Executive Summary

Summary of Key Findings

 “In the near future, distribution utilities can no longer just supply electric energy to customers, but must now plan for, coordinate, and manage the flow of electric energy to, from, and between customers.”

  1. Tradition distribution system planning. Existing distribution planning is traditionally based on assessing each feeder separately to determine how to meet the maximum forecast customer load plus spare capacity in case of temporary reconfigurations. Regulators are normally not very involved in reviewing these distribution plans.

  2. Increasing amount of distributed energy resources (DER). Increasing numbers and sizes of Distributed Energy Resources (DER) systems are being interconnected to the distribution grid as their prices decrease and as their value to customers and other stakeholders increase. DER systems are considered to include rooftop photovoltaic (PV) systems, PV plants, wind turbine plants, energy storage (primarily batteries), biomass facilities, combined heat and power (CHP), diesel generators, and even controllable load.

  3. Low penetrations of DER systems. In low penetrations and/or operating strictly “behind the meter”, DER systems can be almost invisible and can be considered as “negative load” by distribution grid operators.  This means that they can be ignored during planning and operations since they really do not impact traditional procedures.

  4. High penetrations of DER systems. However, in higher penetrations or in “sensitive” locations, DER systems can impact traditional distribution operations. As an example, in 2003 Italy experienced a major blackout which was caused in part by large numbers of PV systems tripping off due to a short frequency anomaly. Germany and Italy then required very expensive retrofitting of the large numbers of PV systems to avoid this problem in the future. Hawaii recently upgraded about 60% of their PV systems for the same reason – fortunately they were able to push a single button to upgrade them electronically rather than pay for truck rolls.

  5. Grid modernization – “smart grid”. At the same time, grid modernization is addressing many customer concerns through the deployment of “smart meters”, conservation voltage reduction, rapid fault location, isolation, and restoration, and microgrids. These efforts are greatly improving efficiency and reducing the number and durations of outages. Most of these smart grid efforts are directly under the control of utilities.

  6. Reluctance of utilities to rely on customer DER systems. Although transmission operations have usually relied on bulk generation that is provided by independent power producers (IPPs) for the last couple of decades, these IPPs are under contract to provide the energy and ancillary services that they have bid to provide. In contrast, within the distribution arena, customer-owned DER systems are predominantly operated for the benefit of the customer, not necessarily for the benefit of grid. Contracts with customer-owned DER systems are typically net metering of energy with the expectation that these DER systems will just do what their customers need. The retail market is very weak for DER systems. Utilities therefore rightly are concerned about relying on DER systems for capacity or any ancillary services.

  7. Development of “smart DER systems” or “smart inverters”. As a result of the European and other experiences, DER systems are being made “smarter” with functions that can provide many different capabilities to transmission and distribution utilities, customers, and society. These DER capabilities range from energy and flexible capacity, to power quality/reliability, to energy efficiency, and to extending capacity of existing transmission and distribution assets. For example, energy storage systems are being used to counter some of the fluctuations caused by PV and wind DER systems, as well as smooth frequency deviations, while PV systems can help maintain steady voltage levels on feeders.

  8. Sooner or later, utilities must take DER systems into account. However, sooner or later, most distribution utilities will need to take DER system impacts and capabilities into account, both for planning and during real-time operations. California has started this process through the Distribution Resource Plan (DRP) effort mandated by the California law AB327 and codified by the California Public Utilities Commission (CPUC). Another California effort is the Smart Inverter Working Group (SIWG) sponsored by the California Energy Commission (CEC) and the CPUC to develop the technical requirements for “smart” DER systems. The MESA Alliance is developing the information exchange requirements for energy storage systems.

  9. DER forecasts and pockets of high DER penetrations. The 2022 DER forecast in the WECC are is for 30 GW. In the short term, based on current RPS and incentive programs, high penetrations of DER systems will predominantly be expected in certain locations within California and Arizona. However, it is expected that other territories will experience pockets of high DER penetration long before an entire State is affected.

  10. Lack of planning and operational tools for assessing DER. Unfortunately, distribution planning tools currently in use are not equipped to support the analysis of where and how DER systems can replace traditional additions of equipment and substations. The California DRP process is analyzing the various “avoided costs” if DER systems are used in place of traditional solutions, by defining a list of mutually exclusive and collectively exhaustive (MECE) categories of values.  Operationally, few utilities even can monitor what DER systems are producing, except through after-the-fact metering. DER aggregators have collected large amounts of data, but have not yet determined how best they and the utilities can use this data, particularly in light of privacy concerns.

  11. Bring together all stakeholders to resolve DER issues. The future for distribution planning and operations is complex and will depend upon many technical, financial, and regulatory issues, but the key takeaway from the efforts so far is that if all stakeholders work together with minimal controversy to identify and discuss the issues, then good solutions can be found. Specifically in the technical areas, joint efforts have proven to be very effective. This principle has been illustrated in California’s Smart Inverter Working Group (SIWG) and in the Distribution Resource Planning (DRP) More Than Smart working group. Heated discussions can still occur over whether 0.2 seconds or 0.3 seconds is better for a particular situation, but the participants still have a common interest in reaching solutions.