How Arizona Public Service is preparing for the grid of the future
New offerings point to the need for a unified control systems to manage DERs on the grid
Back in 2014, two Arizona utilities put the industry on notice when they asked regulators for approval to install rooftop solar as a regulated utility.
Tucson Electric Power, which serves 414,000 customers around the southern Arizona city of Tucson, proposed a 3.5 MW program. After paying a $250 application fee, solar customers under TEP’s program would be locked into a new, lower rate for 25 years. Regulators approved that program in the same month, and TEP is now looking to expand the program, CEO David Hutchens told Utility Dive this week.
Further to the north, Arizona Public Service, which serves 1.2 million customers around Phoenix, floated a different utility-owned solar pilot project. APS proposed to install 20 MW of solar on the utility side of the meter on rooftops across its service area, giving customers a monthly $30 bill credit for letting the utility use their roofs. Regulators scaled the proposal back to 10 MW, amounting to about a 1500-customer pilot program.
At the time, rooftop solar and other distributed energy resource (DER) providers expressed concern with the state’s regulated utilities moving into one of the nation’s most vibrant solar markets. With the utility’s strong customer relationship and established presence, installers worried that more mature utility solar offerings would have an unfair advantage in the residential solar and DER marketplace.
But to hear APS tell it, that concern misunderstands the intent of the utility’s move into rooftop solar, at least for now. Instead of testing the waters for a broader move into rooftop solar installations on its own, APS's Director of Technology Innovation and Integration Scott Bordenkircher told Utility Dive that the Solar Partner Program (SPP) was really all about learning how to better handle high penetrations of DERs on its system.
“There’s nothing written large that this is going to supplant current [rooftop solar options] already in place,” he said, “but it was really to get us in the game from the perspective of we've got some grid problems occurring because of higher levels of [DER] penetration.”
Utility Dive caught up with the APS technology integration lead at the DistribuTECH conference in Orlando this week, the nation’s largest power distribution gathering. In addition to studying rooftop solar through its SPP program in 2016, Bordenkircher said APS will install two new microgrids in its service area and begin a pilot program to test a full suite of customer-sited DERs. The programs are expected to provide valuable insight into how to manage various distributed resources on the grid — and point to the need for a unified control system in the future.
Studying rooftop solar
At the outset, the APS rooftop solar program was notable for its differences from the offerings from third party providers like SolarCity. Instead of more complicated financing contracts based on the expected output of the panels, APS proposed to pay a simple $30 roof rental fee each month to customers whose rooftops are used for the pilot, and it installed the systems on the utility side of the meter.
Bordenkircher said the utility chose that model for its rooftop solar pilot because the intent is not to test it as a business model for later expansion, but rather to study the impacts of higher penetrations of solar.
“Right now, the best thing about our leasing model where we're leasing the rooftop really is that we have complete control over energy produced … which we really needed from the perspective of research,” he said. “We really needed to be able to turn it on, curtail it, turn it on, curtail it, [and assess] what's that doing to the rest of the voltage and everything else on the grid.”
Toying with the output of a rooftop solar array like that is “clearly not a good model” when a consumer is counting on the generation to offset their utility bill, but Bordenkircher said that if the pilot goes well, it could evolve into a larger rooftop solar offering from the utility years down the line.
“Where we go from there, we'll see. The research is really going to be the identifier of that,” he said. “As with all customer choice, I think you're going to have several options and I think customers are going to exercise those options.”
While the Solar Partner Program aims to test the capabilities and challenges of rooftop solar from the utility side of the meter, APS is also looking to assess a fuller suite of DERs sited behind the meter.
To that end, the utility just began the first round of customer acquisition for its Solar Innovation Study, which Bordenkircher called “a natural extension” of the SPP program.
In what APS calls a “rate laboratory,” the study will select 75 single-family households to receive a rooftop solar array and a number of energy management and DER products. APS will then put the consumers on a rate structure that includes time-of-use rates and demand charges in an effort to assess how customers respond to those price signals when they have access to various self-generation and energy management technologies.
In all cases, Bordenkircher said, participants will get rooftop solar. Some will also receive residential battery storage, load controllers and home energy management technologies, as well as high-efficiency, variable-speed HVAC units “to see if we can do the pre-cooling thing.”
The goal is to assess not only how APS can best provide new products and services, “but also then from a customer perspective, if we give you this stuff, what are you going to do with it? What's your take on it, and are you that interested?” Bordenkircher said. APS will be studying how the customers respond to new rate structures, particularly a residential demand charge.
The aim of the program could be thought of as creating the energy pro-sumer of the years to come, Bordenkircher said, so that if and when these technologies become truly widespread in its service area, APS is ready.
