Emerging Challenges of Community Choice Aggregations

Last month, I received a surprise notification in the mail that my electricity provider would be changing to ‘MCE’.  Previously unknown to me, my county was the latest in the San Francisco Bay Area to vote joining MCE, a not-for-profit, community-owned agency that operates under California’s Community Choice Aggregation (CCA) program.

I’ve since discovered that ‘MCE’ is actually a rebranding of ‘Marin Clean Energy’, where it started in 2010 to provide more renewable power options for the citizens of Marin than was offered by the local utility Pacific Gas & Electric (PG&E).  Basically, MCE offers customers a choice of renewable mixes for their power supply – 50% or 100% renewables – and uses the revenue to invest in local green energy projects.  PG&E still provides all the distribution wire services, and a default electric service of about 33% renewables.

Community aggregation programs like CCA are just the latest trend and challenge to hit the utility industry already losing load to customer-owned solar.  We are also seeing “Rural Electric Cooperatives”, “Shared Solar Programs”, and “Community Generation” piloted across North America.  These programs are all variations on the same theme – allow customers to share in the investment and benefits of solar or other clean Distributed Energy Resources (DERs), even if they cannot install it themselves (such as apartment renters).

This is all in addition to the more traditional “Solar Aggregator” type programs where third-parties finance, install, and operate fleets of behind-the-meter solar on customer premises.  “Battery Aggregators” already exist at the commercial level, and residential battery aggregators are coming soon, if the Tesla display at my local Home Depot is any indication.  These DER aggregators target communities more indirectly, by marketing into certain regions and customer demographics.  They may also seek additional revenue streams by selling excess energy or ancillary services into wholesale electric markets.

Besides the revenue implications of community DER aggregates, utilities are starting to worry about the potential grid management operational impacts.  A community, aggregator, or retailer that decides to deploy DERs in a given region may increase penetration rates much faster than a normal unorganized population.  Instead of a gradual, statistically diffuse installation across their service territory, utilities worry about pockets of rapid deployment.  And while each DER unit is individually small and normally independent, an aggregator could operate them in coordination with significant local network affects akin to much larger asset.  This is especially likely in cases where the aggregator is using the cumulative capacity of their fleet to also participate in wholesale markets.

The operational impacts extend beyond the control room into the back office.  Large scale, rapid changes in signups, opt-outs, or interconnection requests put a strain on customer services and planning engineers.  Uncertainty in customer load and solar growth patterns complicates capital budgeting and supply contracts.  Some programs will require new complex metering and/or billing arrangements where the energy export from one site needs to be disaggregated and credited to offset loads or bills at other sites.

For the last few years, GridBright has been working with the DOE, CEATI and leading universities to identify and plan for the expected impacts of DERs on the grid.  Normally this includes looking at the different types of impacts created by large vs small DERs, since their relative sizes and volumetrics result in completely different grid effects.  Community aggregates represent a new, hybrid challenge for utilities that combine both size and volumetric issues.    We expect more utilities will need to examine how community aggregates might alter their DER operations roadmap going forward.