How ADMS and DERMS Are Delivering Smarter Solutions for Utilities and Customers

Advanced Distribution Management Systems (ADMS) and Distributed Energy Resource Management Systems (DERMS) are crucial grid management technologies in today’s modern power delivery system.

ADMS integrates multiple utility operational systems into a unified control platform. It combines functions like outage management, supervisory control and data acquisition (SCADA) systems, and distribution automation (DA) to provide operators with real-time visibility and control across the distribution grid. This integration enables utilities to optimize power flow, respond quickly to outages, and maintain reliability across increasingly complex networks.

DERMS, meanwhile, focuses on managing distributed energy resources (DERs) like rooftop solar, battery storage, electric vehicles, and demand response assets. It allows utilities to monitor, forecast, control, and optimize these diverse, often customer-owned resources. DERMS platforms help coordinate DERs with the broader grid, enabling capabilities like peak shaving, voltage support, and virtual power plants.

Both technologies are becoming essential because the traditional one-way power flow model (from large plants to consumers) is giving way to a bidirectional, decentralized system. As solar, storage, and other DERs proliferate, grid operators need sophisticated software to maintain stability, maximize clean energy integration, defer costly infrastructure upgrades, and enable new market opportunities for DER owners. Together, ADMS and DERMS represent the control systems necessary to transform aging electrical infrastructure into the flexible, resilient grid required for a decarbonized energy future.

To better understand ADMS and DERMS technology, and how it can be most effectively implemented and utilized, POWER spoke to Amy Bartak, grid modernization manager with Burns & McDonnell, and Nathan Brown, director of Operational Technology Services with 1898 & Co., a part of Burns & McDonnell. Their insight is shared below.

POWER: What role does communications infrastructure play in enabling ADMS and DERMS?

Bartak: Whenever we talk about grid modernization, or technologies associated with that, what we’ve seen in the industry has been a big focus on the hardware or on system deployment. Communications or the software management pieces of an ADMS or DERMS are often not included in the original planning, so they become critical and we sometimes hit a critical path item of: “We’re getting ready to deploy the first 50 reclosers in the field, but they’re not monitored within the control center, or we’re not getting communication to them because communication was an afterthought.” So, it’s been an interesting perspective of laying the groundwork.

Brown: I think the interesting thing about communication is you’re really talking about big, long-term projects and investments. Telecom takes significant time—sometimes five, 10, or 15 years—to roll out different aspects. So, if you’re not thinking about it—planning for it—ahead of time, you’re behind. I mean, if you have an ADMS initiative today, and you haven’t been thinking about your telecom strategies and plans, and laying out those and starting to deploy solutions, you’re behind and you’re not going to get caught up, or it’s going to be very difficult to get caught up.

So, I think it’s an enabling solution. It’s an enabling piece of it. It takes a long time to plan and deploy, and you really need to spend the time up front thinking about it. A lot of organizations are out working on deploying these business customer—rate-paying customer—focused systems, and they kind of overlook the enabling solutions that need to go with it.

POWER: Haven’t most utilities already deployed ADMS and DERMS systems?

Brown: ADMS has been being deployed longer, but a lot of it’s been deployed in a less centrally managed state. So, they’re getting data back from systems, but they’re not really centrally managing things for ADMS, and that would be to manage outages, outage response, and reduce customer impact. So, what you’re really seeing now is this next phase on the ADMS side. They are really rolling out centrally managed things, which take a look at the whole network model and say: “How can we be more efficient, effective, and move things around in a better way to support our customers.”

From a DERMS perspective, things are generally a lot less mature there. We still have a lot of renewables coming onto the grid, and there’s still a lot of discussion and debate on how that’s going to be managed and how it’s going to be centrally monitored and maintained. And so, they’re farther behind on those. There are pieces of it out there, but it’s not really a centralized collaboration or coordinated solution yet.

Bartak: To your point, don’t they already have communication systems? Yes, they do. Was it right-sized appropriately? Potentially, not. So, with the big change or impetus with the advanced meters, and not having a meter reader, but having that be able to be collected at certain points and then brought back centrally—that was kind of that first-gen perspective.

