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Effectively Managing Distributed Energy Resources - by Paul A. DeCotis & James McClanahan

Paul A. DeCotis's picture
Senior Partner, Head East Coast Energy & Utilities West Monroe

Paul A. DeCotis is senior partner and east coast lead for West Monroe's Energy & Utilities practice, based in New York City. He leads the firm’s executive advisory and regulatory offerings...

  • Member since 1999
  • 13 items added with 21,492 views
  • Apr 11, 2017

The availability and delivery of electricity is becoming more complex as growing amounts of distributed energy resources (DERs) are added to the electric grid. Grid operators need to respond quickly to changes in supply and demand to balance the system as additional intermittent and distributed energy resources contribute to supply and demand imbalances. To address this challenge, system operators need visibility into the resource, to reliably forecast availability and, if possible, have the capability to exert some limited control over the resource.

At the same time utility distribution system operators work to accommodate more DERs, they continue to have the “obligation to serve” and the responsibility to be the “provider of last resort”. Because of this imperative, utilities need to invest in distribution system infrastructure and necessary information and operations technology (IT/OT) to help dynamically manage the grid. Traditional radial topologies will transform into more complex networked systems requiring two-way communications, new controls and sensors, and new data management systems to balance available supplies with real-time demands while managing meter-to-cash operations. These investments are necessary if the utility is to continue providing reliable and resilient electric service.

Explosive Growth

The growth in DERs over the past decade has far exceeded expectations. The vast majority of these installations are fairly small (e.g., rooftop solar) and distributed across the grid. From a monitoring and control perspective, most smaller installations—especially those with less than 10 kW of capacity, sometimes referred to as “behind the meter” or BTM—have been largely ignored because of their minimal impact on the operations of the distribution system. In fact, because of their nearly negligible impact, these systems are sometimes referred to as “load masking” rather than supply side options.

Given estimates of over 1 million individual sites and the cost associated with real-time communications, the typical utility only has visibility to a fraction of a percent of these sites. By and large, utilities are challenged to maintain even limited visibility to the numerous smaller systems connected to, and in some instances, selling into the grid. This limits their value as a resource that can be considered in balancing supply and demand.

Straining Legacy Systems

Investing in new physical assets and IT/OT systems requires significant amounts of capital as well as the support of regulators and, ultimately, customers. While different studies offer different outlooks for DER adoption, even conservative estimates suggest that DERs will more than triple in capacity over the next 10 years. In addition, the emergence of smart inverters on some DERs means these systems can do more than simply supply energy to the utility.

Going forward, this intelligence enables a myriad of potential applications. New tools that can help with voltage control and reactive power needs are becoming available to the utility. Different parameters for voltage or frequency excursions can be set to reflect the dynamics and health of the grid. These devices might even eventually begin to evaluate proactive participation in microgrids to enhance reliability. The ultimate goal is to fully realize the ability DERs can offer to improve reliability, economics, and safety for utility operations in both normal and event-driven scenarios.

Traditionally, utilities have used remote terminal units (RTUs) and protocols such as Distributed Network Protocol (DNP3) to communicate between larger DER systems and SCADA. But with the emergence of “built-in” intelligence and communications capabilities, this model is changing. Tools to effectively manage smaller, geographically diverse resources have emerged in the form of distributed energy resource management systems (DERMS).

DERMS solutions most often are specific to DER technology offered by a particular manufacturer. As a result, as the diversity of DERs on the grid grows the number of DERMS to support those solutions will grow along with them, if each DERMS solution is unique. This results in a bifurcation between large DERMS that are designed to handle a few sites of utility-scale DER and smaller DERMS that are designed to handle a multitude of smart inverters that might be scattered across a utility’s service territory.

The Manager of Managers

Some utilities are now reaching the point where it is becoming necessary to find a way to integrate disparate DERMS into a consolidated view. Years ago, data networks faced a similar challenge when vendors provided proprietary network management systems (NMSs) that often did an excellent job of supporting their own equipment while providing only token support for equipment from other vendors. Faced with an ever-growing number of NMSs, many larger networks evolved to where element management systems were used to focus on the equipment from individual vendors while a manager of managers (affectionately referred to as a MOM) was used to integrate information from these different systems into a single, comprehensive view.

With the explosive growth of DER and the mish mash of DERMS solutions, the need for the equivalent to a MOM for DERMS is now apparent. Although still in the early stages, several utilities have seen the value in this approach and have begun moving down that path. Their goal is to provide a greater level of insight and visibility to both supply and demand resources and control options to support more informed decisions that optimize operation of the grid. This can be crucial given the much more dynamic environment that now exists beyond the substation and on the distribution feeder or transformer. The value of near real-time insights into grid operations, providing the ability to optimize both supply and demand, rather than taking demand as a given and optimizing supply to meet “as is” demand, cannot be overstated. The new grid with growing amounts of DERs creates a much more dynamic grid requiring much more sophisticated IT/OT software platforms.

