2.1 Why Are Distribution Systems Becoming an Issue for Regulators?

2.1.1 Are Utility Interests and Regulator Interests Different for Distribution System Management?

In the past, utilities planned expansions and upgrades to their distribution systems based on the very simple philosophy of building to reliably meet the maximum expected load over the next 3 to 5 years (see 3.2.1). In some jurisdictions, these distribution upgrades are part of the utility’s normal course of business. If these distribution costs are brought to the regulators as part of rate cases,  the regulators, after verifying the premises for funding these upgrades, could easily agree that the public interest was being best served by this construction.

Recently however, new possibilities for reliably and safely meeting customer electricity needs have emerged, such as demand response (see 3.10.3), fault automation (FLISR) (see 3.2.6), and conservation voltage reduction (CVR) (see 3.2.6). These approaches could potentially reduce customer bills or lower the impact of rate increases, and therefore could be very attractive to regulators in their role of protecting the public interest. But these programs do not necessarily benefit utilities since not only do they reduce customer bills, but they also require the utilities to perform additional studies, implement new types of systems, and install equipment to support the programs.

At the same time, utilities are being pressured by their customers and by third parties to permit increasing numbers of Distributed Energy Resource (DER) systems to be interconnected. Concerned that these DER systems could lead to safety and reliability problems, utilities have been slow in approving them, particularly the larger DER installations. As long as DER systems were just a few in number and size, utilities could treat them as “negative load”.  But as their numbers are starting to increase, utilities are recognizing that they are not only a challenge but also could become an opportunity. Exactly how and what regulatory changes might be necessary are not very clear. But possible options could be to provide some of the DER services to communities and to incentivize customers to install DER systems where they might be most beneficial to utilities for reliability and power quality reasons.

Figure 1 is an example of where different technologies and solutions to DER can reside with utility, customer, or interactive. Regulators will be placed right in the middle of the decision making process on where to direct investment to meet utility and ratepayer objectives.

Figure 1 : Technology Choices for Integrating PV and DER (2013)

Figure 2 : Regulators’ rankings of different issues *

In sharp contrast, as shown in Figure 2, utility executives ranked DER as the biggest growth opportunity for utility investment.  Even for the second ranked item of customer relationship, the interest lay in joining with customers on DER projects. So rather than lowering customer costs, their main focus is on finding new business models for their futures.

Figure 3 : Utility executive ranking of growth opportunities *

These diverging interests may not be apparent in all jurisdictions at this time, but over time will lead to increasing pressures on all sides to find good, if not perfect, solutions. . A recent discussion in the Edison Electric Institute (EEI) identified the need for utilities to develop new business models **:

• In order to participate in the DER industry, utilities need to have the barriers removed from owning, partnering, or operating DER facilities
• Utilities need to be able to partner with other stakeholders to pursue these interests
• Utilities need to have the allocations of costs of providing power more fairly divided between customers who have DER systems and those that do not.
• Utilities need regulators to support investments in grid upgrades that are needed for high penetrations of DER systems.