How energy providers can prepare for summer heat with innovative solutions
Contributed by Ben Paulos
Last summer’s record heat waves triggered a surge in power demand that maxed out supplies and led to outages across the West. This summer has brought renewed challenges though not (yet) as intense.
But rising temperatures from climate change are just one challenge. California and other states are pushing to use clean electricity to power vehicles and buildings to cut carbon, which will increase demand. And the state’s last nuclear power plant and numerous coastal gas power plants are facing retirement.
Meanwhile, the rapid growth of solar power is providing generous amounts of daytime electricity, but, of course, none at night.
With all these changes, it’s clear that power providers have their work cut out for them. One of them, East Bay Community Energy, is using some innovative ways to manage these trends.
Read more: South Carolina’s Past Failures and New Policies Contribute to a Brighter Future for Solar and Battery Storage
In a “root cause analysis” after the August 2020 blackouts, California state agencies found three drivers of the outages. In plain language — 1) it was very hot, 2) California built a lot of solar but not enough other generators to meet demand in the evening when the sun goes down, and 3) some market rules contributed to the problem.
These conditions are echoed by a new report from the North American Electric Reliability Council (NERC) warning that California is at “high risk” of an energy emergency in 2021. In their 2021 Summer Reliability Assessment, NERC points out that California’s traditional strategy of relying on imports to meet evening demand has become an “increasing reliability risk” as other regions face similar peak events and growing solar output, as hydropower output falls due to drought, and wildfires cause transmission outages.
While California nominally has enough resources online (see figure), NERC says a combination of problems could lead to a shortfall during an extreme event.
NERC’s On-Peak Risk Scenario for California
In response to these risks, the California PUC approved an order in June requiring electric providers to procure 11,500 MW of new resources between 2023 and 2026, mostly from batteries, longer-duration energy storage, solar, wind, and other renewables.
The procurement would not only add extra capacity, but it would also make up for the retirement of the 2,280 MW Diablo Canyon nuclear power plant and 4,200 MW of retiring natural gas plants. The order specifically calls for “at least 2,500 MW of firm, zero-emitting resources” to replace Diablo Canyon, and would require power companies to add 1,000 to 1,500 MW in upgrades at existing natural gas plants.
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THE BIG RETHINK
These changing dynamics are leading power providers to rethink their procurement strategies. While solar power is now affordable, quick to build, and helps meet renewable energy and climate goals, new solar no longer helps meet peak demand. With solar regularly providing as much as half of the state’s mid-day power needs, the remaining peak demand (called the net peak) has moved into the evening. As a result, virtually all proposed solar projects in California are combined with battery storage, to shift mid-day generation into the evening hours.
This combination of solar and storage is the resource of choice for East Bay Community Energy (EBCE), a community choice energy aggregator near San Francisco.
EBCE issued a request for offers (RFO) in November 2020 and has received “hundreds” of offers, says Marie Fontenot, EBCE’s Senior Director of Power Resources.
“We knew we needed more long-term resources before the CPUC order came out,” Fontenot says. “These are the types of resources we want in our portfolio regardless.”
SOLUTIONS: EFFICIENCY AND DEMAND RESPONSE
But EBCE is also deploying demand-side solutions, which can be cost-effective, quick, and clean.
Energy efficiency can be targeted at peak reductions, such as by better insulating buildings and using more efficient air conditioners. Demand response, where customers cut power use when asked to or paid to, can be targeted at certain times and places as needed. Indeed, the biggest response to the August shortage, a drop of 4,000 megawatts, came from customers being asked to conserve through the state’s FlexAlert program.
EBCE launched its Pay for Performance program last year, three pilot projects that pay energy efficiency contractors based on their ability to reduce demand during evening peak hours. EBCE contracted with OhmConnect to give customers smart thermostats and wifi-enabled smart plugs that can respond to signals from OhmConnect to cut demand when the grid is overtaxed.
EBCE is also working with Myst AI to use artificial intelligence (AI) to develop more accurate load forecasting, as described in a recent article in PowerGrid International.
Partnering with Sunrun, EBCE customers who install solar and batteries are getting paid to dispatch their batteries during the evening peak each day. The batteries in the Resilient Home program are then available to power the home during outages.
EBCE is also partnering with Leap, a San Francisco company, to use “virtual power plants” to provide flexible electricity capacity ahead of peak summertime demand. Virtual plants are a network of residential and commercial batteries, electric vehicle charging, smart thermostats, agricultural and municipal water pumping, cold storage, and commercial HVAC systems that respond to market pricing signals. Statewide, Leap has 288 MW and over 18,000 meters under contract.
To enable these innovative distributed solutions, EBCE is also advocating for policy changes. Joining with other CCAs and distributed energy providers in the California Clean Resource Adequacy Coalition, EBCE called for a set of reforms to remove roadblocks to storage and demand response. These reforms would better value distributed storage, eliminate limitations on demand response, and make it easier for both to get paid for providing reliable services.
Demand-side solutions are an “integral part of our strategy to enhance reliability throughout summer peak demand, and will allow us to source our resiliency using clean, flexible grid capacity,” said Nick Chaset, CEO of EBCE.
About the author:
Bentham Paulos is the principal of PaulosAnalysis, an energy consulting firm with clients in the government, industry, non-profit, and media sectors.
Source: Renewable Energy