Outages during Christmas reflect poorly on utility forecasting and natural gas units. It’s past time for the states and their utilities to lead and not wait until the grid regulators Federal Energy Regulatory Commission and North American Electric Reliability Corporation conclude their joint investigation.
To ensure safety and reliability, utility leaders should pay consumers to reduce consumption, embrace distributed energy resources in their resource planning, and make interconnecting rooftop solar and residential storage easier.
The question is, however, will they?
Anticipating NERC’s response
FERC and NERC have announced a joint investigation into what happened in North Carolina during Winter Storm Elliot because of multiple outages during Christmas.
The economic and reliability regulators want to get in on regulation and standards after an event, but there is no focus or attention paid before. Maybe that’s just human tendency?
History has always told us, at least in the electric utility industry, that major regulations come after blackouts. The National Electric Reliability Council was formed after the 1965 blackout. Read about fascinating NERC history here (It’s only 177 pages!). NERC came out of regional councils such as Mid-Atlantic Area Coordination Group, which is now ReliabilityFirst.
The Council became a corporation — the North American Electric Reliability Corporation — after the Sep. 2003 blackout with the mandate to levy fines of up to $1 million per day if utilities violated reliability standards, including tree trimming regulations.
Incentivizing DERs before an event
Fast forward to Feb. 2021.
Did we learn anything from winter storm Uri in Texas? We have already forgotten that Texas went through a similar winter storm event a decade earlier, in 2011.
Yes, FERC and NERC jointly investigated and released a report back then. I am sure they will also release a report for Elliott, too. But the jury is still out on Uri’s lessons. A recent proposal in Texas to incentivize generators (not load) to ensure they show up during a grid emergency.
Look at what is happening right now in PJM
PJM just announced that it had more unit outages during the Christmas week than forecasted. If 23% of PJM’s total capacity was forced out, 87% was from natural gas and coal units. And we have executives from Duke Energy Carolinas apologizing for inconveniencing their customers during Christmas. These utilities and RTOs have not taken steps to incentivize demand response and distributed energy resources, yet they are the custodians of safety and reliability.
Why should they pay load to avoid blackouts? Because that’s how MISO avoided blackouts in Feb. 2021.
Utilities must speed up distributed resource interconnections via automation
Whenever the topic of distributed energy resources interconnection comes up, utilities always bring up the fact that they are responsible for the safety and reliability of the distribution grid. Never mind that those utilities have already studied these DER interconnections. They want to “screen” them again so that a solar project is not exporting more than it should when storage is added at the same site.
Solar interconnections can be severely limited on the distribution system due to capacity constraints that could be resolved without the cost and delay associated with major feeder upgrades. In some cases, voltage and current imbalance will limit the feeder capacity. This constraint exists even though capacity is available in other phases.
Companies like Switched Source offer a distribution automation solution, the Phase EQ, that will automatically balance the voltage and current to unlock the capacity of the feeder. In other cases, the ideal location to site a solar project may be served by a feeder at capacity; however, adjacent feeders have the capacity but are not tied together due to the risk of loop flows.
Switched Source also offers another distribution automation solution, the Tie Controller, that can enable adjacent feeders to be tied together and controls the power flow between them to balance the load on the feeders.
Utilities must embrace distribution automation solutions to identify feeders with phase imbalance issues or capacity constraints and deploy solutions to address the issues to enable more load and solar interconnections.
Utilities must reflect accurate modelling of distributed solar in resource plans
Whenever utilities have integrated resource plan (IRP) proceedings, renewable and environmental advocates must push the utilities to incorporate distributed solar in their future capacity expansion plans. It’s like pulling teeth.
The excuse utilities give for not including distributed solar in future resource plans is that they don’t have much capacity value compared to utility-scale solar or utility-scale natural gas plants.
But the recent Christmas event in PJM shows many more outages than forecasted on the system. Additionally, unanticipated outages led to capacity deficiencies in the New England region during Christmas. And the New England grid operator is levying non-performance penalties on non-performing units, but we won’t know who owns these units.
So why are the utilities and their regulators more focused on an antiquated integrated resource planning process that incentivises more non-renewable generation and the transmission needed to interconnect, when we should be looking at more distributed options on the demand side?
To reduce the magnitude of a blackout or even the likelihood of entering into an emergency event, grid planners should be talking to policy professionals and educating them before it is too late. It is easy to think about policy during an emergency event. It is hard to think about the policy before an event.