaluations of reasonableness (or "best-fit") to narrow the range of options for certain core platform technologies (e.g., sensing and measurement, communications, and controls/ automation). 

The HEC report states that while cost is a primary evaluation metric for that type of review, other attributes of the assets are considered as well, such as the ability to enable future functionality. Under such a testing regime, they said, the selected capital initiatives may not be the strictly lowest-cost options. Instead, safety and reliability needs may become a factor. For instance, such projects as infrastructure replacements, which are aimed primarily at guaranteeing ongoing safe and reliable service, may be given equal or greater weight than cost. 

For investments that are neither self-supporting projects nor required for RPS compliance purposes, the utilities recommended use of a total resource cost (TRC) framework. They contended that TRC analyses could be done as part of the ongoing integrated grid planning process that evaluates the net benefits of resources and investments that are necessary to integrate these resources. Under such a scenario, the benefits associated with the resources and the grid investments are offsetting costs to yield a net benefit for customers. 

Under the investment strategy suggested by the utilities, self-supporting investments would be paid for mostly by participating customers, and any utility contribution or incentive would be limited to the net benefits that would be expected to accrue to nonparticipants. The companies emphasized that the self-supporting program would be designed to prevent cost-shifting from participants to nonparticipants. The programs also would be based on the customer's choice to participate. 

As an example of a self-supporting project, HEC pointed to customer utilization of electric vehicles (EVs) and installation of related premisessited EV charging systems. The companies stated that the costs of any associated electrical wiring would be borne by the EV customer. 

That is, the report indicates an expectation that while EV rates and incentives may be available toward the purchase of an EV, the primary costs of ownership would be the customer's responsibility alone. Modernizing Hawaii's Grid for Our Customers, Report by the Hawaiian Electric Companies, Aug. 29, 2017.