Valuing DER Benefits to the Distribution System

Across the U.S., utility managers and planners have primarily viewed the connection of distributed energy resources (DER) to the distribution system as something to be tolerated. Indeed, the entire DER connection process is designed with a baseline objective of preventing negative impacts to utility customers.

While “preventing negative impacts” is necessary, the positive impacts of DER on the distribution system also merit exploration. Most utilities have not yet developed a functional strategy to manage and effectively capitalize on the positive impacts of DER. We view this as a missed opportunity for utilities. By valuing—and compensating—the positive impacts of DER on the distribution system, utilities can optimize the performance of existing distribution resources while also encouraging DER adoption in beneficial areas.

Calculating the Capacity Value of DER

One particular benefit is DER’s ability to offset local load, which reduces the thermal loading on existing utility equipment. This reduction provides additional capacity and can help utilities defer capacity investments that would otherwise be necessary, which can help reduce customer rates or enable other investments that improve customer outcomes. 

A recent Berkeley Lab report (on distribution system planning) discussed how distribution capacity is the most common DER service considered [see page 50]. Utilities can calculate distribution capacity value of DERs in either the short run or long run.

• Short-run capacity value refers to specific capacity upgrades expected to be necessary at specific locations within the utility’s distribution planning forecast time horizon (e.g., 5–10 years). DER value for such locations is based on the magnitude of the capacity investment and the number of years it can be deferred through DER-derived capacity.
• Long-run capacity value refers to capacity-related investments that may become necessary but are not currently included in the forecast. These types of capacity needs may result from deviations from the utility forecast or occur beyond the forecast window.

Utilities can use either short-run or long-run values (or both) when determining distribution capacity value. But the broader consideration is that distribution capacity value significantly affects the magnitude and locational nature of any resulting customer incentives.

In recent years, the Illinois Commerce Commission initiated an investigation into the value of, and compensation for, DER. Their scope included a review of the full value of the distributed energy resources and the manner in which each component of that value is or is not otherwise compensated.

Install DER Where Needed

Distribution capacity needs are highly locationally specific. Many utility substations may have sufficient capacity available for the foreseeable future, while others are forecast to experience growth that will necessitate a costly capacity expansion project.

As an example, across the country we see new housing developments are increasingly electrifying in response to “work/study/play from home” trends, electric appliances (particularly heat pumps), and garage installations of electric vehicle (EV) chargers. Now the managerial focus can shift to installing DER where it is most valuable, and shepherding DER (with incentives) to those areas to help offset the corresponding anticipated increases in load.

Typically, areas of need are traditionally identified within the distribution planning process. When DER can be directed to these areas of need, they can provide capacity relief, delaying the need for capacity expansion investments.

Consequently, when contemplating the value of DER to the distribution system, locational capacity needs must be represented within the value calculation process. Any resulting programs or incentives must also be differentiated by location in order to maximize the value to the distribution system (and the associated magnitude of DER incentives). Locational Value of DER frameworks can enable new possibilities for resolving capacity needs. 

For example, in the past, common programs such as net metering gave every customer the same incentive and the same participation regardless of their location. Rather than averaging out across the whole system, utilities can augment such programs to further incentivize specific areas of need and provide direct incentives (through rebates, etc.) to the developer or homeowner installing the DER, such as rooftop solar.

Value of DER in Distribution Planning

Valuation of DERs is not yet commonly practiced in the utility industry, and many utilities do not include Value of DER considerations in distribution planning filings. Even in states such as New York, with a Value of Distributed Energy Resources rate offering to customers, relevant inputs and assumptions for each utility’s value of DER offering are separate from the distribution planning process. EPE’s approach uses the distribution planning process as a primary input, which ensures that the resulting incentives are deployed in a manner consistent with actual expected capacity needs and align with the oversight processes used for other utility capital investments.

Through advanced analytics, load forecasting, and DER integration, utilities have an opportunity to:

• Defer capacity investments and place downward pressure on rates,
• Encourage DERs (with incentives) to areas that need capacity, and
• Optimize distribution planning for future growth in an increasingly decentralized energy landscape.