We had a lot of hope in the initial deployment of AMI [Advanced Metering Infrastructure], or other mesh networks, to be able to get all of these devices that we were putting on to communicate. But when it came down to implementation, what happened was it was laser focused on just billing information, and the industry didn’t really go through some of the use cases or technical challenges for the distribution automation devices or the control devices on the lines. For DA, a lot of times I like to call it a “comms light” or a “not-comms-enabled deployment” of hardware and sensors and stuff on the grid.

And so now, by being able to think through that from a communications perspective, we’re building out a more robust network. We’re focusing on throughput. We’re focusing on what points and what volume are coming back to a certain location so that we can start making better-informed decisions.

So, by enabling comms, and focusing and putting that picture all together, we’re able to leverage the data. We’re looking at the communications to be able to connect to those devices and see those states—to paint a better picture of how we can actually make change in the grid without having to go: “Do we need to build a new generation plant? Do we need to look at something else? How can we change wires?” So, we’re effectively being able to provide data from the operational lens of the system holistically on what we can do to make sure customers have the best experience they can have with their power.

POWER: What does it take to manage these systems once they’ve been deployed?

Bartak: DERMS has been a unique one, because it covers many different organizations and forces people to work together more, instead of in silos that they have. Long term, we’re seeing more of a need for additional resources—maybe not resources per se, maybe head count stays the same, but a retooling and a retraining of those individuals. Who’s going to look at the DERs that are impacting the system on the distribution and transmission level? What are we looking at from an operational-needs perspective, maybe from a price signaling aspect, or if we’re looking at demand response—energy efficiency for peak load shaving and how can we affect that?

We’ve worked with several utilities to actually think about: “What does grid management of the future look like?” So, there are a couple of different roles. It’s bringing in some planners and engineers within the control center to be able to help make some real-time decisions when it comes to that. And then, can we train or retool folks that maybe have worked as meter readers or something else to now go out and work on firmware and security upgrades and patches for a telecommunications system, whether it’s a firewall or a switch. Or can we help retool those folks that need to go out and troubleshoot? Or how can we change that staffing system of who’s making the decisions from an ADMS perspective?

And then, the one that doesn’t get talked about a lot is the IT [information technology] support that’s needed. A lot of times, people get stuck in their operational lens and don’t really consider who needs to keep the software system itself up and running, and what that entails from a whole team perspective.

Brown: The bottom line is collaboration is required across groups who are traditionally not used to collaborating. From my lens, operational technology [OT] systems used to be very “set it and forget it.” We bought a device from GE or Schneider. We threw it out in the field and expected it to run for 20 years. And, if for some reason somebody realized it stopped running, we’d just grab one from off the shelf, replace what was out there, and throw the old one away.

That’s not really the case anymore. Now, we put in a system, we’re scaling it out from hundreds of devices to tens of thousands of devices, plus a lot of underlying structure for networks and security and things like that. This really has to be managed and maintained. So, we have to take some lessons learned in the IT space—IT service management has been around for a long time—on how do we alert and alarm on things, how do we manage for events, how do we manage incidents, and things like that. We have to apply these in the OT world.

It’s not a one for one mapping. It’s not a “Do what IT did and apply it to OT.” It’s “Take the lessons learned from IT and apply them in a way that works in the OT space.” But the bottom line there is: It’s got to be managed now—for safety, for security, and for operational aspects—to make sure that rate-paying customers are getting what they asked for. If we have a system that’s out there, but it only runs 50% of the time, they’re not getting what they asked for. So, we need to make sure that we are managing toward those expectations.

POWER: What challenges do utilities face when they embark on an ADMS or DERMS implementation?

Brown: The first thing that hits them all—and it takes a while to realize—is that they don’t plan well together. So, they’re all off working in different groups, going forward at different paces, with different initiatives that aren’t concerted. So, we take a lot of time with our clients and work on combined planning and governance efforts. We talk about: “All right, we know we put a plan out there. We know it’s going to change. When it does change, how do we make sure that everybody understands the change and agrees upon the change, and that we pick the right priorities?”

