After a two-year hiatus, DISTRIBUTECH returned to the Kay Bailey Hutchison Convention Center in Dallas. With thousands of attendees representing utilities, vendors, policymakers, and industry analysts, the conference rooms and exhibit floors were jam-packed.
And while vendors and session topics ranged the full gamut, our team identified three questions that we field multiple times from utilities and vendors alike. Check them out (and our recommendations) below.
Walking the halls of Distributech, our team counted nearly 40 vendors proclaiming to offer DERMS solutions. How is anyone supposed to make sense of that many offerings – especially when their actual capabilities differ?
One starting point is to evaluate the use cases that each vendor actively supports today. Navigant and AutoGrid published a helpful table (see below) that outlines common DERMS use cases across distinct stakeholders: from the end customer to grid operators and wholesale market participants.
While nearly every DERMS provider claims to serve a wide swath of these, no DERMS provider today delivers all of these capabilities in one platform. Several focus primarily on the “beyond the meter” (or “behind the meter”) use cases, while others are geared more towards grid services or market participation.
Instead of looking for a one-stop shop, we recommend prioritizing the DERMS use cases needed for your utility and evaluating providers based on their ability to
You can do that by talking with vendors (and fellow utilities) about the real-world applications they’re supporting and their approach to scaling their architecture and orchestration strategies as more DERs come online.
From our conversations with utilities of all sizes, we know that scalability is top of mind. It’s also difficult for non-experts to evaluate. One initial exercise is to ask yourself: what information do I want informing how DERs are orchestrated, and does this provider use that data to inform their actions?
At Camus Energy, we’re strong proponents of utilizing context on real-time grid conditions (i.e. loading and voltage) to inform DER dispatch and evaluate whether DER behavior is achieving the intended results. If your DERMS solution lacks visibility into real-time grid conditions, it will struggle to manage increasing quantity and heterogeneity of DERs – and you’ll be disappointed. This is especially relevant for utilities subject to FERC 2222, where integration of DERs into wholesale markets will cause coordination to be a very real challenge very quickly.
We believe the best solutions for scalable DER orchestration are those that provide real-time situational awareness as an input for DER dispatch.
This one can be a pretty scary question. When chatting with one electric cooperative, they asked us “How am I supposed to prepare for EV adoption when I don’t know who is buying them until right before they want to plug in, and my transformer lead time is two years? Am I supposed to stock up on transformers in case lots of folks get Lightning F-150s? How would that not increase rates? But I can’t make folks wait 24 months to charge their truck, right? So what’s the reasonable middle ground?”
Dealing with change that happens faster than ever is tough. While utilities are and should be excited about the clean energy transition, managing that change is complicated and, at times, feels daunting.
Our recommendation is to start by identifying the “no regrets” investments that help improve your organization’s flexibility and ability to manage change. Often, the best “no regrets” investments relate to data. From laying down broadband for improved data collection and connectivity to investing in software that cleans, organizes, and visualizes operational data, there’s a lot that utilities can do to better understand what’s happening on their grid in real-time.
This focus on improving real-time visibility and building a robust data foundation was discussed in detail during the Distributech panel titled “No Regrets Investments for a DSO Future”. During the discussion, leaders from Vermont Electric Cooperative and Holy Cross Energy gave practical examples of their investments. [We’ll update this post with a link to the recording when it’s made available. Panel details are available here.]
Our response to cybersecurity-related questions typically focuses on three tips.
First, embrace a zero trust security posture. We offer more detail in this blog post (and are always happy to chat with utilities), but the general idea is that your system should be protected at all levels, not just the perimeter.
Second, we strongly recommend communicating with customer-owned devices outside of the utility OT system. That’s consistently echoed by utility experts too. In a panel discussion at Distributech on Monday, Chris Bilby of Holy Cross Energy spoke about how excited he was to call upon member devices. His colleague turned to him and said, “Great. Now get the DERs out of my SCADA!”
By doing so, utilities can prevent intrusion at the customer device level, which is both less protected and a much larger attack surface, from resulting in security risks for core utility operations.
Third, many of the most common security risks come from vendors or third-party support teams. In conjunction with moving to a zero trust approach, which limits access for vendors, ensuring that your vendors have robust cybersecurity policies is paramount. When it comes to security, you are often only as strong as the weakest link.
We enjoyed attending Distributech and speaking with a diverse set of utilities and solution providers. If you’d like to learn more about any of the topics above, contact us to set up a call.