The rapid uptake of distributed generation (DG) has impacts on the distribution system, bulk power system, and utility cost recovery economics, especially with high penetrations of DG. On the distribution system, utilities worry about voltage regulation, reverse power flow, protection schemes, and thermal limits. On the bulk power system, utilities worry about lack of visibility, inability to dispatch or curtail DG, lack of ride-through and other essential reliability services. There is also a concern that lack of integrated DER and resource planning may lead to overcapacity.
We don’t necessarily get the best value from our DERs. For example, west-facing distributed PV (DPV) may provide valuable capacity benefits to the feeder and/or to the system, but the combination of net energy metering (NEM) and rates that do not vary with time, incentivize south-facing DPV. Utilities also complain that they cannot recover cost of service from customers with DG under NEM tariffs because customer rates tend not to be aligned with utility cost drivers. Utilities generally have high fixed costs, and if these must be spread over fewer customers, this can lead to cost-shifting between DG and non-DG customers. Ironically, grid modernization infrastructure to manage high penetrations of DG increases utilities’ fixed costs. Additionally, there are other equity issues, for example, if PV must be curtailed due to oversupply, the lack of controllability of DPV means that utility-scale PV (UPV) must be curtailed instead which impacts the economics of UPV projects.
The aforementioned technical issues are all solvable, but they may require significant focus of engineering staff and financial resources, including grid modernization investments. Some utility distribution staff are proud to ‘have never met a DER project that they couldn’t solve’. Many utilities are trying to get ahead of the customer through DER forecasting and hosting capacity analyses so that that utilities can anticipate where customers will go and what they will install and better plan for that future.
But what is the point of getting ahead of the customer if the customer is going in the wrong direction? They are only going in that direction because we’ve driven them there with a resource portfolio that doesn’t meet their needs and an economic framework bolstered by falling DER technology prices. DERs are not an end in themselves but rather a means to reaching an end goal such as lower customer bills or cleaner energy. Most customers don’t specifically want PV panels on their roofs; they want clean energy. By simultaneously giving customers choice and price signals that do not reflect grid needs or costs, the industry set itself up for a situation in which benefits accrue to individual customers but not necessarily to the system (or society). Moreover, the infrastructure to enable this high DER future increases fixed costs for all customers which impacts affordability and equity.
Instead of getting ahead of the customer, why don’t we consider what DERs can do cheaper, better, and more efficiently than other resources and use that as our North Star for establishing pricing, programs, procurements, as well as all of the processes (interconnection, hosting capacity, etc) to enable this. If you were to ask me that question, I would say that DERs are much more than just DPV. DPV was simply the gateway drug that opened the floodgates to a new paradigm. But batteries, EVs, controllable water heaters, and smart thermostats are fast on its heels. While each utility is different, common use cases likely include:
- Deferring distribution upgrades can provide high value at low cost and that’s one thing we are getting right with non-wires alternatives (NWA). As industry is finding through processes like California’s Distribution Investment Deferral Framework though, procurements incur time and effort and aren’t always successful. Also procurements are not easily scalable like organic DER growth from prices and programs.
- Demand-side flexibility is a crucial measure to integrate high penetrations of variable renewables. Increased electrification of other energy sectors like transportation and heating, and extraction of the flexibility that may be inherent in those sectors (controlled EV charging can act like storage; smart thermostats can provide regulation reserves) will enable increased levels of variable renewables.
- Manage electrification to avoid distribution upgrades: Managed electrification can help the system. Electrification can hurt the system, however, if it is not managed. The further down you go on the distribution system, the less utilized that system is and the more capacity you need per customer. The capacity needed for a customer can easily double with unmanaged electrification of their transportation and heating. This has implications on feeders where there is not significant load diversity and can lead to needs for distribution upgrades. Multiply these needs by the many feeders on the system and this could be a very significant infrastructure investment. Managing electrification may be able to avoid or mitigate this need.
- Capacity needs – accelerated coal retirements are leading to resource adequacy shortages in some regions. DERs that provide capacity can serve multiple functions due to their location. They can help the system meet peak and/or manage peak demand on a feeder to address #1 above. And of course capacity could be served with distributed generation, distributed storage or demand response.
DERs are a very powerful tool, and their potential scalability means they can have tremendous impact. But any tool needs to be harnessed. It behooves us all to decide whether we want the outcome of the path that we are on or whether there are different choices to make.