by Jeff St. John
November 30, 2018

We regularly track the states that are integrating distributed energy resources (DERs) into their utility distribution grid planning and operations, from vanguards like California, New York and Hawaii, to more nascent efforts in Nevada and Minnesota. 

Now it’s time to turn to Arizona, a state that’s also struggling to adapt to the impacts of booming solar growth — and not just inside its own borders. 

Earlier this month, Arizona Public Service launched a pilot project that could serve as the state’s broadest DER integration effort to date. It’s with EnergyHub, maker of a distributed energy resource management system (DERMS) platform that will be controlling a host of grid resources — connected thermostats, water heaters, battery energy storage, and solar inverters, specifically — to “dynamically manage its portfolio of grid-edge devices through peak demand reduction, load shifting and renewables matching, and solar inverter management and curtailment.”

This isn’t the first time APS has tested the capabilities of DERs to manage local and system-wide grid imbalances. "We’ve done significant work, some industry-leading work on advanced inverters and solar integration," Marc Romito, APS’ director of customer technology, said in an interview last week.

APS’ Solar Partner program, for instance, has broken new ground in terms of large-scale testing of advanced solar inverter capabilities, with 1,600 PV-equipped homes participating. Its Solar Innovation Study is pairing behind-the-meter batteries from Sunverge with home energy management systems for grid optimization. 

But the new project with EnergyHub is an effort by APS to “look at energy efficiency and demand side management totally differently,” he said. Specifically, the project grew out of APS’ efforts to modernize their traditional efficiency and DSM programs “to manage this imbalance due to excess daytime solar, and look at using these programs to integrate more of it.” 

The APS project also represents a new level of participation in utility grid integration, CEO Seth Frader-Thompson said in an interview. The Brooklyn, N.Y.-based company, which was acquired by Alarm.com in 2013, has about 40 utilities using its Mercury DERMS platform today, most of them in full-scale deployments, he said. 

"Most of them are doing relatively traditional demand response. There might be a mix of water heaters, EVs and thermostats, but they’re only doing like 10 to 30 events per year. The difference with this project — and I would say, most projects in the future — is that it’s every day,” he said. “You have a variety of resources you have to orchestrate dynamically, and it’s done every single day.” 

While the APS-EnergyHub project is still a pilot at present, it’s already gotten to a significant scale. “The thermostat part of the project is already live,” he said, with several thousand residential customers participating. And under a newly launched APS rate program, at least 200 smart water heaters have been installed in customers’ homes, Romito said. 

Solving the belly of the duck curve 

The APS-EnergyHub project is also unusual in another way, Romito said. It’s one of the few demand response programs out there that’s aimed not only at getting customers to reduce energy usage during certain parts of the day, but actually increase their loads at midday, when solar generation is peaking both within its territory, and across the region.

“Traditionally demand response programs were designed for peak shaving, but we wanted to take a look at the other side of the curve — the belly side," said Romito.

He’s referring to the “duck curve,” made famous by California’s grid operator CAISO, which shows how the state’s electricity demand-supply balance can get out of whack on spring and autumn days, when solar generation is high, but the air conditioning loads that make up a significant part of regional electricity demand is absent. The result is a big drop, or belly, in the demand-supply curve at midday, and a steeply rising peak, or "neck," in late afternoon and early evening, when solar generation is declining, and people are coming home from work and turning on all their household loads. 

APS has its own native solar generation creating these kinds of imbalances on its own system, he said. But it’s also seeing the effects of California’s much greater duck curve, in the form of negative pricing for energy on the regional Energy Imbalance Market (EIM), a Western U.S. real-time energy trading network that APS has been participating in since 2016. 

APS saved its customers about $30 million by trading on the EIM during its first year of participation, Jeff Burke, APS director of resource planning, said in an interview. While it hasn’t broken out how much of that is due to being able to take California’s excess energy at negative prices, it’s a significant and growing opportunity, he said. 

“It becomes a seasonal phenomenon, because people just don’t use that much electricity when the weather’s nice outside,” he said. “From an Arizona perspective, that’s 7 or 8 months out of the year.” And while APS has been operating its own generation fleet and existing demand-side management levers to try to maximize how much of this excess solar from California it can absorb, it’s anticipating that it will need many more tools to manage the increasing amount of solar expected to be added to the system in coming years.

APS’ response to this market dynamic was to launch new rates in September, dubbed Cool Rewards, Reserve Rewards and Storage Rewards, that offer customers super-low midday rates in exchange for allowing the utility to tap their smart thermostats, water heaters and batteries, respectively. The new rates are among the first in the country aimed specifically at encouraging people to use more energy at certain times of the day, along with the utility's long-standing higher time-of-use (TOU) rates for its peak period of 3 p.m. to 8 p.m.

The smart thermostat program, Cool Rewards, offers customers a free thermostat and $25 a month, in exchange for allowing EnergyHub’s platform to control them up to 20 times per year. On those days, EnergyHub will crank up the AC throughout the midday hours of excess solar generation, effectively creating thermal energy storage units out of pre-cooled homes, so that they can have their AC usage cut during the late afternoon into evening peaks.

APS has already seen some significant results from the Cool Rewards program in its first few months, Romito noted. “We’ve seen 1,600 or so currently active participants reach the same demand response equivalent of 386 residential batteries,” in terms of their peak reduction capacity — and at a cost of only about $1000 per thermostat, versus thousands of dollars for a behind-the-meter battery system.   

The Reserve Rewards program, which fully rebates the cost of an 80-gallon, utility controllable water heater, hasn’t had the same amount of time to show its effects, he said. But the concept of using them to pre-heat water at midday, so that they don’t have to use as much electricity to heat water during peak hours, is a well-tested one. Utilities have been doing it for decades — although usually via timers or one-way radio signals, rather than the two-way, real-time controls being implemented by APS and EnergyHub. 

