Part 2: Getting ready for the heat

As extreme weather events drive up peak power demand, and solar power continues to grow rapidly, we are reminded that with electricity, timing is everything. To look at some issues of timing and what they mean for EBCE and its customers, we present a three-part series. This is part 2.

Reliability is always a top priority of power suppliers, but the massive heatwave and power surge of August 2020 were too much, resulting in rolling blackouts in California. With a hotter climate threatening to drive up power demand for air conditioning, and the electrification of vehicles and buildings to cut carbon, demand is likely to keep going up.

Add to that the pending retirement of California’s last nuclear power plant and numerous coastal gas power plants, the need to get ready for bigger electricity peaks has become critical.

After the August 2020 blackouts, Governor Newsom requested that California’s energy agencies — the Independent System Operator (CAISO), the Public Utilities Commission (CPUC), and the Energy Commission (CEC) — report on the factors that led to the outages.

In their Final Root Cause Analysis, the agencies found that “there was no single root cause of the August outages.” Instead, they identified three sets of causes:

In other words — 1) it was very very hot, 2) we built a lot of solar in California but not enough capacity to meet demand in the evening when the sun goes down, and 3) we need to fix some market rules.

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.

In their “On-Peak Risk Scenario” for California (see figure), NERC sees that although the state nominally has enough resources online, 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 CPUC opened an emergency docket on summer readiness. In late June, the commission approved an order requiring electric providers (including CCAs) to procure 11,500 MW of new resources [pdf] between 2023 and 2026, with batteries, longer-duration energy storage, the solar, wind, and other renewables making up 90% of the new resource mix.

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.

One big change is that power providers need 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.

EBCE had already 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. She plans to bring proposed contracts to the board this summer.

“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.”

The “firm zero-emission resource” she sees as most viable right now is solar combined with battery storage. Last spring, EBCE collected information on long-duration energy storage (more than 4 hours) and will likely solicit offers for it in the next two years.

While much of the response has focused on developing more supply, less attention has been paid to demand-side solutions, which can be cost-effective, quick, and clean.

EBCE is meeting its resource adequacy (RA) requirements through both supply contracts and more demand-side options. 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 FlexAlert program.

EBCE launched its Pay for Performance program last year, paying energy efficiency contractors based on their ability to reduce demand during evening peak hours. Three pilots are also underway, including the Low-income Peak Management Pilot. 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. The 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.

“Contracting with Leap is 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.

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.

Another way of driving customers to cut peak demand is by changing electric rates. For more on the rollout of time-of-use rates, read the third article in this series.