| | JANUARY 20189Taking DER lifecycle management step by stepThere are six key steps in the DER lifecycle management process: connection and energize, operations and control, service and maintenance, risk analysis and planning, outage and distribution management, and customer interaction. Connect and energize. Utilities already have established new-connect processes, which can be extended and modified--and automated--to account for the new complexity involved in connecting new customer DER as well as capturing the key DER attributes needed to model and manage the grid connection. The connect-and-energize process is also an excellent opportunity for the utility to increase customer engagement and build a different relationship by ensuring customers are aware of all the incentives they qualify for, or aiding them in understanding how they can adopt ongoing technical planning and management of their DER.Operations and control. Much like sensor-based field devices and smart meters, DER create high volumes of complex data, and though DER are decentralized, they are still part of the utility's grid infrastructure. Extracting value from that data (for demand response programs, outage management, load shifting and other benefits) begins by the utility treating DER as a grid-side resource so that the work of integrating them into the network model--where they are visible--can be expedited. To scale up to the millions of devices expected to popular the new, distributed energy grid, utilities will need automated information management processes in place with customers and/or their contractors to populate a DER device asset registry that can, in turn, be used to model customer connections and related grid impacts.Service and maintenance. Once the DER is visible to the utility and managed within the context of the network model, it's all about being able to deliver value-based service to the customer wherever possible. While these services will vary by regulations and by geography, they could include: · Alerting customers when their output is dropping and their rooftop photovoltaic system needs maintenance, and connecting them directly with third-party service providers to affect repairs.· Increasing customer choice to participate in programs such as demand response, load shifting, and the sale of excess and stored DER generation into other markets.· Connecting and communicating with customers when and how they prefer.Risk analysis and planning. Once the DER has been integrated into the network, the utility can begin to incorporate its data within its ongoing planning process. Most utility regulators assume distribution grid-side resource benefits in the DER feed-in tariff or net-metering retail rates, and so it is up to utilities to fully leverage their value in planning and operating models to avoid any excess costs of T&D infrastructure capacity. Outage and distribution management. Looking ahead, the substantial penetration of customer DER, combined with the utility's ability to aggregate, prioritize and control it could eventually support islanding, which would permit the utility to isolate parts of a grid and power each individually using local solar gardens, batteries, backup and rooftop generators and even demand response to balance load requirements in real time. In the case of an outage, islanding would permit power sharing, which can significantly lower the negative economic consequences of widespread or prolonged outages.Customer interaction. Ultimately, if the utility has successfully incorporated all the lifecycle steps above, it will be able to circle back to its customers with new information, new programs, and new models for continuing engagement. The customer-centric approach becomes a win-win, both for the DER customer and for the utility. ECProviding service to today's electricity customer, though, is a different kettle of fish entirely
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