by Jeff St. John
October 23, 2020

This is the third installment in a GTM Squared report examining the discrete paths toward distributed energy resource integration being taken by different states. Our first two pieces dealt with California and New York, two states with ambitious clean-energy and carbon-reduction mandates and wholesale energy markets.  

This week’s installment focuses on Arizona, a vertically integrated state with a checkered record on clean energy and distributed solar policy. But it's one where utilities are increasingly coming around to incentivizing customers to enlist their solar systems, behind-the-meter batteries, and price-responsive loads to meet their decarbonization goals.  


Arizona is one of the most solar-saturated states in the country, ranking fifth in overall solar capacity and third for residential rooftop solar. It’s also one of the hottest states in the country, with climate change pushing that heat to record levels this summer. This combination is pushing the Republican-dominated state’s energy policies in increasing alignment with its Democratic-controlled, solar-rich and climate-change-wracked neighbor to the west. 

While Arizona lacks California’s aggressive renewable-energy and carbon-reduction mandates, that could change soon. The Arizona Corporation Commission (ACC) is debating whether to expand current renewable mandates from 15 percent by 2025 to 50 percent by 2030 and mandate carbon-free energy by midcentury, with a decision possible by month’s end. 

Meanwhile, Arizona utilities are making massive investments in utility-scale solar and batteries, backing out of coal-fired power, and setting their own carbon reduction goals. The state’s biggest investor-owned utility Arizona Public Service has set its own goal of zero carbon by 2050, starting with 65 percent clean power by 2030. Tucson Electric Power plans to reach 70 percent renewables by 2035, and sprawling municipal utility Salt River Project plans to cut emissions by 62 percent by 2035 and 90 percent by 2050. 

And while Arizona’s utilities have earned a reputation for fighting the spread of customer-owned solar, they’re now starting to embrace distributed energy resources (DERs) such as solar, batteries, electric vehicles and smart appliances. That’s largely been led by utility managed pilot projects, but it is spreading to include incentive programs to boost customer adoption to help manage the shift to a decarbonized grid. 

Arizona’s vertically integrated utility regulatory structure doesn’t provide wholesale energy market opportunities for DERs, which are set to expand significantly under Federal Energy Regulatory Commission Order 2222. But APS’ integrated resource plan relies heavily on customer-sited DERs and efficiency and demand response incentives to reach its goals of 65 percent carbon-free energy by 2030. And its vision for integrating those resources in a way that merges traditional grid planning with incentives and pricing to enlist customer-owned DERs offers an intriguing model for other utilities. 

A sun-drenched state’s checkered record on distributed solar

As the ACC closes in on a plan to boost its renewable energy goals, DER advocates are demanding a boost for distributed energy’s role as well. A proposal from Sunrun, the Arizona Solar Energy Industries Association, Solar United Neighbors, Vote Solar and Coalition for Community Solar Access is asking the ACC to require that 10 percent of the state’s aggregate peak demand by 2030 be met with energy storage, half of it distributed. 

These groups are also proposing a community solar program for Arizona, something that’s only been offered in one-off utility programs to date. The new plan is “designed so that both private entities and third parties could own it — that could include nonprofits, government agencies, municipalities,” said Art Terrazas, interior West director for nonprofit group Vote Solar.

“We’re creating a framework where we could have more solar and storage for private customers to take on,” including “a carve-out that includes low-income communities,” he said. “Our bottom line is that we need to make sure this technology is available to people because it is now the cheapest source of energy across the board.” 

Arizona might have even more rooftop solar if not for a series of market-roiling policy shifts over the past decade. Starting around 2013, Arizona’s biggest utilities started proposing demand charges and monthly fees to address the “cost shift” from net-metered customers to those without solar. Solar groups condemned the plans as utility attacks on customer energy choice, and APS’ spending to boost favored ACC candidates muddied the political picture.   

Eventually, APS and Tucson Electric Power agreed to an ACC “value-of-solar” plan that yielded a 2016 decision to replace net metering with solar export credits tied to the value of utility-scale solar pricing. This policy has slightly reduced the economics of rooftop solar, with 10 percent annual declines in export values putting today’s values slightly below retail rates. (The ACC voted in September to halt those annual reductions through 2022 to avoid burdening solar-equipped homeowners amid the COVID-19 pandemic.) 

