California's recent blackouts revealed serious shortcomings in the state's energy transition planning, but may also have prompted a reconsideration of a distribution system resource that previously had a bad reputation.
Demand response (DR) failed California in its 2000-2001 energy crisis and left regulators inclined to call on it only in the most dire energy shortages. But the recent heatwave-induced rolling blackouts had billion-dollar-plus costs and the performance of a new kind of DR got policymakers' attention.
Preliminary data from a CPUC analysis of the blackouts suggests the still-small supply of flexible DR "contributed quite a bit to grid support," said CPUC Deputy Executive Director for Energy and Climate Policy Edward Randolph. "This is the first event in many years that required sustained demand response. The analysis of its performance will inform future decision-making."
"If California had already seriously embraced flexible demand response, it would not have even come close to blackouts," said Gridworks Executive Director and former California Public Utilities Commission (CPUC) Energy Advisor Matthew Tisdale.
If the CPUC analysis confirms flexible DR's potential, the resource will face new and bigger challenges because its value will change with increased use, according to Randolph, DR advocates, and a July 2020 study from Lawrence Berkeley National Laboratory (LBNL). That will add to the regulatory controversies about its value that have obstructed DR growth for years.
The need for flexible DR to manage peak demand is likely to grow as more of the economy is electrified and the need for and value of being able to shift and shed load becomes greater.
The value of flexibility
California's rising penetration of distributed energy resources (DERs) makes it a leader in discovering the value their flexibility can bring to power systems across the country.
Buildings use 75% of U.S. electricity and in some regions up to 80% of peak demand generation, LBNL reported. Making buildings more energy efficient and managing their energy usage with flexible distributed energy resources (DERs) can limit blackouts without compromising reliability.
"Demand flexibility is the capability of DERs to adjust a building's load profile across different timescales," according to LBNL. The strategies to do that are "the core" of grid-interactive efficient buildings (GEBs) and "the potential impacts are significant."
"Our aggregations of nearly 60,000 devices and appliances, including thermostats, batteries and home car chargers are bid into the CAISO market 10,000 times a day, like small power plants on standby all over the state."
GEBs use "smart technologies, including advanced controls and sensors," to "optimize" building energy use, LBNL added. The building's load profile can be adjusted by shedding, shifting or modulating load and supplying generation.
Nearly 200 GW of flexibility from both the traditional DR used for decades and new DER-driven flexible DR could reduce the projected 2030 U.S. peak load 20%, avoiding over $16 billion annually in costs, a 2019 Brattle Group study concluded.
"Modernizing conventional programs" can deliver 40% of that potential, but the other 60% is in "emerging" building automation technologies, Brattle Principal and study co-author Ryan Hledik added.
Where flexibility is working
DR's value in meeting August's "grid needs" was recognized in CPUC Energy Division Demand Response spokesperson Aloke Gupta's Sept. 3 email to demand response providers, in which Gupta called for their "continued support." The California Independent System Operator (CAISO) has similarly recognized and praised DR's contribution.
Utilities also took advantage of flexible DR during the recent shortages.
Residential and commercial-industrial customers "delivered" in response to the millions of Pacific Gas and Electric emails, phone calls and texts sent between Aug. 17 and 21, the utility's spokesperson Ari Vanrenen emailed. On Aug. 17, the utility's flexible DR programs dispatched about 480 large customers and about 1,500 capacity bids, and 234,450 customers earned rate rewards for load reductions.
Utilities across the country are beginning to discover the potential of flexible loads. In South Carolina, Duke and DER providers proposed adding customer-sited DR, and an Illinois Commerce Commission proceeding is considering a new approach to compensation.
In Massachusetts, Eversource Energy has had similar success with flexible DR launched in 2019, said Michael Goldman, the company's energy efficiency, regulatory, planning, and evaluation director.
Eversource's "portfolio of flexible loads" includes "customer-sited behind the meter assets" like smart thermostats, batteries, electric vehicles, smart appliances and traditional commercial-industrial loads.
