Emerging Changes in Electric Distribution Systems in Western States and Provinces

Executive Summary

Distribution system planning has traditionally been managed by utilities estimating new or increased loads that need to be served in each area generally over the a 3 to 5 year timeframe.  Utilities design distribution systems to reliably serve load, which includes calculating the maximum demand during peak periods for each of these areas, and then designing and building distribution substations and feeders to meet those maximum demand requirements reliably. If capital distribution costs do not fall under a utility’s ordinary course of business, these capital costs may be presented to regulators in utility rate cases for approval for cost recovery.

This traditional distribution planning process is (or will be soon) undergoing a significant changes. For instance, most Western States have enacted Renewable Portfolio Standards (RPS) or Renewable Portfolio Goals with policies ranging from 15% renewable energy by 2025 (Arizona) to 30% renewable energy (for IOUs) by 2020, to Hawaii’s 40% by 2030, to California’s recently announced goal of 50% renewable energy by 2030 .  Although larger renewable energy resources to meet these RPS requirements are usually directly interconnected to the transmission system, most of the smaller renewable distributed energy resources (DER) are being interconnected to the distribution system.

Utilities and regulators in a number of jurisdictions are seeking to better understand the both the positive and negative impacts of various types of DER systems on system-wide and local peak demand capacity requirements, emerging flexibility needs, and capital project deferral.  As distribution planning could be seen as an increasingly important part of the overall utility integrated resource planning (IRP) processes and as DER technology development continues to provide new capabilities, the need for distribution resource planning (DRP) is becoming clearer.

As the number and density of DER systems are growing, they are beginning to impact the distribution grids – both positively and negatively. For instance they can cause two-way flows of energy on distribution lines that were originally designed for one-way flows of power from substations through the grid to customer loads.  Additionally, in cases where the DER energy source is renewable energy, the power generated can be unpredictable and intermittent.  However, DER systems can also be more effective at certain locations, such as in high load areas, or near substations where they could provide reactive power and/or frequency support to the transmission system. The anticipation of high penetrations of bi-directional, intermittent power coming online at many dispersed sites on the distribution system necessitates a rethinking of distribution grid management, and possibly incentives for locating DER systems at critical locations.

In States that may see a high percentage of DER integration, whether to meet RPS requirements or for other reasons, the positive and negative impacts of DER on the distribution system will need to be taken into account. The negative impacts of DER systems would need to be understood and mitigated where possible – and equally importantly, the capabilities of “smart” DER systems must also be used to ameliorate these impacts and improve the overall reliability and efficiency of distribution operations.

The challenge for regulators and utilities is how to best understand the positive and negative impacts of these new technologies, how to recognize and address the technical, financial, societal, and regulatory issues as the distribution system evolves, how to partner with key stakeholders to coordinate mutually beneficial activities, and how to make “least regrets” decisions on technologies and processes.

Key Findings

Essential Recommendations

Beneficial Recommendations

Primary Author

Frances Cleveland, President / Xanthus Consulting International