Salt River Project, the state’s second-largest utility and one that’s not under ACC’s jurisdiction, imposed a far more costly demand-charge regime on solar customers in 2015, leading to a major drop-off in rooftop solar installations. A lawsuit from SolarCity (now Tesla) was settled in 2018, with SRP agreeing to contract with Tesla for a utility-scale battery project and fund a pilot program and battery incentive for residential customers. Another lawsuit brought by SRP customers is being appealed after having been rejected in federal court. 

Randy Miller, one of four pro-solar SRP board members winning election after the demand charges were put in place, noted that the utility has since opened alternative rate plans for solar customers, with a focus on reducing or prohibiting exported power. He doesn’t think much of them: “Now we have three crappy plans,” he said in an interview this week. 

But he did note that SRP is taking steps to understand how solar can be added to its distribution grid. “They’ve been doing a pretty good job so far of doing energy efficiency programs. [...] I’ve been trying to frame renewable energy in the same way — not as a competitor, but as resources we can use to lower our peak.” 

Energy storage, grid integration and interconnection challenges

These changes, along with time-of-use rates at APS and Tucson Electric Power (TEP), have created conditions in which behind-the-meter batteries are making more economic sense to capture solar energy for self-consumption or demand charge reduction. But solar-linked batteries can also perform valuable services for the distribution grid. 

Arizona utilities, like those in other distributed solar hotbeds, are worried about backfeeding power on distribution circuits causing grid disruptions or driving costly grid upgrades. Unlike most other utilities, Arizona’s APS and TEP have won regulator approval to own some rooftop solar and behind-the-meter batteries to find ways to mitigate these problems. 

Solar companies fought these programs as an unfair infringement on their markets, and the ACC limited the scope of these programs. Still, projects like APS’ Solar Partners Program have helped inform both sides on the value of being able to modify the flow of solar onto grid circuits, tap smart inverters to stabilize voltage disruptions and store power to reduce peak demand at a local and systemwide level. 

One of the most immediate applications has been reforming Arizona’s grid interconnection regime. Earlier this year, the ACC approved new interconnection rules for the state’s investor-owned utilities, meant to streamline the process for approving solar and battery projects. 

“The big progressive step in these rules is the detailed treatment of storage,” said Ken Wilson, engineering fellow with environmental group Western Resource Advocates. Those include defining the process for interconnecting non-export and export-capable systems, and built-in assumptions that solar-storage systems won’t simultaneously export power in ways that could overwhelm circuit hosting capacity.   

Arizona’s new rules also lay the groundwork for customers and utilities to agree to DER operating parameters that could reduce the need for distribution system upgrades, much like California’s recent Rule 21 revisions do, he noted. Being able to tap the control capabilities of the latest generation of smart inverters “should allow a bigger hosting capacity on many feeders,” he said. 

Tighter integration of utility and DER operations could help resolve interconnection bottlenecks like those that have plagued TEP in recent months. After the utility denied a small subset of solar system applications on its system, the Arizona Solar Energy Industries Association complained that the denials violated the state’s new interconnection rules and demanded it conduct a hosting capacity analysis to show real-world grid conditions.

TEP responded by noting that only 6 percent of the sub-20-kilowatt solar applications it’s received under the new rules have been denied. About one-fifth of those have been able to connect under no-export restrictions, it said. TEP also highlighted its work on analyzing 16 capacity-constrained feeder circuits to develop a plan to upgrade them and broader hosting capacity. 

Utility pilot projects using behind-the-meter batteries to help moderate peak load could indicate a path to solve these kinds of interconnection problems, Wilson noted. “When the solar providers start complaining that more feeders are now unavailable for hosting, then this issue will become important at the ACC.” 

A holistic approach to the behind-the-meter resource mix

By storing excess midday solar production to mitigate late afternoon and early evening demand, batteries can also ease the “duck curve” demand-supply imbalances caused by solar’s rising share of Arizona’s energy supply. But batteries alone won’t be able to solve the challenge — at least, not cost-effectively.

That’s the view laid out in APS’ integrated resource plan. In the next five years, APS plans to add 962 megawatts of utility-scale renewables, about 400 megawatts of rooftop solar, and 750 megawatts of large-scale energy storage. But it’s also planning nearly 200 megawatts of demand response, and another 575 megawatts of “demand-side management” — a category that’s traditionally encompassed energy efficiency and programs to reduce overall consumption. 

But APS sees demand-side management (DSM) more as a set of tools to reduce its summer evening peak demand and increase electricity consumption when solar power is plentiful. That could allow it not only to solve its own grid needs but also to take advantage of California’s even more pronounced solar-driven imbalances, which have led to low or even negative prices for neighbors that can absorb its excess supply. 