“I think it puts us in a much better position to understand impacts we're having now and what we can do to provide our customers with information and potentially different services and products,” he said. “We really have had a goal for quite some time to really be that energy partner, and how you really truly engage customers beyond them sending a check once a month, that's something that's really interesting to us, and this is part of that next step on how to become more involved.”
New microgrid projects
In addition to its solar studies and two, 2-MWh battery arrays it plans to test in 2016, APS is making inroads in the microgrid space, finalizing two new projects at the end of last year — one with a Marine Corps air base in Yuma, Arizona, and another with an undisclosed data center customer.
While separate from the solar and storage initiatives, the programs are on “two parallel paths going down close to each other on the same track,” Bordenkircher said, since all of them will provide meaningful insight into how to manage a diversity of distributed resources on the grid.
At the outset, the two microgrids won’t have any solar or storage at all, and will instead run on high-efficiency diesel generators. But they are being designed so that cleaner resources can be added “when it’s economically viable,” Bordenkircher said.
The utility’s microgrid offerings are focused on three areas — defense industry, critical infrastructure (fire, police, water, etc.) and “economic development,” the APS technology head said. The undisclosed data center customer is a prime example of the latter, in that APS was able to convince the customer to site their facility in Phoenix based in part on the utility’s willingness to share the cost of backup generation.
“We had a data center company that was looking at three states for where they wanted to move in and we were able to put in front of them an offering along with the Arizona economic development group and they said Phoenix is where we want to be,” Bordenkircher said.
Customers like data centers or military bases with must-run operations plan on installing backup generation with or without a utility, he said, but when a utility shares some of the cost in constructing a microgrid, it can use the backup generation assets for grid services when not in use by the customer. In the case of the diesel generators at the data center and Yuma air base, the microgrids will give APS “the ability to run those units for frequency response, for local peak shaving, or whatever else we might need.”
In that way, APS is not only gaining a new resource for addressing grid needs, it’s helping create demand by attracting key accounts to its service area with microgrid offerings.
“We called it a triple win when we started,” Bordenkircher said. “It had to be a win obviously for the end customer that's providing the cost share, it had to be a win for the utility from the perspective of this provided some level of resiliency or something that … maybe would offset other expenses or other capital purchases, and then it had to be a win for our customers at large, because really they're the other cost sharing part of this.”
At present, customers at large aren’t on the hook for the project. At a later panel discussion on microgrids, Bordenkircher told the audience that APS financed the microgrids through shareholder dollars at first, and will look to recoup the costs from ratepayers in its next rate case.
“We did not ask for regulatory approval ahead of time,” he said. Proving that the microgrids provide benefits to all ratepayers, and not just the specified customers, will be essential if the utility wants to rate base future microgrid investments.
But whether or not they are able to rate base investments in the future, Bordenkircher was optimistic about the potential for more microgrids that offer the utility new resources for grid services while also providing reliable power to key accounts.
“Lots of companies who have backup generators sit there and do nothing but get tested once a quarter or whatever their cycle is,” he said. "So being able to harvest that value from really that kind of stranded asset is really kind of exciting.”
The future grid: Controlling DERs
While programs like the solar innovation study and new microgrid offerings have the potential to teach utilities a great deal about how to optimize their distribution grids, they also uncover a new need — a single Distributed Energy Resource Management System (DERMS) to automatically monitor and control various DERs across the distribution grid.
“I think whether it's inverters, whether it’s battery storage, microgrids or combinations of those, definitely utilities will have to look toward how we construct a management system of those systems,” Bordenkircher said.
While APS is currently testing DERs in multiple programs, he said, but the bigger question going forward will be “how does DERMs really work, because you’re going to have to cross all these technologies.”
The need for a good DERMS system to control multiple DERs is not unique to APS. At the microgrid forum on Tuesday, Jeff Geier, vice president for transmission and system engineering at San Diego Gas & Electric, spoke about the Borrego Springs microgrid, one of the first renewables-plus-storage microgrids in the nation.
When asked about lessons learned from the project, Geier did not hesitate in naming DER control systems as an area that needs to be addressed. “It’s pretty rough still,” he said.
But it’s not just utilities with lots of solar like APS and SDG&E that are expected to explore DERMS systems in 2016 and beyond. GTM Research sees the sector moving in that direction as DER penetration increases, and the group forecasts that the DERMS market will grow from about $50 million last year to $110 million by 2018.
“The market will double,” GTM Senior Analyst Omar Saadeh told Utility Dive late last year, “as utilities invest in platforms that meet their specific needs.”
For APS and other utilities, the need for a DERMS system is becoming clear now.
“Whether it's a distributed system whereby you've got more edge intelligence or whether it all comes back centrally, some of that architecture needs to be worked out,” Bordenkircher said, “but you're definitely going to need a system, because you're not going to have an operator sitting there 24/7 trying to control several hundred random things on the grid."
Correction: An earlier version of this article referred to Bordenkircher by the first name of Steve. His name is Scott.
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