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    Monday, March 07, 2016


    Planning the Distributed Energy Future; Emerging Electric Utility Distribution Planning Practices for Distributed Energy Resources

    February 2016 (Solar Electric Power Association and Black & Veatch)

    Executive Summary

    The market landscape for electric utilities in the United States is shifting dramatically toward a future with much higher penetrations of distributed energy resources (DERs), including:

    „ Solar photovoltaics (PV)

    „ Energy storage (ES)

    „ Electric vehicles (EVs) and charging infrastructure

    „ Demand response (DR)

    „ Combined heat and power (CHP)

    „ Other non-solar types of distribution generation (DG)

    „ Energy efficiency (EE) measures

    This shift is driven by changes in customer choices around energy; technological development leading to lower costs and better performance; and new policies and regulatory proceedings requiring utilities and utility customers to embrace DERs in many forms.

    To understand how utility planning is changing, Black & Veatch and the Solar Electric Power Association (SEPA) interviewed five leading utilities across the United States and identified trends in utility planning practices. Each utility is pursuing a different mix of new methodologies and tools for DER planning, based on its own unique circumstances and concerns, including:

    „ Methods and tools for assessing the DER hosting capacity of distribution circuits

    „ Valuing the locational costs and benefits of DERs

    „ Guiding DER installations to preferred interconnection locations

    „ Assessing the need for rate restructuring

    „ Monitoring and control of DER assets

    These utilities are also trying new organizational structures that bring together the multi-disciplinary teams needed to effectively plan for all aspects of DER deployment. New modeling software capabilities are emerging to address the needs around grid modeling in an age of increasing DER penetration, and leading utilities are beginning to take advantage of the new analytical tools. However, a number of open questions remain around DER planning processes, modeling approaches, and monitoring/control methods.

    To the authors’ knowledge, no utility has yet put into practice a comprehensive framework for utility planning that incorporates the far-reaching impacts of DER growth.

    To assist utilities in addressing this major industry challenge, this whitepaper outlines a proactive DER planning process, which is summarized in Table 1.

    The five processes noted in Table 1 are interconnected, where a change in any one aspect will affect the others. For example, under one set of incentive rates there may be PV and EV penetration that overly stresses a utility’s transmission and distribution (T&D) system. Strategically, the utility may seek to change incentives, which will then change customers’ adoption of those particular DERs, and will in turn require a re-examination of T&D impacts (though regulatory constraints may limit the ability to modify incentives). The process is thus iterative, with a goal of converging on a utility’s optimal portfolio of distributed grid opportunities (please refer to Section 3 for additional detail).

    Utilities can realize numerous benefits from better DER planning, including more efficient interconnection processes, expanded capacity to accommodate DERs, reduced total infrastructure costs, and improved forecasting of DER impacts on load and utility revenues. However, a number of issues must be considered when implementing a proactive DER planning process, including:

    n Ownership and control of DER assets

    n DER markets and procurement

    n Data sharing and confidentiality

    n Rate impacts

    n Interactions with other utility regulatory proceedings

    n IT infrastructure n Staff resources

    n Preferences of local customer and policy-makers.

    To summarize, key takeaways include:

    „ Significant growth in DER penetration is expected across the United States due to multiple market drivers. Among these drivers, is a growing list of states that are providing active policy support and regulatory guidance for utilities

    „ More sophisticated tools and methods, along with new utility processes and organizational structures, for DER planning are being developed and adopted rapidly

    „ DER forecasting and valuation will become a standard part of the utility planning process in the near future

    „ New procurement methods and business models are emerging around DER assets and grid integration, and DERs may be able to replace some conventional grid investments in the distribution system (with appropriate contract structures and technical specifications)

    „ Utilities will need to make significant financial investments in new hardware and software, but also investments in human capital (e.g., staff retraining and reorganization, new skill-sets, new processes and new ways of doing business) to enable the DER-rich grid of tomorrow


    DER growth is challenging the status quo of distribution planning as a result of changing customer choices, technological development and new policies and regulatory proceedings. Higher DER penetration is pushing a number of leading utilities to confront industry gaps in this area by developing new methodologies and tools, adopting new software with more sophisticated modeling capabilities, and reorganizing internal departments to bring together the multi-disciplinary teams needed to streamline DER deployment. However, a number of open questions remain around DER planning processes, modeling approaches, and monitoring/control solutions.

    No single utility has yet put into practice a comprehensive framework for distribution planning in this new high-DER environment. This whitepaper provides a framework as a starting point for utility leaders. This framework emphasizes the need for an iterative planning process that is repeated frequently to capture rapidly changing market conditions in the electric utility industry. Traditional integrated resource planning frequency (usually every 2-5 years) will likely not be able to keep pace with the expected rapid growth in DER penetration and its associated impacts.

    The benefits of a more holistic and proactive DER process could include:

    n Better forecasting of DER growth and resulting impacts on net load profile

    n Better forecasting of revenue and rate impacts from DERs

    n Decreased DER interconnection timeframes

    n Increased DER hosting capacity n Minimization of distribution system infrastructure costs.


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