Batteries can do that, but so can smart thermostats and water heaters that “store” solar power in the form of precooled homes and preheated water. All three are combined in a set of APS programs, now entering their third year, that faced their biggest test during the August heatwaves that covered the Western U.S. and forced California to use rolling blackouts to ease an overtaxed grid.  

Arizona’s utilities were under similar stress but avoided blackouts, partly from tapping the flexibility of these new programs, said Tom Hines, former APS energy efficiency program manager and consultant to its ongoing DSM efforts. Most of that came from its Cool Rewards program, with nearly 40,000 smart thermostat-equipped homes shaving load during the 10 times they were called this summer, four of them in August. 

While customers are allowed to opt out of turning over their air conditioning, “customers really hung in there,” he said, largely due to precooling that mitigated the heat they had to suffer through. Compared to traditional air-conditioning switch programs, which essentially offered customers the proposition of “we’ll pay you to be uncomfortable, these new programs are much smarter.” 

Cool Rewards got APS about 42 megawatts of peak load reduction, while its Peak Solutions commercial demand response program yielded another 36 megawatts over the five days it was called on this summer, he said. By next summer APS expects to be able to gain 100 megawatts of smart thermostat load reduction and plans to grow its commercial demand response to 75 megawatts. 

APS’ smart water heater and connected battery program, dubbed “Reserve Rewards” and “Storage Rewards,” respectively, haven’t grown nearly as fast as its smart thermostats, but are expected to expand over the coming years. Water heaters, along with pool pumps and other big household loads, are particularly useful for absorbing solar power encouraged by cheap midday prices. 

APS recently approved residential battery pilot will further integrate energy storage into its grid management plans, with $3 million in incentives of up to $2,500 per customers or about one-third of the price of a typical installation, he said. Unlike its previous utility-controlled Solar Partners systems, “we’re taking a somewhat hands-off approach — we’re not going to control the battery.”

Instead, it will be tapping the same integrated DER management platform orchestrating its smart thermostats, water heaters, pool pumps and other demand-side devices to track how the batteries respond to time-of-use prices. “It’s more of a data program, to look at a future of what pay-for-performance might look like.” 

Electric vehicle chargers will form more nodes in the demand-side network APS is building, through a partnership with public charging provider ChargePoint and time-of-use pricing for home chargers. Arizona has about 40,000 EVs, some 16,000 of them in APS territory, said APS electric transportation adviser Kathy Knoop. It’s not a big challenge yet, like a water heater or an air conditioner,” she said. “We have a little more time to get these incorporated in the right way.” 

A distributed energy plan to meet long-term goals 

Viewing DERs in a holistic manner is critical to find the most cost-effective combination of technologies to meet APS’ overall goals, said Tyler Rogers, vice president of utility sales for EnergyHub, which provides APS’ orchestration software. It’s also an important step in assuring that price signals to thermostats and appliances can be as reliable as utility-dispatchable batteries to grid operators that will rely on it. 

That requires a radical reconsideration of the role of energy efficiency, demand response and other traditionally siloed utility programs, Hines said. “A few years ago, we would be doing programs that would be saving energy at the same time we were curtailing solar.” 

APS’ new goal is to align its incentives and pricing structures to encourage customers and DER providers to match the load shapes of an increasingly clean-powered system. “There’s a science to that, but there’s also an art to it, because it does involve human behavior,” he said. “We put a matrix together, adding what’s the initial investment, what’s the payback period, how much do they save per year versus what’s our cost per hour of savings for the grid,” he said. “That maximizes our value per megawatt while also giving our customer an acceptable payback.” 

It also provided an opportunity to orchestrate DERs in ways that can be folded into the long-range plans contained in its integrated resource plan, said Judson Tillinghast, APS’ customer to grid solutions product development and strategy leader. 

APS has been working with Advanced Energy Economy on exploring next-generation approaches to solving this challenge. Target projects range from electric school buses that can power the grid while parked, to generating hydrogen at the Palo Verde nuclear power plant to provide zero-carbon fuel for peaker plants. 

Another focus is on structuring programs that can allow grid planners to compare the values of aggregated DERs to traditional power plants, from their ramp rates and operating limits to their cost per megawatt-hour across all 8,760 hours of the year. 

“When our resource adequacy team goes out to procure a new resource, they can compare and say [whether a particular] demand-side aggregated resource is just as reliable as this traditional resource,” he said. “That will be a fundamental change to increase adoption of DERs across the country.”