Eversource used "tens of thousands" of distributed assets to reduce system peak demand by 100 MW to 200 MW in the program's first year, Goldman said. And "we are thinking about new use cases [for DER] to provide transmission or distribution system services."
"Making smart devices available and affordable to more customers would, however, be an investment in making California ready for the next heat wave."
Executive Director, Gridworks
California has seen both a growth in DR and a shift from the traditional approach, which focused on large corporate loads that respond to direct notification by the utility or system operator to curtail energy use.
California grew its 2003 DR capabilities of 1,485 MW to 2,732 MW by 2019, according to CPUC data provided by Randolph. But traditional DR diminished after 2015, when the commission turned toward flexible DR. Its pilot Demand Response Auction Mechanism (DRAM) mandated investor-owned utilities acquire flexible DR and it ruled that diesel-fueled backup generation could not serve state DR programs after 2017.
"The goals of demand response have shifted," CPUC's Randolph said. Because CPUC directives discouraged traditional DR, California's total DR growth fell, but "it is starting to build back up," he added. With new initiatives "there will be significant growth by 2021."
California's private sector has also shown the new flexible DR is viable.
OhmConnect is a private aggregator of customer-sited DR. Its 150,000 California customers answered calls over 200 days in 2019 and at times reduced state peak demand over 150 MW, OhmConnect CEO Cisco DeVries said. "Our aggregations of nearly 60,000 devices and appliances, including thermostats, batteries and home car chargers are bid into the CAISO market 10,000 times a day, like small power plants on standby all over the state," he said.
OhmConnect reduced over 200 MWh of load on Aug. 14 and 18, almost 200 MWh on Aug. 17, and almost one GWh of total energy usage from Aug. 13 to Aug. 20, DeVries reported. Its customers earned over $1.3 million for usage reductions and 739,000 adjustments to devices and appliances were made, including 580,000 done automatically with only 20 minutes notice and "without a single failure in dispatch."
OhmConnect "has spent seven years building the capability and technology to address load reduction and learning how to engage customers," DeVries said. "It is not easy, but we can now do it at scale, in real time, and in measurable and predictable ways."
The company is targeting 600 MW of California DR capability for summer 2021, or "more than half of what was needed during the blackouts," he added. Flexible DR "is the only way we can solve the blackout issue in the near term without fossil fuels."
On the blackouts' first day, smart battery provider Stem's deployments through the DRAM, Southern California Edison, and private contracts "supplied about 50 MW to customers, which reduced peak loads equivalent to taking 20,000 homes offline," said Ted Ko, Stem's vice president of policy and regulatory affairs.
But LBNL, advocates, and utilities said big challenges are ahead if flexible DR's real potential is to be realized.
The problem of success
"Utilities and regulators must confront technical and market complexities" to enable greater use of flexible DR, Brattle's Hledik said. Measuring its value will require metrics not necessary for traditional DR.
Performance assessments must "determine the timing, location, quantity, and quality of grid services," LBNL reported. The metrics must show system operators, utilities, building managers, and occupants that flexible DR can "optimize building performance."
Much assessment will be by comparison with a "counterfactual" or "baseline" quantification of what would have happened in the absence of flexible DR, LBNL said.
But when flexible DR events are called multiple times a week, defining that baseline will be harder, LBNL Electricity Markets and Policy Department Senior Advisor and paper co-author Steven Schiller said. Unlike traditional DR value, based on quantifiable past impacts, calculation of flexible DR value will require "automated analytics" to make complicated performance projections of changing loads and customer participation.
Non-event days "may not be a reasonable proxy for normal load when normal load is altered on a continuous basis," Eversource's Goldman agreed.
Some industry observers said flexible DR's potential will only be realized through rate reform.
Effective use of DR "has to start with efficient pricing," said CAISO Senior Manager for Infrastructure and Regulatory Policy John Goodin. "Customers must be exposed to time-varying, grid-informed, grid-supporting prices, and homes and buildings must be automated to use customers' preset preferences to react to price signals."
