The top priority of a California microgrid proceeding is to reduce impacts on customers of the public safety power shutoffs (PSPS), implemented by the utilities to reduce wildfire risks. But bids in response to solicitations by the state’s two biggest investor-owned utilities (IOUs) found only temporary microgrid deployments are financially viable and none will meet clean energy advocates’ call for including customer-owned distributed energy resources (DER).
The utilities want to place fossil fuel generators at priority substations “for powering the communities behind them,” Senior Public Policy Director and Deputy General Counsel Melissa Brandt of community choice aggregator (CCA) East Bay Community Energy (EBCE) told Utility Dive. The other approach, from clean energy advocates, would “maximize the local benefit” and “protect California’s climate goals.”
In 2018 and 2019, Pacific Gas & Electric (PG&E) and Southern California Edison (SCE) encountered customer backlash when they shut off power to customers to prevent wildfires. In response, California regulators have focused on implementing 2018’s Senate Bill (SB) 1339 requirement to drive microgrid commercialization. But that will take time and money, even with leveraging customers’ DER, the IOUs told Utility Dive.
For 2020, PG&E and SCE’s high costs and the urgency of the approaching wildfire season make it necessary to focus on microgrids that rely on temporary fossil fuel-powered solutions, they said. In 2021, stakeholders expect to return to the debate about their differing approaches to permanent microgrids.
In October 2018, PG&E, faced with a wildfire threat, shut off high risk area power lines that might spark fires. Medical emergencies, business losses, and customer protests followed, but not fires. That November, facing another wildfire threat, PG&E chose not to impose shutoffs. The Camp Fire followed, killing 86 people and destroying 18,661 structures.
“The best case scenario would cost about 13 times more than alternative solutions and would not include clean energy technologies, so we have decided not to move forward with a microgrid deployment for the 2020 wildfire season.”
Director of Energy Policy, Southern California Edison
A microgrid is any “interconnected system of loads and energy resources,” that can “act as a single, controllable entity,” according to SB 1339. It must “connect to, disconnect from, or run in parallel with, larger portions of the electrical grid” and use DER and other power system tools to “maintain electrical supply to connected critical infrastructure” during “larger disturbances.”
The microgrid framework should “accomplish the state’s broader policy goals,” according to the order, including reducing greenhouse gas emissions, adapting to climate change, and protecting the health and safety of Californians.
The order required a framework for microgrid deployment based on proposals from PG&E, SCE and San Diego Gas and Electric (SDG&E), the state’s three major IOUs. The CPUC’s December 2019 Track 1 ruling and a subsequent ruling required IOU proposals by January 2020.
IOU responses differed, but PG&E and SCE — without reference to the current health and financial emergencies caused by the novel coronavirus — agreed they can’t do anything ambitious on microgrids this year.
SCE‘s proposal identified six potential microgrid sites likely to reduce the frequency, duration and number of customers impacted by PSPSs. The utility sought “cost and technical feasibility information from vendors” for microgrids that could be online by fall 2020 and designed to allow future upgrades in favor of better solutions.
Responses from “a robust set of qualified vendors” showed that “building a microgrid for 2020 is cost prohibitive, because of the limited deployment timeframe,” Southern California Edison Director of Energy Policy Shinjini Menon told Utility Dive.
“The proposals were for diesel-powered microgrids, and ranged in cost from $15 million to $30 million, depending on the location,” Menon said. “The best case scenario would cost about 13 times more than alternative solutions and would not include clean energy technologies, so we have decided not to move forward with a microgrid deployment for the 2020 wildfire season.”
Instead of microgrids, SCE will work on grid hardening measures, like covering conductors and increasing the sectionalization capabilities that allow utilities to reduce the size of system sections affected by PSPSs, Menon said.
“Maybe diesel is part of the solution, but if we talk in advance, we might be able to mitigate reliance on it.”
Senior Public Policy Director and Deputy General Counsel, East Bay Community Energy
“We will also procure more mobile backup diesel generators for PSPS-impacted circuits and assist customers in obtaining battery storage,” she added. “We have been in regular contact with the communities and the CCAs where microgrids were proposed and we are working closely with them on the viable mitigations for this year and beyond.”
SCE’s provisions for future upgrades, for only temporary use of diesel generators, and for incorporating customer-sited resources are three of “many good attributes” in its proposal, Vote Solar Senior Director for Grid Integration Ed Smeloff told Utility Dive.
“SCE is proceeding prudently and acting in the best interest of ratepayers to not pursue permanent fossil fueled microgrid solutions,” Smeloff said. But SCE should “consider public health and clean air benefits in the cost-effectiveness of clean technology solutions.”
PG&E‘s January proposal drew significant pushback from stakeholders for its emphasis on fossil fuels and for the utility’s limited consideration of clean energy alternatives proposed by CCAs and local governments.
Its primary request was for CPUC approval of $135.2 million to build permanent make-ready infrastructure for microgrid interconnections at 20 high-priority substations, its January 2020 filing reported. But stakeholders said the proposal would lead to permanent natural gas infrastructure at the substations.
After a limited response from microgrid vendors to its December 2019 solicitation and feedback from dissatisfied stakeholders, “we have decided to not move forward with the original microgrid proposal,” Pacific Gas and Electric Director for Grid Innovations Quinn Nakayama told Utility Dive. “We concluded it is not feasible to execute it by June of 2020.”
For 2020 PSPSs, PG&E will use temporary mobile generators run with renewable diesel fuel derived from vegetable oil at strategic locations, Nakayama said. “We are now going to pivot to a make-ready-lite program with temporary generation islanding capability, potentially for more than the original 20 substations.”
