For a 100% renewable future, focus on resources capable of providing operating reserves.
We can achieve 100% of our energy consumption from renewables.
We must focus on operating and planning reserves to ensure lights stay on in the distant future when 100% of our energy comes from renewable sources. Renewable energy policy must go hand in hand with incentives for demand flexibility to reduce grid emergencies. Energy policy advocates are focusing too much on planning reserves and too little on operating reserves.
Electric grids have 2 kinds of reserves - operating and planning.
Operating reserves are needed to meet unanticipated grid conditions, such as a polar vortex or a tree branch falling on a transmission line (September 2003 blackout that started in Ohio), natural disasters such as hurricanes, or more recent wildfires in California.
Planning reserves are needed for anticipated conditions, such as planned maintenance on a transmission line or substation or a planned generator outage.
Renewables are adding new dimensions to unplanned outages on the grid; hence grid operators need to re-think incentives for resources that qualify for operating reserves. Preventive maintenance on the wind turbine and periodic calibration of the relay in the substation are some examples of planned outages for wind. However, shutting down the wind farm due to wind speeds of 55 miles per hour is unplanned. Or the most recent example of an unplanned outage for wind happened in Texas during the February 2021 winter storm. Most wind plants in Texas shut down because their blades were frozen.
Source: PJM Manual 12 Balancing Operations
Solar farms come with operational challenges also. The unexpected tripping of 1,200 MW of utility-scale solar in California during a 2016 Blue Cut Fire event that tripped several transmission lines is an example of an unplanned outage. In 2019, Xcel Energy, a Minnesota utility, scheduled a 10-week distribution feeder outage to add a new Community Solar Garden that impacted the existing seventeen 1 MW CSGs, an example of a planned outage.
Before the renewable integration, grid operators carried operating reserves based on the loss of a single major transmission line. After the renewables, the operators started relying on forecasts to determine the precise amount of operating reserves. But numerical weather prediction models do not give precise renewable energy production forecasts more than 2 weeks out. Hence grid operators cannot plan for additional operating reserves beyond 2 weeks. That is why operators need to focus more on a rolling 2-week period.
For solar and wind, grid operators charge energy imbalance charges from renewable asset owners if the asset performs outside the tolerance band. Minor deviations in 5-minute increments are not penalized, but if the asset deviates outside the minimum (6 MW) and maximum (30 MW) tolerances in 4 consecutive 5-minute increments within an hour, the asset owner must pay energy imbalance charges.
The grid operator penalizes the asset owner for these deviations because the market must procure operating reserves from another resource(s), which is unanticipated. And energy prices are typically higher in shortage conditions than in normal conditions. Reducing these energy imbalance charges keeps the renewable project profitable for the asset owner.
We need renewable developers to stay in business for our 100% RE future.
To aspire 100% RE grid, we must ensure we have enough online (< 30 minutes) and offline (> 30 minutes to a couple of hours) operating reserves. Since RE is variable, there will be instances when energy imbalances occur. When those imbalances occur, the operator needs dispatchable resources.
The amount of dispatchable resources needed depends on how much capacity is online versus how much capacity is offline. This capacity does not have to be a generation supply. It could be demand-side resources such as interruptible loads, programmable thermostats, net energy metered solar, and behind-the-meter generation, including energy storage.
We need aggregations of distributed energy resources to qualify as capacity resources, resources that are capable of responding to grid emergencies. Those aggregations will expand the clean energy tools available to operators during shortage conditions. Additionally, these demand-side options reduce the overall price of procuring operating reserves.
Calling offline resources too soon is risky during an emergency event if the event runs longer than anticipated. For example, if a battery was called at 5 pm and asked to discharge for 4 hours until 9 pm. Because the battery had enough energy to last for 4 hours, it was not a problem. But what if the event lasted more than 4 hours? The operator must call upon another offline resource, potentially causing emissions at a higher price. Hence we need to focus on price incentives for resources that are ready within 30 minutes and those capable of performing in a couple of hours.
Planning to have sufficient planning reserves alone is insufficient because the uncertainty in a forecast beyond 2 weeks increases as time progresses. We don’t need to build a combined cycle natural gas plant anticipating a high demand forecast in 2 years unless we have exhausted the demand flexibility option. Enabling aggregation of demand-side resources provides operators with online dispatchable capacity.
Public officials relying too much on emergency alerts to reduce demand is akin to the fable of a boy crying wolf the first time. By the time the state Governor sends the third emergency alert, the public will not respond as they did for the first time. That’s why we need economic incentives to proactively reduce demand before entering into a grid emergency event, not during or right before an event.