Smart technologies that can control flexible DR are available and companies like OhmConnect have shown how to unlock their value with time-varying pricing, GridLab Executive Director Ric O'Connell added. "But there is not a robust market that compensates providers and users for that value."
Instead of the complicated reliability rules that limit DR viability in California, Texas uses market signals to drive new investment "and wholesalers and retail distributors manage the risks of shortages and price spikes," O'Connell said. But "it makes a participation model for flexible DR, which may not be price-competitive with utility-scale renewables, more difficult, and we need to unlock its potential."
California has "a duct-taped, MacGyver-like resource adequacy system in need of overhaul."
Executive Director, GridLab
Customer engagement is "critical," but California should start with basic, easy things like more messaging to customers when load shedding is needed, not rate reform, Gridworks' Tisdale said. "Making smart devices available and affordable to more customers would, however, be an investment in making California ready for the next heat wave," he agreed.
The biggest obstacle to advancing flexible DR is California's regulatory and legislative apparatus, Goodin, O'Connell, Tisdale and Randolph agreed.
MacGyver's duct tape
California has "a duct-taped, MacGyver-like resource adequacy system in need of overhaul," GridLab's O'Connell said. "Our generation mix is changing dramatically, and the blackouts are part of a complicated transition," but "the way we address change now will not serve us going forward."
Measures to improve compensation to customers for adding flexible DR devices, now stalled before the CPUC, should be advanced, flexible DR advocates said.
Stem could have provided twice the 50 MW load reduction it delivered if rules recognized and compensated the multiple uses of batteries and allowed export of stored energy to the grid, Ko said. "A 2017 LBNL study for the CPUC called the flexibility of customer-sited battery storage 'the ideal DR technology,' but the commission did not follow through," he added.
The 2017 study did show the need for more flexible DR and storage, CPUC's Randolph acknowledged. But rules that apply to flexible DR are "fundamentally different" than those for "event-based" DR, and commission rules calling and compensating flexible DR must be consistent with "the ISO's specific need" for resources to be available when called.
The uncertainties about flexible DR have slowed development of participation rules, but its potential, especially of automated DR, "is becoming clear and we need to move faster," he added. Those rules will not, however, change "tomorrow" because providers "might not be able to meet them that fast."
A major commission failure was curtailing the DRAM program, OhmConnect's DeVries and Stem's Ko said.
The DRAM was intended to help scale flexible automated DR, and it was imperfect, but inadequate fixes to procurement processes were made, DeVries said.
If those procurement changes on incentives had not been made, there might have been "as much as 300 MW more commercial sector storage available to respond to the blackouts," Ko added.
"The DRAM pilot project did not perform well initially but was extended, with rule and process changes," CPUC's Randolph replied. Because "some providers still could not meet their contractual obligations," it was reduced "to protect ratepayers."
"These events are the first big test of this kind of demand response and now we will have a lot more knowledge to work with."
Deputy Executive Director for Energy and Climate Policy, CPUC
More recently, new DR providers, using "a new type of customer and new technologies, are matching or exceeding their obligations," he added.
A 2019 CPUC "Load Shift" study suggested that from 2025 on, over $600 million per year could be saved with load shifting strategies to integrate more renewables and support reliability, Tisdale said. "But caution about the DRAM program's $10 million budget contributed to a billion dollar or more power outage. We need to be much bolder."
California "can no longer afford to be timid in readying the power system for massive climate changes," he added. "We can learn from our mistakes. The only thing that will stop us is timidity. Timidity and incrementalism got us blackouts, so why not try boldness?"
It is fair to criticize regulators for being too risk averse, CPUC's Randolph acknowledged. "But rules protecting reliability are one of the most fundamental things regulators must get right to keep the lights on. We have to be very conservative around those rules."
Regulators must, however, "avoid stifling innovation and potential market transformation," he agreed. "That is why we are doing a deep analysis of the blackouts' root causes. These events are the first big test of this kind of demand response and now we will have a lot more knowledge to work with."