A new study by the National Renewable Energy Laboratory identifies challenges and makes recommendations for utilities implementing distributed energy resource (DER) aggregation programs.
For the study, “Expanding PV Value: Lessons Learned from Utility-led Distributed Energy Resource Aggregation in the United States,” NREL analyzed DER aggregation programs at five utilities.
Even though the characteristics of those programs vary widely in terms of design, scope and timelines, NREL found that a pattern of common challenges emerged.
NREL identified five categories of challenges: the development and implementation of software, called Distributed Energy Resource Management System or DERMS, to control DER aggregation; customer acquisition; DER deployment; communicating with DERs; and DER performance.
The most common challenge – faced by three of the five utilities studied – was the development and deployment of DERMS software, NREL found.
NREL undertook the study to “fill a gap” in the literature on the scope, performance, and lessons learned from utility-led DER aggregation. Distributed residential photovoltaic capacity in the United States has grown rapidly in the past several years, from about 0.4 GW in 2010 to 10.5 GW in 2017.
When those resources are aggregated, they can provide useful service to a utility’s grid, such as voltage support, frequency response and contingency response. If those nascent utility-led DER aggregation projects prove successful, they could open new value streams for solar power and other DERs and expand the deployment of DERs and transform the energy market, NREL said.
NREL identified 23 utility-led DER aggregation initiatives nationwide. The earliest project was begun by the Bonneville Power Administration in 2009, but most were launched after 2014. There are DER aggregation programs in more than a dozen states, but only Arizona, California and Hawaii have more than one program.
To illustrate the progress and challenges of utility-led DER aggregation programs NREL chose five utilities – Green Mountain Power, Maui Electric, Pacific Gas and Electric, Southern California Edison and the Sacramento Municipal Utility District – because they incorporated solar photovoltaic installations, published data on DER performance, and had diverse characteristics in terms of project capacities and the types of DERs involved.
Some of the utilities faced similar issues. For example, three of the five faced challenges with developing software to control disparate DER technologies. Often, however, the utilities’ experiences and challenges varied substantially. For instance, Green Mountain Power, PG&E, and SCE found that DERs performed as expected, while SMUD and Maui Electric found that performance varied.
In studying SMUD’s 2500 R Midtown project, NREL found that controlling DERs at 10 homes provided an average load reduction of 2.66 kW per house and an aggregate 44 kW of load-shifting capability at peak.
The project included 34 newly constructed single-family homes outfitted with a 2.25-kW PV array, an 11.7-kWh lithium-ion battery, a smart thermostat, and a “modlet.” Of the 34 homes, 10 agreed to let SMUD control their DERs.
According to the NREL study, SMUD had difficulty identifying cost-effective pathways to manage integration and data exchange across the utility and third-party platforms and that communication was hindered by third-parties wanting to protect proprietary information.
Communication was also an issue for Green Mountain Power’s DER aggregation program. For the McKnight Lane Redevelopment project, the Vermont utility replaced 14 manufactured housing units with seven net-zero energy modular duplex-homes. Each of the modular duplexes were equipped with a 6-kW solar array, a 4 kW, 6 kWh lithium-ion battery, as well as equipment such as heat pump water heaters and cold climate heat pump compressors.
The program met two of Green Mountain Power’s three goals, peak load reduction and transmission and distribution upgrade deferral. It was less successful in meeting the utility’s goal of arbitraging energy in the ISO New England’s day-ahead and real-time markets.
The main lesson learned from the program, according to the NREL study, was the difficulty in establishing communication between the batteries and the software controlling the DERs. In some cases, the equipment had to be replaced, but the utility still experienced communications problems that, in some cases, required manually resetting the equipment.
One of the key objectives of PG&E’s DER aggregation program was to predict and avoid constraints on its system. The results of the San Jose Distributed Energy Resource Demonstration project are still not public, but preliminary results demonstrated a proof of concept scenario.
Otherwise, PG&E’s San Jose DER project involves 124 kW of residential solar arrays, 66 kW of lithium-ion battery storage in 27 homes, and 360 kW of commercial lithium-ion battery storage at three commercial locations.
Among the lessons learned from the project, NREL said that once the DERs were deployed, PG&E faced challenges with communicating with remote DERs and that the residential internet connections that served as the communication link between PG&E and the DERs were not always consistent. In addition, PG&E reported cases of incorrect data or gaps in reported data, particularly when batteries were tripped offline.
In Hawaii, Maui Electric’s JumpStart program was able to aggregate DERs to provide grid services. The program included a standalone 153 kWh lithium ion battery, a standalone 576 kWh lead acid battery, 80 bidirectional chargers for electric vehicles at homes with rooftop solar arrays, and 10 smart inverters at rooftop solar homes.
In the program, each DER was used to demonstrate a different grid benefit. Among the results, NREL found that the 80 electric vehicles with bidirectional chargers had the most potential to maximize the consumption of renewable energy during times of peak solar generation.
However, using smart inverters to provide voltage support from solar panels proved to be difficult because safety standards that had not been finalized in time for the program limited the use of the smart inverters.
Maui Electric also faced difficulties in recruiting participants in the program because potential participants were concerned that they would lose net metering benefits if they installed batteries that would absorb energy that otherwise would generate net metering revenues.
Both the Maui Electric and the PG&E programs demonstrated the potential difficulties of recruiting customers to DER aggregation programs.
NREL recommended that utilities should consider how DER aggregation will impact or align with existing DER incentive structures so that potential customers see a net benefit of participation.
And citing the communications problems that were evident across the programs studied, NREL recommended that utilities will need to develop a software that can find cost effective ways to integrate DERs with different communication protocols.
The study is available here.