Storage Rewards is the most constrained of the new rates, with only about 40 customers picked to receive a rebated behind-the-meter battery and a one-time $500 participation credit. APS has lots of experience in both behind-the-meter and grid-connected batteries, Romito noted. But “we didn’t want the whole thing to be dominated by chemical storage. Battery storage is great, it’s a great tool in the value stack,” he said. But they’re also a lot more expensive than smart thermostats, controllable water heaters, and other tools being enlisted in its new effort.

APS’ new rates are among the first in the U.S. to actively address the issue of negative pricing driven by excess solar. APS can’t actually pay its customers to use electricity, Burke said. That would open up incentives for them to game the system, or simply crank up every appliance in the house for no reason. But because the savings APS achieves on the EIM are passed directly to customers, participants are not only earning money for themselves, but helping their fellow ratepayers save, he said. 

Building a scalable DER management platform 

Beyond the groundbreaking application of new rates to control an array of load-modifying DERs, the APS-EnergyHub partnership has a longer-range goal, Romito said — to serve as the foundation of the utility’s broader DER integration and grid management evolution. And to do that, the platform has to be able to scale far beyond its current scope. 

“We no longer have a uni-directional grid — we’re bi-directional now,” with more and more distributed PV feeding back power to the distribution grid. “We have to worry about the thousands of feeders we have, and solving thermal or power quality constraints on those feeders.” 

Through its Solar Partners program, APS has shown that it can control thousands of smart inverters and scores of batteries to help mitigate those constraints on a handful of feeders, he said. “But what about when you have hundreds of thousands of systems?” 

APS is investing in a host of technologies to take on this challenge, including artificial intelligence and low-latency telemetry to support its distribution operations center, which monitors its distribution grid in real time. And while its work with EnergyHub is at the pilot scale at present, “the EnergyHub platform is a part of that system of systems that we’ll be building out over the years to come. They are the partner that’s executing our vision to manage each one of these devices, interactively.”

This is a pretty succinct summation of the challenge facing utilities and the companies providing the DERMS platforms that are starting to emerge across the country. While the DERMS moniker can be used to describe demand response platforms that don’t have much integration to the grid, or advanced distribution management system (ADMS) capabilities that don’t have much connection to behind-the-meter DERs, no utility has yet deployed a true “enterprise DERMS” platform that incorporates all levels of this integration challenge, according to Wood Mackenzie Power & Renewables research. 

There are good reasons why utilities have yet to deliver on an enterprise DERMS platform — the integration challenge is a daunting one. “You have a native operating environment for every single device,” Romito said. “When you layer similar devices in with non-similar devices, it’s become a much more complex resource.” And all of these DER resources have to be managed in conjunction with APS’s existing distribution grid operations — “the conventional grid is full of fascinating telemetry, and that has to talk to the greater system. “ 

EnergyHub is taking on some new challenges as part of the APS project, Frader-Thompson said. It’s already managing and optimizing millions of smart thermostats across the country, but primarily for the traditional goals of broader energy efficiency and peak load reduction, he said. The APS project adds the imperative to consume energy during solar-rich hours, and combining multiple devices. “If you look at the discrete services we’re providing, there’s a load-shifting element that’s important — think of it as flexible capacity,” he said. 

The APS project is also putting EnergyHub’s platform to use in managing smart inverters and batteries, though not in a direct control role, he said. Instead, EnergyHub is managing so-called “phase one” smart inverter capabilities — largely automated features like low-voltage ride through or reactive power support — in terms of collecting the data on their operations for later audits or reviews, he said. “You’re programming a curve, and saying, we need all these things to have the same curve set, and when they act, you can monitor what they actually do.” 

But in the process of building the real-time integrations to all of these systems, EnergyHub is also creating the platform that could be used for more active management of these smart inverters, he said. The first application on this front will likely be through remote updating of smart inverter settings in response to changing conditions: “You may have to periodically upgrade these settings, and the last thing you’d want to do is roll a truck” to do it. 

EnergyHub’s platform will also be critical in managing the combination of smart thermostats, water heaters, inverters and batteries to demonstrate how they can be operated in the most cost-effective manner, he said. But this cost-effectiveness calculation becomes much more complex when one considers that every action a DER can take has financial impacts for the customer, for local distribution grid operations, and at the system-wide level.  

APS isn’t just looking to integrate DERs to help manage its current grid and energy market challenges, he added. The broader goal of the pilot is “to show that you can make long-term planning decisions around this stuff. It used to be that demand response was the thing that was there, but you hoped you didn’t have to use,” he said. “If you’re using it all the time, you have to convince the distribution system operators, the transmission system operators, that it’s just as reliable” as traditional utility investments, “while still keeping customers satisfied.” 

Integrating DERs into utilities’ future grid and generation investment decisions has largely been driven by state utility regulators, as with New York’s Reforming the Energy Vision (REV) initiative or California’s Distribution Resource Plan proceeding. Arizona has seen a host of important regulatory decisions affecting rooftop solar net metering, customer demand charges, time-of-use rates and other policies that affect the state’s DER picture, Romito said. 

But APS has undertaken its pilot with EnergyHub and broader plans for DER integration without the push of a regulatory proceeding. “We’ve chosen to use a more sophisticated methodology in distribution planning,” said Romito. “We need to investigate what distributed energy resources can do to solve both thermal and power quality constraints. Can you do non-wires alternatives? Can you do capital deferral? There are so many use cases we need to understand, objectively and transparently.”