California Demonstrates that Distributed Energy Resources Can Solve Grid Problems
The shift away from utility-centric, top-down distribution system planning towards one that engages consumers and leverages the benefits of distributed energy resources is gathering momentum in California. Using distributed solar, battery storage, energy efficiency and demand response measures to lower the cost of delivering electricity just got an important boost. After more than two years of planning, competitive procurement and regulatory review, one of the state’s largest utilities, Southern California Edison (SCE), contracted for the development of four battery energy storage systems totaling 9.5 MW of peak capacity as a way to defer an estimated $10 million of distribution system upgrades in two communities in Southern California. This is a first for SCE and could lead to dozens of similar projects implemented across the state each year by California’s distribution utilities with hundreds of millions in annual savings for ratepayers.
The SCE contracts are part of a pilot project the California Public Utilities Commission (CPUC) authorized back in December 2016. The idea at the time was to examine whether distributed energy resources (DERs) like batteries, distributed generation and load shifting technologies could be deployed as cost-effective alternatives to conventional utility investments in equipment such as transformers and new distribution circuits to maintain reliable service for growing communities.
The CPUC directed each of the California’s three major investor-owned utilities to identify candidate projects and to conduct competitive solicitations for non-conventional solutions using DERs. PG&E identified a project at a Santa Rosa substation that was later damaged by the catastrophic Tubbs fire. They were granted permission by the CPUC to delay their pilot project. SDG&E’s proposed project did not lead to any compliant proposals according to a report the utility made to the CPUC. That left only SCE to follow through on the DER pilot project.
SCE initially identified three potential sites but narrowed those down to two because of changes in expected growth in one of the areas. SCE specified that DER solutions could include distributed generation (DG) or battery storage or a combination of the two on the utility-side of the meter, or customer-controlled DG with or without storage, energy efficiency, demand response measures or permanent load shift located behind-the-meter.
What makes these pilot projects so important is that they raise a fundamental question about the way that regulated distribution utilities will do business in the future. Traditionally, a utility investment in new distribution equipment would be included in a general rate case and if a need was demonstrated the utility would earn a profit while the equipment is being used. For the pilot projects the CPUC, recognizing that the utility would miss out on an opportunity to earn a profit on its investment, decided instead to allow the utility to earn four percent on the contract payments for DER solutions that were selected through a competitive bidding process.
For the longer run the CPUC needs to evaluate other mechanisms to incentivize utilities to contract for DERs for grid services. An advisory committee set up to oversee the pilot projects asked SCE to analyze how alternative incentive structures would allocate costs and benefits differently than the 4% of contract value incentive used in the pilot project. The advisory group recommended three alternative approaches for analysis: 1) a 4% incentive based on the cost estimate of the conventional solution, 2) sharing the savings between utilities and ratepayers amd 3) ratebasing an upfront payment to the DER vendor. The analysis SCE submitted in the public version of its report to the Commission is highly redacted. However, it can be seen that each of the alternative incentives would yield more earnings for the distribution utility than they will earn in the pilot project.
The two projects that SCE identified for the pilot were one near Palm Springs in the Mojave desert and another near Thousand Oaks along the coast, north of Los Angeles. Both of the communities are experiencing growth in housing and new businesses.
Serving the projected load growth around Palm Springs would conventionally require a new transformer and distribution circuit to avoid an overload at a local substation. Such utility upgrades would cost approximately $4.6 million to implement in order to reliably serve about 8,800 residential and business customers with a peak demand of 28 megawatts. The substation in 2020 was forecasted to be overloaded between 3 pm and 6 pm on the hottest summer days. By 2026 the overload was forecast to reach 2.5 MW without an upgrade.
At the Thousand Oaks site in Ventura County the overload would impact three 16kV circuits coming out of a distribution substation. The conventional solution would be to add a fourth circuit and redistribute the load. Installing a new 16 kV circuit was estimated to cost about $5.4 million. The four circuits would serve some 8,700 residential, business and agricultural customers. However, if the load on the existing circuits could be reduced at critical times the construction of the fourth circuit could be deferred.
SCE conducted a two-step solicitation process to identify the most suitable DER solutions to address these distribution problems. SCE received 161 responsive offers. The majority, 122, were for in front of the meter battery energy storage. Another 35 were for demand response measures, two were for energy efficiency and two were for combined DG/storage systems. SCE short-listed a number of projects which led to the negotiation of the selected offer.
SCE selected esVolta LP to provide four batteries, one located at the Palm Spring site and one each for the three distribution circuits at the Thousand Oaks site. The batteries vary in size from 1.5 MW to 3 MW. These projects are the first in a sizeable future market for DERs.
The CPUC has created an annual distribution resource planning process where each of the utilities is required to identify opportunities for cost-effective DER projects and then procure solutions through competitive solicitations or tariffs.
As the cost of solar, batteries, fuel cells and other clean energy technologies decline and the automation of demand response and load shifting technologies advance there will be increasing opportunities to use DER solutions instead of upgrading conventional infrastructure. However, In order to enable the transition to a more consumer-centric and resilient electric system the CPUC will need to streamline the DER procurement process used by utilities and adopt a cost recovery mechanism that makes utilities indifferent to choosing the least cost distribution system solutions to overcome grid constraints.