Getting Grid Modernization Right
EMPOWERING CONSUMERS RATHER THAN GOLD PLATING CALIFORNIA’s GRID
It has been almost three years since Southern California Edison (SCE) requested authorization from the California Public Utilities Commission (CPUC) to spend nearly $1.9 billion on grid modernization. SCE argued massive new investments in grid modernization were needed for three reasons; 1) to improve electric system reliability and outage restoration, 2) to enable customers to quickly install distributed energy resources (DERs) like solar and storage, and 3) to support the use of DERs for the delivery of grid services like voltage support. To support its campaign for grid modernization SCE published a white paper entitled “The Emerging Clean Energy Economy: Customer-Driven, Modernized, Reliable”.
In 2009, the Legislature defined grid modernization for the CPUC under the rubric of a Smart Grid capable of utilizing “advances in technology to create a safer, greener, more efficient, and more reliable electricity supply.” The Public Utilities (PU) Code lists ten characteristics of a Smart Grid that include increased automation and advanced controls, dynamic optimization of grid assets, integration of renewable energy, cyber security, consumer transparency, and the deployment and utilization of demand side resources, or DERs. AB 327 (Perea 2013) goes on to define DERs and sets a standard of “cost-effective” and “just and reasonable” as necessary for approval of utility spending and cost-recovery for grid modernization (PU Code §769(a)-(d)). The CPUC’s clear guidance supports SCE’s three-point justification, but requires utilities to do so with a minimum of expense taking advantage of the inherent cost-savings potential of DERs.
While the proposed goals of the SCE grid modernization were laudable, the costs included in the plan were not. In the most recent SCE general rate case, Vote Solar along with The Utility Reform Network (TURN) and the Office of Ratepayer Advocate (ORA) argued that most of SCE’s proposed grid modernization investments were not justified. We testified that SCE had not demonstrated net benefits for ratepayers in investments in grid automation and utility-owned communication infrastructure. We also pointed out and that the plan failed to account for opportunities to use DERs and other third party services to minimize costs.
Recommendations from the Administrative Law Judge (ALJ) in the case came down strongly against major elements of SCE’s proposed modernization plan. Instead of the $1.9 billion SCE asked for, the ALJ recommended that the CPUC approve just $613 million to further automate SCE’s distribution grid, upgrade its communication system and develop software for data analysis and decision making.
Vote Solar, along with TURN and ORA, took strong exception to the proposed goldplating of grid automation. There is nothing new about remotely controlling the operation of the grid. About three-quarters of SCE’s distribution system is already automated to some degree. The typical SCE distribution circuit has a remote controlled mid-point switch and a second remote controlled circuit-tie switch linked to a neighboring circuit. The first switch is normally closed and the second open. But they can be reconfigured to isolate segments and allow for load transfers to the adjacent circuit when a branch falls on a line or a car runs into a pole. This remote switching is done to minimize the number of customers experiencing an outage during a fault on the system.
In its grid modernization plan SCE proposed to equip around 20% of its circuits with up to three mid-point switches and three circuit-tie switches along with fault sensors at a cost of nearly one million dollars per circuit. SCE initially argued that all this automation was needed so they could see what was happening on the grid in real time with many DERs on the system. They claimed these investments would minimize disruptions and to maintain reliability. However, when asked by Vote Solar whether SCE could name another utility that had adopted a similar approach to automation, they were unable to do so. Nearly three-quarters of SCE’s proposed investment in automation was rejected by the ALJ as unjustified.
Likewise, SCE was unable to justify much of its plan to upgrade its internal communication infrastructure. Their proposal to spend $314 million to further automate their substations was not demonstrated as cost effective. Another $117 million for installing fiber optic cable to connect substations and control centers was also found unnecessary for the immediate future.
Vote Solar argued that it is important that SCE and other utilities to use existing and emerging third-party communications for the control and dispatch of DERs as much as possible. By using third-party communications, utilities can minimize redundancy and avoid creating stranded costs that end up raising electric bills. Vote Solar pointed out that utilities have used third-party radio networks for decades to switch on and off air conditioning and water heating as a way of directly managing load. The CPUC’s deferral of SCE investments in communication and control infrastructure at this time can open up opportunities for the use of lower cost third-party communication infrastructure in the future.
Early in the general rate case Vote Solar convinced SCE that its proposal to spend $129 million over three years to quickly replace 588 protective relays on it subtransmission system was unsupported by reasonable factual analysis. SCE had argued that its forecast of rapid growth in DER installations indicated that there could be significant reverse power flows on the grid which could damage vulnerable relays needed to protect the electric system. However, when asked to identify the specific times when each individual relay might be overloaded, SCE responded it was not able to accurately predict the timing. SCE decided it would be more appropriate to replace the relays over time as part on its normal replacement program.
One area of ongoing dispute with SCE has been over a photovoltaic (PV) dependability study it conducted. This study was used to determine the peak load forecast on sections of SCE’s distribution system. As more solar is installed it can be expected that peak demand on wires and transformers will be lower. Vote Solar argued that the method and data SCE used in its PV dependability study were flawed and resulted in forecasted needs for more distribution capacity upgrades than actually were required. While the ALJ acknowledged that our concerns were valid they decided not to force SCE to immediately correct its errors in the current general rate case. Vote Solar will seek to establish a common approach among California’s utilities on PV dependability in another regulatory proceeding so that California utilities do not systematically overbuild their distribution systems.
In one area Vote Solar agreed with SCE that there was a need for new software that can be used to facilitate the increased adoption and use of DERs. The new software will enable SCE to perform more precise and frequent power flow and capacity analyses of the electric system that will both improve operation of the grid and allow for the installation and optimal use of more DERs. Similarly, SCE’s proposed DRP external portal should result in an interactive website for customers to access interconnection capacities circuit by circuit on the SCE distribution grid.
A final decision by the CPUC on SCE’s general rate case is expected in the near future. Vote Solar’s involvement in the case has been recognized by the ALJ as making an important contribution to the record and qualifies Vote Solar for intervenor compensation. Vote Solar is now pivoting to reviewing PG&E’s grid modernization plan and preparing testimony in that general rate case with a goal of assuring that costs are reasonable and support more comprehensive use of DERs.