The Role of Aggregation

Even with such a solution, there are still challenges that come along with adding thousands (or tens of thousands) of individual intelligent devices into existing Energy Management Systems (EMSs). This has led to a growing recognition that some type of aggregation layer, potentially provided by DER equipment providers or third-party service providers, is necessary. This is a case where more unfiltered information is not necessarily better, and where aggregation adds value for utilities by distilling the deluge of information related to DER systems in ways that make it easier to plan, forecast, control, and monitor.

There is no well-defined line on DER size at which aggregation is optimized. There is certainly value in aggregation at a bulk power system level where it can help reduce the need to build or buy capacity. In fact, aggregated DERs are sometimes referred to as virtual power plants (VPPs). There is also value that can be realized from more granular levels of aggregation reaching down to the feeder, feeder segment, or even distribution transformer level. As aggregation solutions are evaluated, it is important to remember that the value they provide to operators looking at next year’s requirements often take different forms and the full range of use cases should be considered as solutions are developed. As these solutions continue to develop and evolve, it seems likely that the size of installation that it makes sense to aggregate will shrink to the point where even fairly small DERs will be aggregated and integrated into grid operations. Such aggregation makes it possible to compare non-wire alternatives (DERs) to traditional transmission and distribution system investments to realize the most value from investments in either. As DERs continue to represent a growing portion of the capacity mix for utilities, the positive impact of successfully integrating even smaller installations into a DERMS will grow (e.g., voltage control).

Even with aggregation, most utilities will still be faced with a wide variety of aggregated DERs through various DERMS provided by individual vendors. In addition to looking at development of a MOM, several other things are being done to help address this issue. One possibility being explored is the development of standards related to DERMS and recent changes to IEEE 1547 intended to encourage more flexible operation of intelligent inverters and similar devices by allowing DER assets to be active participants in the control of voltage and frequency. Another approach that might aid in this aggregation is the emerging concept of a field service bus (FSB) which acts as an “interpreter” that allows disparate systems to communicate through a well-defined agent that sits between them.

The business case for investing in DERMS can be further justified by evaluating the benefits of improved systems and integration of advanced metering infrastructure (AMI), the meter-data-management system (MDMS), enterprise service bus (EBS) architectures, advanced distribution management systems (ADMS), distribution system automation (DA), and supervisory control and data acquisition (SCADA) systems. Information about DERs must be coupled and included in these systems to provide utility operators the visibility, data, and processes necessary to manage the distributed networked grid.

Just as DERs can span the line of supply side and demand side options, DERMS solutions are also beginning to integrate demand side options. For the utility, this means the line between supply and demand as resources available to help operate the system begins to blur. For customers, it begins to unlock the full value of any DERs they own as well as the value of behavioral changes  when electricity is used. For example, an intelligent thermostat that is receiving real-time pricing signals can become a source of information that can drive behavior that affects energy consumption in a more comprehensive sense. Another example is the potential to use electric vehicles (EVs) as both a demand resource (through the control of the EV charging cycle) and a supply resource (by using the EV’s battery for energy storage). Antidotal information further suggests that consumers who reach this level of engagement in managing their electric usage are also more aware of how the decisions they make day-to-day can impact their overall energy consumption.

This also folds into the need for aggregation as mentioned earlier. For the utility, solutions that account for distributed consumption can provide as much value as those that focus on distributed generation. In fact, some utilities are finding that distributed consumption can have the additional benefit of offering a non-wire alternative to some of the traditional distribution system upgrades that are entering their distribution system planning horizon.


In computing and networking, the concept of abstraction is often used. In other words, abstraction is trying to preserve information that is relevant in a particular context while eliminating information that does not add value or insight. Utilities can use a similar approach to improve the visibility and manageability of DERs. Aggregation provides one layer of abstraction by making thousands of devices appear as a single element on the power system. With the emergence of a DERMS MOM, a further level of abstraction is provided giving consistent visibility and manageability across the various DER solutions deployed. Underpinning all of this is a two-way communications network that acts as a form of glue allowing the various portions of the overall solution to share information in real-time. Although not currently as much of a pain point for most utilities, this type of approach could also support other emerging technologies such as microgrid controllers and EV charging.

While this evolution is taking place, new and enhanced tools such as analytics are maturing and will ultimately need to be integrated into these solutions. Analytics might enable entirely new features and services such as condition based monitoring of individual DERs to help improve their operational reliability and efficiency. This may also provide utilities with a greater degree of insight than the simple aggregation of numbers can provide.

Something else utilities must keep in mind is a customer will often sit at the other end of the DERMS and aggregated systems. Even those with small systems will interact with the utility potentially much more frequently under scenarios involving real-time pricing and greater user control, ensuring a more engaged and positive customer experience.


Given the changing industry landscape and the political and economic realities of the day, utility infrastructure is aging, with post-World War II industrial-era transmission, distribution, and generation assets nearing the end of their lives. Many of these assets will be replaced in the coming decade, and they will not be replaced with in-kind technology. Physical assets being replaced will reflect current state-of-the-art technology and require new IT/OT systems to operate in a dynamic two-way communications system, and in the case of electricity, two-way power flows.

While the direction is clear, we are still early in the process. Nonetheless, it is clear the next generation of DERMS and the associated systems will play a key role moving forward.

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Thank Paul A. for the Post!
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