By Bradley Williams
Utilities’ residential and business customers alike are adopting distributed energy resources (DER), especially rooftop solar photovoltaic, at an historic pace. Their ability to impact grid reliability, outages, revenue and even overall business health can be positive or negative, depending upon how utilities integrate these DER and the large amounts of data they continuously produce.
At the same time, the data produced by these and other grid connected devices-the Internet of Things (IoT)-is putting new pressure on utilities. In combination, these challenges are causing utilities to transform their business models to better manage evolving distribution operations.
NEW APPROACHES TO UTILITY PROCESSES
With so much distribution grid innovation now being driven by consumers and policy and regulatory changes, utilities must quickly understand how to turn the grid edge into business opportunities, rather than a stumbling block. They can do so by evolving their business model, which can open up innovative ways of gaining revenue, improving asset performance and lowering operating cost, such as:
- Increasing customer choice to participate in demand response (DR), load shifting and the sale of excess and stored DER generation into other markets.
- Minimizing asset risk by identifying and mitigating negative performance patterns via predictive modeling of granular DERs and their connections to the grid. The models leverage real-time, location-based weather forecasts, as well as related sensor data to provide clear DER visibility at the edge of the grid.
- Alleviating utility grid, as well as supply-side, constraint via DR by leveraging both utility and consumer assets to dynamically shift output among other generation sources. DR is a great resource to help mitigate grid impacts from the intermittency of renewable DERs.
The systems required to deliver this innovation must support new approaches to utility processes, such as automating DER and other device connections. In addition, utility and other sensor devices must be able to communicate with these resources. And, depending upon the utility’s business model, third-party service providers might also be part of the processes. Complex programs, billing and load shifting also must be reconciled with customers to ensure revenue. An entire connection-through-customer-service process lifecycle for DER, DR and other connected devices exists. It is decidedly more complicated than the traditional customer or asset lifecycle process employed by utilities in the past.
DEFINING THE DER LIFECYCLE MANAGEMENT PROCESS
The traditional distribution process has its own defined lifecycle, and so does DER management. Sometimes, when dealing with grid-edge devices and technologies, it’s a matter of managing a distributed device on its own. When dealing with a higher proliferation of DER within a specific territory, the process also involves bringing perhaps millions of granular DER devices into the utility’s network model and understanding how they impact the utility’s traditional distribution model. Beyond initial pilot projects, utilities must leverage automated information management processes to capture and keep these models current.
The DER lifecycle management process, much like many other utility processes, begins and ends with the customer.
Following are six distinct steps seen in this process, beginning with connecting the customer’s DER:
- Connect and energize
- Operations and control
- Service and maintenance
- Risk analysis and planning
- Outage management
- Customer interaction
Connect and Energize. Regulated utilities are obligated to serve their customers as part of their regulatory mandate. Many see the connection of customers’ rooftop solar PV as an assumed extension of that mandate. The “connect and energize” step from a DER perspective means trying to get valuable generation or storage or both connected and into the grid model as quickly as possible so that those resources also are available to the utility, which can use them for reliability and revenue purposes.
Every utility has established a process for dealing with new building or customer connections, and this process is similar from one utility to the next. When it comes to connections for DER or other smart devices, however, utilities have taken many different initial approaches. Some began as pilot projects, others have been managed through GIS, and so on. These approaches may have worked for a few hundred or even a few thousand devices, but a more robust process is needed for continued customer engagement when a utility begins to deal with DER at scale. In this instance, the connect-and-energize process must allow for process automation, with predefined workflows to speed the associated work. As DER levels increase, utilities need automated DER asset registry processes and systems that can scale to every utility connected customer.
Operations and Control. Much like sensor-based field devices and smart meters, DER create high volumes of complex data, often in real-time. Although DER are decentralized, they are part of the grid infrastructure. Extracting value from that data-for DR, innovative programs, outage management, load shifting and other benefits-begins when utilities treat DER as assets and can expedite their integration into the utility network model, where they are visible. A DER-specific asset registry is integral to this process.