PG&E studies showed that alternative proposals would not be suitable for the network architecture in many of the PSPS regions, Nakayama said. “We also heard from local government officials, communities and CCAs that they did not want the proposed fossil fuel generation and infrastructure at or near their substations.”
Thermal generation using renewable diesel fuel is “the only currently available and scalable option,” and PG&E “is working with partner vendors on fuel procurement,” he said. “We are also testing the use of temporary natural gas generators, but that will probably not be viable and scalable before 2021.”
Air quality impacts could upend PG&E and SCE plans to use diesel fuels, Electric Power Research Institute (EPRI) Senior DER Research Program Manager Haresh Kamath told Utility Dive. Because of California’s clean air standards, “utilities have not even tried to permit diesel generators in recent years and these proposals could force air quality agencies to choose between clean air and power outages.”
PG&E’s new 2020 plan will not encounter those clean air permitting obstacles, Nakayama responded. “This type of unit is permitted for temporary use by the state’s air quality agencies and was used in 2019 at several substations. The vendors for the new temporary portable generators will register them under the appropriate regulations and should not require additional permitting.”
PG&E’s initial plan to seek cost recovery for the microgrid investment in California’s Integrated Resource Planning (IRP) proceeding “remains on the table for 2021 and beyond,” he added. The original microgrid filing’s proposal that the permanent fossil generation be used both for PSPSs and to meet the utility’s Resource Adequacy (RA) obligations “is on hold” and “will be reassessed as we move forward,” Nakayama said.
PG&E’s decision to defer its move to permanent fossil fueled microgrids postpones but does not end the debate. “We will be closely tracking what PG&E proposes in the IRP proceeding,” Vote Solar’s Smeloff said.
PG&E’s failure to consult with local jurisdictions and their CCA energy providers was another major barrier to stakeholder acceptance of its original proposal, Smeloff, EBCE’s Brandt and other stakeholders agreed.
CCAs have worked with local public health and emergency safety agencies to identify “over 300 critical facilities and develop resilience systems,” EBCE’s Brandt said. “Maybe diesel is part of the solution, but if we talk in advance, we might be able to mitigate reliance on it.”
A January 2019 CPUC Energy Division Staff white paper also emphasized the importance to the commission of local government participation in microgrid solutions. It recommended better access to interconnections, to IOU system information for microgrid siting, and to customer compensation incentives for use of their DER in microgrids.
The importance of protecting those Staff recommendations from IOU modifications was stressed in the microgrid proceeding filing from CalCCA, the CCA trade association. “There are things IOUs and CCAs could work together on today,” EBCE’s Brandt said.
PG&E has done “a lot of listening and talking about grid resiliency with county and local elected officials” and has been “in close communication with the CCAs,” Nakayama said. “We are going to have further discussions to ensure our plans on resilience line up with their needs because that two-way conversation allows reaching more informed decisions.”
“We will be engaging with Sunrun and other vendors to study the technical feasibility of leveraging behind-the-meter and front-of-the-meter solutions,”
Director for Grid Innovations, PG&E
CCAs and PG&E have different strategic approaches because CCAs see resilience from an individual customer and behind-the-meter perspective and PG&E sees it at the substation from a grid perspective, he added. “But those perspectives can be coordinated to create the right microgrid strategies and resiliency solutions and there is definitely an appetite to partner with the CCAs.”
The decision to focus on “this new temporary generation strategy for 2020 gives us the greatest short-term impact and the most flexibility as we pivot toward solutions for 2021 and beyond,” Nakayama said.
A February white paper by Sunrun, the leading U.S. rooftop solar installer, proposed a collaboration by utilities and DER providers on a clean energy microgrid solution that could be what the IOUs and the other stakeholders are looking for in 2021 and beyond.
The perfect choice?
Switchgear can “disconnect distribution substations from the transmission grid” and the resulting “independent distribution grid” could function as a microgrid, Sunrun’s white paper said. Disconnections could be autonomous or controlled by the utility.
Execution would require collaboration by key power system stakeholders, Sunrun Vice President for Energy Services Audrey Lee told Utility Dive. “Homeowners’ distributed resources on that circuit installed by private providers could sustain the islanded system” and “substation control and communications systems would be installed and managed by the utility.”
The proposal cannot be in service for 2020 due to the operational complexities that would need to be agreed on by system stakeholders, “but investments in hardening the existing grid are not the same as investing in the future grid to reach California’s 2045 clean energy goals,” Lee added.
DER supplied by homeowners would reduce IOU microgrid costs, she said. “Ratepayers only pay for the substation hardware, which benefits them by providing resiliency and backup power during PSPSs.”
Sunrun’s concept is more relevant to PG&E’s proposal for substation-level microgrids, SCE’s Menon said.
But the problem for PG&E is the limited system control the concept offers, Nakayama said. It could lead to an energy supply-demand imbalance and “the microgrid would collapse.” But “we will be engaging with Sunrun and other vendors to study the technical feasibility of leveraging behind-the-meter and front-of-the-meter solutions,” he added.
The issue is not microgrids’ “technical potential, but the choices they present,” EPRI’s Kamath said. “Electric utilities are used to getting low-cost power whenever they need it,” but in “contingency situations,” there are trade-offs.
“In a distributed future, some of today’s proposals will be realities,” but the value of each of those solutions now is uncertain. “There may not be a perfect choice but only one that leads to what is next.”
CORRECTION: A previous version of this article misspelled the name of senior DER research program manager. His name is Haresh Kamath.