Because, really, you’re taking a whole bunch of groups who have just been free to go do things on their own, in their own vacuum, for years. Now, they can’t be successful unless we put some of that structure around it—that governance and that ability to work together, plan together, and deliver together. So, the biggest challenge is bringing everybody together under one consistent plan. And then, understanding that plans are going to change, and we need to govern that, and have the right people to make the right decisions to prioritize and reprioritize as things do change over time.

Secondary, and not a part of that, is funding. Everybody goes out and does different methodologies for getting funding. Depending on what kind of utility you are, you have different functions for that. A lot of times, different groups will be out there driving for funding for different parts of this, without thinking about how it affects the other groups. I see it all the time, where, for example, the distribution group is out getting funding to deploy a whole bunch of reclosers, cap [capacitor] banks, voltage regulators, and things like that, and they just assume that the network is going to be in place. But the network team has not gone out and asked for that funding, and has no ability to recover that funding at that time. So, then, everybody’s scrambling to figure out how to make sure that it’s all supported together.

Bartak: Or, the engineering side will be like, “Well, I’ve done my pilot using a leased cellular function, so now I’m going to deploy 10 or 100 times that with the same model.” No one is pausing to look back and consider what that’s going to cost from a monthly leased-cellular modem fee from an ATT or Verizon, and should I do a business case study to determine if a private network that is owned by the utility would cost less over time. Meanwhile, a lot of telcos [telecommunications companies] are getting out of those services supporting the electric utilities and are pushing utilities to have their own network that they then have to manage. And so, having those conversations has been interesting.

We’ve seen multiple times that they tend to miss the communications enablement piece. They may have included everything from the hardware component in the grid itself. They may have even done the software selection of an ADMS and built in that $5 to $10 to $15 million that it’s going to take to do those systems. But they still then forget the comms piece, which is an interesting perspective, and why we like to talk about the three things as a whole. It’s not only the hardware, but also the technologies—the software solution and the communications—that truly makes the grid modernization successful.

POWER: What outcomes can utilities expect if they invest in the full ecosystem needed for ADMS and DERMS?

Bartak: Off the bat is the visibility. The visibility that they are now starting to see—whether that’s a DERMS or just showing your DERs within your ADMS or your EMS [Energy Management System]—it’s that visibility from a safety perspective. When we’re thinking about outages—when a storm rolls in or a planned outage—the number one focus is making sure that we can return electricity back to our customers safely. And so, by having all of that in one pane of glass, if you will, or maybe an Operations Center, we’re able to work through energization—switch order management—in a safe and effective way.

It also gives them a little bit more power from a decision-making perspective as well, maybe for future planning, for new subdivisions or new upgrades—the ability to change out their grid and maybe change conductor size to be more effective. From a DERMS perspective, it’s, again, that insight into what we have, where can we control, maybe that we can defer, then improve, generation costs or other things within that network.

Brown: From the ADMS side, it comes down to resiliency. System resiliency is one of the biggest things they’re going for, and rightly so. I mean, that’s what it’s built around.

From the DERMS side, it gets a little more interesting in that, it can enhance system resiliency. It can also save generation costs, especially over time. I think we’re going to see some efficiencies as we start to really monitor the way the power is delivered over the grid in a more advanced manner. And we’re going to be able to leverage our customer-deployed renewable resources.

You’re seeing more and more customers’ microgrids, or even house systems, being put on the grid. We need to be able to monitor and manage and watch what that does. But we can also use those inputs to the grid in a more efficient manner and use them to enhance reliability and lower overall energy costs. There are a number of utilities who have plans to defer additional generation built by the utility by leveraging customer-based renewal resources. And I think there’s some reality in that over time.

Bartak: The ADMS and the DERMS help enable advanced functionality to have more automated control or switch order management, FLISR—fault location, isolation, and service restoration. Being able to do those things, create the programs, understand how we can recover more customers, and have those schemes set up by having that advanced program can send out and dispatch in a lot quicker fashion.

Both those systems enable a lot more key decision-making that in the past would have resulted in a truck roll to a substation to then go drive the line. Now, we can potentially have better direction: “Hey, it’s going to be on feeder A and check spans 3 and 4, because I believe, based on customer outages and FLISR restoration, that’s going to be your best bet.” So, it really does help the troubleshooters in the field.

—Aaron Larson is POWER’s executive editor (@POWERmagazine).