Service and Maintenance. In the cases where DER is owned and maintained by the utility-for example, where residential rooftop solar is deployed and operated by the utility on behalf of the customer-service and maintenance is fairly straightforward. For deregulated utilities, such as distribution retailers in Europe or utilities that have spun off separate businesses for the purposes of DER installation, service and maintenance, these on-premises, value-added services represent a new, potential revenue channel. Utilities can monitor actual outputs and compare them to forecasts to predict maintenance needs.
For all utilities with DER integrated into the grid model, this “service and maintenance” process also extends well beyond the health of the DER asset itself. By integrating DER into the network model, utilities can not only automate sensor maintenance and upgrades and ensure real-time asset performance management (APM) health scores of DER assets are reflected, but also account for DER impact on distribution assets.
Risk Analysis and Planning. This is one of the most important-and potentially most lucrative-areas of DER lifecycle management. It involves the utility having the ability to make dynamic grid adjustments to ward off unstable conditions and improve resource planning. Currently, in many cases, no grid adjustments are being made to account for DER risk factors because of a lack of visibility or control over customer-owned DER assets. Further, DER data might not be incorporated into the network model, and DER growth might not be factored into future planning, leading to increased customer costs to provide duplicate utility capacity.
Under this DER lifecycle management model, the utility would gain visibility to all distributed generation on existing circuits; identify and model patterns of DER growth; and potentially defer the need for additional generation and traditional grid capacity by incentivizing customers in specific areas to update DER so the utility has additional, customer-supplied generation in places where it is needed. As utilities move to real-time, this becomes a transactive energy market model.
Outage Management. Traditionally, DER are poorly leveraged for outage use. DER is tripped out in an outage event to keep the crews working on the outage safe. DER, therefore, will not be available on the line being restored during the outage restoration process. When tripped off, DER can extend the duration of an outage because additional switching steps are required to pick up the load when circuits are re-energized.
Optimally, within this DER lifecycle management model, the utility would know if a DER is appropriately sized and equipped for islanding operations and be able to model each resource’s capabilities for outage management. This would allow the utility to aggregate load and restore power faster to areas after a service disruption. In addition, it would accurately model and account for DER in cold load pickup.
DR can be used to temporarily free up capacity during the switching steps, then once restoration is complete the DER will re-energize and the DR event can be completed with minimal impact to the customer.
Customer Interaction. This is where DER lifecycle management begins and ends. The customer is central from the beginning of the DER integration process, and integral to program uptake and additional revenue opportunities. New utility revenue opportunities will require regulatory and policy changes, and those are beginning to take place. For example, the New York REV (Reforming the Energy Vision) initiative is working to transform the utility into a value-based business model, which includes the ability to support customers’ choices and provide them with access to third-party service providers that those customers value. In jurisdictions where end-use customers and metering have been separated from the grid operators (e.g., parts of Europe), this vision is much more difficult, creating an obligation to serve customers and connect to DER without the information to effectively plan and operate.
As the integration and evolution of the DER-inclusive model continues, utilities need the ability to create rate structures for any level of program complexity, enable more accurate segmentation of their customers, integrate third-party vendors where applicable and dynamically communicate to the DER on their grid network.
A DER INCLUSIVE FUTURE
Every utility must deal with growing grid-edge technologies in some way, moving forward. Many already are dealing with it, more quickly than they ever anticipated. While regulatory policy changes are moving forward in many jurisdictions to assist in DER integration, utilities also are exploring the technology changes necessary to their systems to manage the additional complexities brought about by DER integration. A new approach to lifecycle management is an important first step.
Bradley Williams is vice president of industry strategy, Oracle Utilities. Williams is responsible for Oracle’s smart grid strategy as well as utility solutions for outage management, advance distribution management, mobile workforce management, work and asset management and OT analytics.