by Jeff St. John
February 14, 2017

This year’s DistribuTech conference in San Diego added up to three days of nonstop information about the state of the utility industry, from the opening ceremonies to the last-minute deals being cut on the way to the airport. It’s hard to cover such a large event that covers so many subjects.

Topics ranged from traditional subjects like advanced metering and substation automation, to the latest trends like microgrids, the internet of things, and, of course, distributed energy resources (DERs). And that doesn’t include what’s happening on the showroom floor.

We’ve already highlighted some of the key news from the annual conference. But that leaves out a lot of odds and ends collected over the course of the event -- starting with some prize-winning utility projects that are worth a closer look. I caught up with two of the three utilities that won awards at Tuesday’s opening, and got some more details on what they did to deserve them.  

APS and its first-ever residential smart inverter test

The first was Arizona Public Service, which with the help of the Electric Power Research Institute and its vendor partners have built a technology framework for making individual rooftop solar inverters part of its distribution grid operations. That’s something that a lot of utilities have talked about doing, but which very few, if any, have turned on in the real world.

“As far as we know, this was the first direct utility control of advanced inverters,” Scott Bordenkircher, APS’ director of T&D technology innovation and integration, said in an interview. Over the past one and a half years, APS has equipped about 1,600 homes with west-facing solar panels and SMA inverters, linked via cellular or AMI networks to a substation control system it has co-developed with Siemens, he said.

“What the customer got was a $30 a month credit on their bill for 20 years. We essentially leased their roof -- that’s the compensation, they know what it is -- and we can do whatever we want," said Bordenkircher.

Chief on that list was the ability to inject or absorb reactive power, which can help stabilize surges or sags in voltage that can affect solar-rich distribution feeders. “If you get outside the voltage standards, you start to cause a lot of problems. You’ll actually start to trip off old inverters.”

Over a nine-month test period, APS and EPRI ran the inverters through a long list of test capabilities, based on the template laid out by California’s Smart Inverter Working Group, he said. “We did pretty much every mode of operation that the advanced inverter has -- direct volt/VAR, direct volt-watt, curtailment -- we messed around with the curves in terms of when reactive power came on and off,” he said.

Finally, unlike most of the other small-scale smart inverter tests that have been done so far, APS tested "much they can move the needle" with a large density of the devices.

The results varied pretty significantly from feeder to feeder, he said. “Every feeder really is different -- the length, the structure of it, is it just radial, does it have a lot of taps, what the sizes of the loads are,” he said. “We have two relatively equally populated feeders in terms of PV, and in one case, we were able to help improve the hosting capacity, manage voltage, and in the other, we weren’t.”

As for how many circuits could use smart inverters for these needs across APS territory in a cost-effective manner, “We don’t have that answer yet,” he said. However, APS is doing a feeder-by-feeder analysis with that aim in mind. The week before DistribuTech, the utility took its advanced inverter control live with its Schneider advanced distribution management system -- first as a relatively simple linkage with its outage management system, but with tighter integration with distribution-grid SCADA coming in the next few months.

"This research will take us in a couple of directions. One is very much considering changing our interconnection standards, [and for] that, smart inverters are required. The other thing is starting to mandate that the utility has the ability to set, or at least dictate, what the settings are, for that advanced inverter," said Bordenkircher.

CPS and AutoGrid’s all-together demand response platform

The second prizewinner I spoke to was the San Antonio municipal utility CPS Energy, which was recognized for its integration of some 160 megawatts of mixed demand response, from big commercial and industrial loads to bring-your-own-thermostat programs, under one platform.

The project features a host of partners, including Nest, Cooper and Honeywell on the BYOT side, and the fast-acting residential demand response platform built by Landis+Gyr’s Consert, as well as the site-by-site arrangements at C&I customer premises. For Wayne Callender, CPS’ zero-emissions resource manager, that's all just the demand-side part of the equation he has to manage each day to keep the utility’s clean energy resources in balance.

“Most utilities grew into demand response, starting small, and then growing to the point where it was a big enough load drop that our operations engineers were starting to see it,” said Callender. “My colleagues are all the real-time grid operators -- I report to the same guys. Out goal was to bridge the gap between customer-facing programs and asking how we can monetize this in the market.”

To tie together those disparate behind-the-meter resources, CPS put out an RFP in 2015 for a demand response management system, or DRMS. In early 2016 it hired AutoGrid, the Silicon Valley startup with 2 gigawatts of demand-side resources under management via its big-data software platform. Over the next two months, AutoGrid was able to integrate about 370 customers with 60 megawatts of C&I load in time to put them through approximately 20 DR events over the course of the summer. That's a pretty fast turnaround for such a complex project. 

The basic function of a DRMS is to take all the different processes CPS has put in place over the years, and combine them into one operations platform. "We got some good feedback from the operators -- they’re used to logging into the AutoGrid system, they’re used to the look and feel of it now,” said Callender.

Beyond that, CPS is looking to use AutoGrid’s forecasting capabilities, as it did to reduce consumption during last summer’s four Coincident Peak days, and implement a customer portal for C&I customers to get their data without the hassle of contacting their account managers. CPS is also integrating AutoGrid into its meter data management system, provided by Siemens’ eMeter, to provide the same functionality to its small business and residential customers.

AutoGrid has been expanding its share of demand response and distributed energy management projects over the past year, CEO Amit Narayan said in an interview. But while these systems come under a variety of names -- DRMS, DERMS, virtual power plants -- at the end of it all, “everything is flexibility on the grid edge," he said.

The same concept is being replicated by software and grid vendors and utility partners across the spectrum, as we covered in our on-the-spot coverage at the event.

