Should Utilities Procure Distributed Energy Resources Instead of Investing in the Grid?

As distributed energy resources (DER’s), particularly solar PV and battery storage, come down in cost and increase in penetration, they are increasingly the topic of intense conversation, debate, and excitement. One area of interest is the idea that utilities should actively procure DER’s and/or DER services to defer or avoid traditional utility spending. The thinking goes that if these DER’s are less costly than what the utility would have spent on a particular project, ratepayers, society, and DER’s win. This relatively simple idea, however, is more complicated than presented given the significant uncertainty in what project the utility would have actually accomplished over a specific time frame (e.g. the avoided or deferred utility cost). Utility forecasts, often presented in general rate cases, may be project-specific but ratepayer money is spent on an as-needed basis on whatever projects actually arise. Often, what was planned two or three years ago is tossed aside as certain needs disappear and others arise. Clearly, this makes the value of procuring DER’s in lieu of traditional spending also hazy.

However, rather than an insurmountable impediment to the idea that DER’s can be procured to create ratepayer value, this uncertainty must be better understood and utilized as a lens to guide cost-effective DER procurement. Closing our eyes and wishing these facts away will create false market signals and, in addition to wasting valuable ratepayer funds, will do nothing to help DER’s become trusted sources of alternative investment for utilities.

Uncertainty in Utility Distribution Planning

There are likely several types of projects that DER’s can defer, but the most obvious at this time are “capacity” projects (transformers, reconductoring, etc.) whereby the utility expects peak load to increase to an extent that equipment becomes overloaded and prone to failure causing damage to the equipment and, potentially, blackouts. These projects are usually funded through general rate cases that may occur every three years or more; as the project date gets closer, the utility will continue to update forecasts and often times can delay or avoid the project entirely, without doing anything, depending upon specific circumstances in local areas.

To illustrate these points the following two figures show a utility peak load forecast (Figure 1) and a summary of actual data from PG&E Test Year (TY) 2014 General Rate Case (Figure 2), where I’ve analyzed capacity project data regarding what PG&E planned to do versus what actually happened. It should be pointed out that though we have few data points on utility procurement of DER’s to avoid traditional utility spend, we have decades worth of utility distribution planning data that can be utilized to understand this critical area.

Figure 1. Illustrative Peak Load Forecast Compared to Actual Results — Forecast from 2013
Figure 2. PG&E General Rate Case Test Year 2014 — Capacity Project Analysis

These figures show two trends that highlight the uncertainty in distribution planning at issue here. First, Figure 1 shows that peak load was under-forecasted for most substations, particularly three years out in 2016. However, one can see that the forecasts become much more accurate (recorded over forecasted load was closer to 100% for many projects) just one year out (2014). That is to say, unsurprisingly, forecasts get better as the time horizon shortens.

Figure 2 shows the potential corresponding result from the under-forecasted projects (using actual PG&E data) — the majority of PG&E’s projects in this rate case were deferred (and may be ultimately completely avoided) mainly because the high peak loads that were expected during the forecast period never materialized. I’ve looked at SoCal Edison data that showed similarly 45% of capacity projects deferred for a TY 2015 general rate case, but this likely varies depending on the rate case, time horizon, and specific utility. The point is that if DER’s are procured to “defer” projects that happened to be in the blue section of the pie (projects that were deferred anyway due to lack of expected load growth) they will not create any value. The goal should be to identify projects completed in the year they are forecasted, the orange sections of Figure 2.

This forecast uncertainty arises primarily from the vagaries of load forecasting, which can diverge for a variety of general reasons (economic, etc.) as well as specific local area when a large developer cancels a large project. Another big reason projects can be delayed is utility land purchase and permitting (particularly for large substation projects).

Analysis of Distribution Planning Uncertainty Highlights Potential Solutions

Knowing distribution planning uncertainty exists, and why, provides a useful lens for the procurement of distributed energy resources that actually provide value to ratepayers. Based on the uncertainties discussed above, utilities should emphasize the procurement of DER’s based on the following types of identified capacity projects:

• Where load growth is not due to just one (potential) customer;

• Where the load growth can be less than expected (forecast<actual peak load) and equipment would still be overloaded and need to be replaced;

• The utility “need” (identified project) is not too far in the future.

As the idea of procuring DER’s to defer traditional utility costs is further developed through pilots and stakeholder input, key capabilities for regulators, stakeholders, and ultimately utilities include identifying projects that are relatively foreseeable and quick solicitations/procurement of DERs. In the near-term, procurement of DER services from existing DER’s may be an obvious candidate to meet these criteria — the use of smart inverters holds particular promise such as voltage and/or reactive power correction. When procurement of new DER’s is necessary, it may be possible for solicitations to consider a “pool” of like projects, to allow for the likelihood that some projects will become unnecessary as the project installation date gets closer.

Utilities and stakeholders must continue to work on how to identify low-risk projects that create value for all stakeholders. Though it remains to be seen all the ways this will be accomplished in the future, the best path forward is illumination and correcting for the uncertainty we know about today — this can lead us closer to a world where DER’s become grid alternatives that provide real value to utilities and ratepayers alike.