Demand response has traditionally been a fairly simple product, but rapid changes to grid architecture and resources are driving fundamental changes. In the future, curtailing peak load as we now know it simply won't have much value.
That's one of the revelatory findings from a recent report on California's demand response potential, which concludes the state has gigawatt-hours of flexibility in its industries, businesses and homes. But efficiently harnessing it will require a better understanding of what the state's energy future will look like.
The research, from Lawrence Berkeley National Laboratory (LBNL) and Energy and Environmental Economics (E3), broke down load profiles from almost 25 million investor-owned utility customers. It generated data sets so large that researchers had difficulty downloading them. And the results were surprising, reflecting how a rapidly changing resource mix is impacting future needs.
"When we heard shed has little-to-no value, our heads were spinning," said Mark Martinez, a senior manager for Southern California Edison. "We said, 'wait a minute, this is what DR does. This is how we save the grid.'"
Martinez manages SCE's emerging markets and technology programs, and recently discussed the study findings in a conference call hosted by the Peak Load Management Alliance. He said the results challenged researchers' initial assumptions.
"It's important to remember," he explained, "that in California we have a very strong renewable portfolio. Meaning there is a lot of renewable generation planning to occur in the future. So the need for actual clipping peak (demand) may not exist or be there."
The study attempts to quantify the value of demand response in new ways, looking beyond specific tariffs and time-of-use rates to a reimagining of what function load management can have. The report takes a look at demand types in a more "nuanced" way, reflecting grid needs: shape, shift, shed, and shimmy.
"Shed" is the more traditional demand response production: it describes loads that can be curtailed to provide peak capacity and support the system in emergency or contingency events. "Shape" captures demand that reshapes customer load profiles, and "shift" nudges customers to move energy consumption to times when there is a surplus of renewable generation.
"The value of shed as a resource is at the distribution level," said Jennie Potter, a senior engineer associate at LBNL and lead on the report.
"Shimmy" is the most emerging service: researchers say it involves harnessing loads to mitigate short-run ramps and disturbances, and can respond in as little as four seconds. Potter said about 300 MW are cost effective, in 2025, generating $25 million in value.
Shape and shift can be modeled similarly, depending on the desired outcome, and the report found the potential DR was approximately 1.8 GWh per day for 2025, "indicating that significant load can be shifted throughout the day with price signals from retail rates."
The report found 15 to 20 GWh of daily load shift could provide "upwards $500 million in value to California ratepayers," Potter said.
Demand response value is in timing and location, not load
The report finds there "are many opportunities for flexible loads to provide value to the operation of a renewably powered electricity system," but also concludes the value will not look like it does today. A greater integration of renewable resources will shift peak needs, and new demand will alter load curves.
At SCE, for example, Martinez said the utility is changing its definition of "peak" from the traditional noon to 6 p.m. timeframe to 4 p.m. to 9 p.m., to account for changes in costs.
Combined with energy efficiency, the LBNL report concludes there will be sufficient generation available during net load peak times to meet system-wide demand, "and therefore no opportunity for accounting for value from avoided investment in new capacity."
But that was, for years, the underlying principle of demand response. Going forward, however, new resources and needs mean grid services will be a key driver of demand response opportunity.
"The value of DR is at the locational level, at the distribution level," said Martinez. "This is probably the next step for demand response, looking at locational resource needs. That was one of the big takeaways in the report. ... we are looking at locational net benefits of distribution services at the grid level."
There are still opportunities for shed-load to provide value, according to the report, but it will be specific to distribution-level circuits.
"While there is a surplus on the system level, the local availability of generation is still binding in some transmission-constrained areas," the report said. The Los Angeles Basin and San Diego and Ventura counties all currently experience local capacity constraints that must be met either with expensive local generation, energy storage or other demand-side management programs.
About half of the California's shed resource, as much as 7 GW, depending on the scenario, is located in these areas.
The report also concludes fast shed resources have the ability to help "meet the needs of the distribution system and avoid investment and maintenance is another important future application." In 2025, LBNL models significant renewable capacity contributing to the system's supply—customer-sited solar becomes a larger contributor to mid-day supply, meaning other generators must be ramped down to prevent curtailment.
EVs as a resource
If distributed solar represents one of the most significant new resource additions, electric vehicles are the demand that goes with it. Electrification of the transportation sector is widely seen as a way to slash emissions, and the demand it generates will be flexible and predictable.
While utilities facing stagnant load have looked to EVs as a new source of revenue, it may be the charging infrastructure and ability to move the demand that generates the most value. That flexibility helps and highlight why utilities are in such a rush to roll out charging ports and move into a new kind of business.
California's three large investor-owned utilities have proposed a $1 billion rollout of electric vehicle charging infrastructure, including expanded fleets, tens of thousands of charge points and residential rebates. Transportation accounts for about 40% of greenhouse gas emissions in the state, and California wants to reduce emissions 40% below 1990 levels by 2030.
Using EVs as a "shift" resource will require utilities to be able to move that demand through price signals and programs, generally helping consumers avoid charging in the early-evening hours.
"This highlights the value of charging infrastructure, since while some [s]hift is possible with at-home charging scheduling, it would be important to have significant charging infrastructure available to enable daytime charging as well," the LBNL report found. Commercial charging stations, along with workplace and public ports, are the near-term technology deployments needed.
The research showed residential electric vehicles can provide demand response services ranging from 30 to 38 MWh/year from battery electric vehicles, and as much as 83 MWh/year from plug-in hybrid vehicles. For commercial EVs, available Shift DR resources include 7-8 MWh/year for BEVs, 2-3 MWh/year for PHEVs and an additional 3 MWh/year for BEV charging at work.
EV Shift service is cost competitive with prices ranging from $28-$30 per kWh-yr, LBNL found.
Electric vehicles, along with behind the meter storage and other new load categories, "could also significantly alter the dynamics of price sensitivity," the report concludes. And harnessing them can be achieved through new pricing programs: combining battery storage, advanced controls, and retail prices that incentivize arbitrage. That, in turn, "could lead to a dynamic where significant fractions of the Shed and Shift we describe in the DR potential supply curves is achievable through retail prices alone."