DOE grid edge funding expands, with "infrastructure" as the new buzzword

One of the big questions floating around DistribuTech was what will happen to key federal funding streams under the Trump administration. For now, some of the Department of Energy’s grid edge R&D grants are going forward as planned.

Specifically, on the first day of the conference, DOE’s SunShot program announced up to $30 million in additional funding for 13 projects under its newly launched Enabling Extreme Real-Time Grid Integration of Solar Energy (ENERGISE) funding program. SunShot program director Charlie Gay noted in an interview that this funding opportunity was first launched in May, with a particular focus on integrating existing infrastructure -- including the grid itself and the software platforms now in place to manage it -- with a distributed energy future.

Along with several six-figure grants to universities and DOE research labs, ENERGISE is giving out millions of dollars to a handful of utilities, most of them in California, to build out an “enhanced system layer” of software atop their existing device, telecommunications and control systems.

These include $3.24 million to Texas-based Pedernales Electric Cooperative, the country’s biggest distribution co-op; $6.5 million for Pennsylvania’s PPL; $3.2 million for the City of Riverside Public Utilities; and $4 million for Southern California Edison.

Several of the projects involve software startups we’ve been tracking, such as Smarter Grid Solutions, the Scottish startup that’s now working with SCE and the City of Riverside Public Utilities, and Canadian startup Opus One, which is working with Pedernales in Texas.

Another big winner of the ENERGISE program is Advanced Microgrid Solutions, which is the lead contractor on the Pedernales project and a participant in Southern California Edison’s work. And while the project in Texas is a new deployment, featuring a relatively small 500-kilowatt-hour battery, its California project could eventually tap the megawatts of batteries it’s already deploying for SCE.

“The idea is to take advantage of our existing installation with the Irvine Ranch Water District,” said Audrey Lee, the startup’s vice president of analytics and design. That 50-megawatt battery has already been contracted to SCE to provide resource adequacy during times of peak grid demand. But that leaves a lot of hours of the day when it could do other valuable tasks, she said.

One of the goals of the ENERGISE grant is “to show that energy storage can either absorb some of the excess electricity being provided by solar, or if there are voltage issues, to provide real and reactive power” from the system’s inverters, she said. That’s a lot like the work being done by APS, only with one big array of inverters rather than lots of smaller ones.

At the same time, SCE and its partners are looking into the planning side of distribution grid integration via “DER self-provisioning,” she said. “A lot of the challenges of solar integration lie in the interconnection studies required,” she said. “The goal of the grant is to show DER self-provisioning in less than five days,” rather than the weeks that the current processes can take.

SCE is already planning to spend hundreds of millions of dollars to build a new software “system of systems” to manage its distribution grid and DER needs. Its new ENERGISE work is “leveraging and expanding on SCE’s Integrated Grid project,” funded by a California Energy Commission’s EPIC grant, and will incorporate the circuit-level capacity and planning data the utility is doing under the state’s Distribution Resource Plan (DRP) proceeding.

A cybersecurity "sniffer" for the AMI network

This year saw a lot of new offerings from advanced metering infrastructure (AMI) vendors to bring distributed intelligence and “internet of things” capabilities to their networks. The list includes Silver Spring Networks and Itron’s latest IOT expansion, new distributed energy support from Honeywell’s Elster and Toshiba’s Landis+Gyr, and enhanced distribution network features from ABB and Oracle.

Most of the country’s smart meters operate in the unlicensed 900-megahertz band and communicate through mesh networks that transfer data from meter to meter in “hops” toward a set of centralized data backhaul points. It’s a lower-cost way to collect data than cellular or broadband connection to each home.

But according to Tony Bogovic, vice president of cybersecurity firm Vencore, it’s open to intrusion by parties that can tune their radios to the same unlicensed bands to collect private data, or even inject data with malicious intent. 

On the floor at DistribuTech, Vencore was showing off a new device that watches over these types of mesh networks in real time. “These are probes, they’re sensors, and they passively glean what’s out in the radio network,” Bogovic said. And because they’re linked to the utility operations center by real-time cellular networks, they can offer insight faster than the mesh network itself can, he noted.

That could help utilities manage AMI radio frequency (RF) security, a topic that’s been on the minds of grid researchers for years now. “Most of the solutions out there are IP-oriented -- malware detection, firewalls, all the tricks of the trade. But on the RF side, for intrusion detection, you don’t see much going on except for what we’re doing.” That’s a problem, because a hypothetical hacker could render meters across a neighborhood mesh system inoperable with a single packet of data, he said.

This isn’t a hypothetical use case. Vencore’s demos used data from real utility deployments, including a screen that referenced Baltimore Gas & Electric. Bogovic wouldn’t identify any of the utilities his company is working with, but he did note that Vencore’s real-time mesh network traffic data analysis can be used to troubleshoot network problems, find misplaced meters, and perform other tasks with value beyond catching cyber-intrusions.

“We have two sorts of customers,” he said. “One is those that are in initial trials, they’re piloting solutions, and the extra visibility that we provide into their communications helps them with their evaluations. But also, after utilities have deployed AMI and have had it operational for some period of time, they realize that they could use tools like this to help with meters that they’re not getting to, or with intermittent issues associated with performance.”

Some of Vencore’s initial work on this front was funded via DOE’s Cyber Energy Delivery System (CEDS) program, which since 2013 has directed $210 million to "collaborative cybersecurity research and development projects among industry, universities, and national labs. “We built out some of these applications in particular” to meet the goals of previous grants, said Bogovic. "What the DOE recognized is that there’s exposure in AMI, and they used our technology to provide the industry with potential solutions.”