Utility in Transition: What We Saw Inside APS April 19, 2018 | By Rachel Henderson Walking into the combustion turbine area at the Palo Verde Nuclear Generation facility, I adjusted my goggles, pushed my earplugs in a little further, and was immediately engulfed by hot air, every bone in my body vibrating from the sheer power of this machine. Clearly, my visit to Arizona Public Service (APS) was going to be radically different than my standard cubicle-inhabiting work week at the Smart Electric Power Alliance (SEPA). The Palo Verde Nuclear Generation facility is the largest nuclear facility in the United States, capable of producing 3.3 gigawatts (GW) of electricity. The SEPA team visits to the Palo Verde Nuclear Plant, standing inside of one of the turbine rooms. From left to right: Ryan Edge, Spencer Schecht, Janine Fiasconaro, Rachel Henderson, Jared Leader, Nick Esch, John van Zalk, Gary Ellars (APS Energy Innovation Program Consultant), and Erika Myers In the late 1950s, nuclear generation was a new, innovative technology that could provide substantial electricity to the grid. Until the 1980s, nuclear was seen as cutting-edge power. It was during that exciting time that Arizona Public Service and other nearby utilities invested in the Palo Verde plant, which became operational in 1986. Palo Verde’s story is not unique to the power sector. Technology everywhere has rapidly evolved in the past 40 years, so much so in the case of the electricity sector, that most of the nuclear generators and other baseload plants were functional well before my time, as well as before over half of folks on our tour. But, as technology has changed, so has APS. More than 130 years old, the utility has had to change and evolve with the times. It embraced centralized generation when it was the best way to satisfy consumer demand for safe, reliable and cheap power. But now, Arizona is ramping up distributed renewable generation throughout the state. The Arizona Corporation Commission is now considering a 50-percent clean energy standard, with an 80-percent clean peak requirement. If passed, it could position Arizona as one of the nation’s leading states in renewable energy adoption. So how is APS — the largest and oldest investor-owned utility in the state — preparing for this transition? Earlier this year, I was one of several SEPA staffers who had the opportunity to spend a week at APS, exploring the behind-the-scenes operations at this vertically integrated utility. We saw first-hand how APS is laying the groundwork to prepare its system to effectively manage the intermittency associated with the deployment of more renewable energy resources across Arizona, more than 1.6 GW in APS’s service territory alone. Most importantly, we had the chance to speak to APS employees who are in the midst of this transition and learn how they see the challenges and possible opportunities that lie ahead for their utility. “These four days at APS crammed as much learning about how a utility works as I got from my four-month internship at an investor-owned utility back in college,” said Ryan Edge, a program manager at SEPA, who was part of the group that visited APS. “My time there stayed mostly within business models and customer programs, but with APS, we saw generators of all types, distribution operations, energy trading, balancing, and even the call center. APS gave us the whole picture.” While on the ground, we frequently heard concerns from APS employees about maintaining a high level of reliability of electricity service for their customers — something they’ve come to be known for — while also managing the incorporation of high levels of variable renewable generation on their system. The challenge here is twofold: (1) Phoenix is a fast-growing urban area, which leads to even more load growth, and (2) the grid peak in the desert southwest is especially steep and long — up to five hours — during the hot summer months. Thoughtful preparation is needed to maintain the system’s reliability during the summer for the utility’s 1.2 million customers across a 35,000-square-mile area in the state. A Vision for DERs: an Interconnection Application Platform Looking at this situation and the changing needs of its customers, APS has developed a broader vision to position itself as an “interconnection application platform.” Through this approach, the utility hopes to provide customers with a single hub to submit interconnection requests for solar installations, electric vehicles, air conditioning systems and home pumps, load controllers, or smart thermostats. Like many utilities that are seeing more customers connecting distributed resources to the distribution grid, APS is striving to get ahead of the curve by offering customers easy ways to connect such distributed technologies while still maintaining grid reliability. To make this platform a reality, the APS’s Renewable Energy program recognized that it needed to revise its interconnection application process. All too often APS staff were revisiting interconnection applications multiple times, and this back and forth with installers and customers led to frustration for all parties. The APS team, led by Renewable Program Development and Manager Supervisor Erika Larsen and Energy Innovation Program Consultant Gary Ellars, saw this as an opportunity to do a better job of engaging with local installers to ensure that the installers’ user experience would be as seamless as possible. The team conducted qualitative research on the most frequent types of errors on the applications and realized interconnection requirements needed to be more transparent. This research eventually led to series of meetings with installers to assess how to improve processes and reach the mutual goal of decreased interconnection times for end customers. Since then, Larsen and Ellars explained, the process has gone more smoothly for everyone involved. In 2017, APS received over 25,000 residential and commercial applications — a record number — and connected more than 18,000 rooftop solar systems totaling 151.3 megawatts (MW) of capacity to their system. Since 2016, APS has also interconnected more than 100 battery systems through this process. Pilot Projects: Research Opportunities and Valuable Experience APS is also conducting research via several pilot projects, to inform the utility’s future decisions as it transitions to a new utility model. These projects allow APS to understand the capabilities of new technologies –such as solar and battery storage — to provide short- and long-term value for the grid, and insights on how to plan for the future. One example of APS’s pilot projects is its Solar Partner program, which began in 2014 as an effort to test and evaluate the grid-supporting capabilities of residential solar installations with advanced inverters. Interconnection standards (specifically IEEE 1547) forbid inverters installed behind the meter from actively manipulating local power quality and, in the event of a frequency or voltage disturbance, requires them to trip off. These requirements work well for utilities with low penetrations of solar power, but as solar proliferates, many jurisdictions are experimenting with grid services from inverters. As the grid moves from reliance on centralized, dispatchable, fossil fuel-burning plants toward distributed, variable solar, grid services from inverters will be required. For the Solar Partner program, APS installed utility-owned, west-facing solar panels with fully enabled smart inverters on residential customers’ homes. The utility maintained these systems at no cost to the homeowner, providing a guaranteed savings of $30 per month on the customer’s energy bill in return. The 10-MW, 1,600-home program targeted select feeders in the utility’s distribution system to determine how they would function with during times of peak solar generation. Several use cases for solar power with smart inverters were identified, including voltage regulation, expanded ride-through, interoperability with other utility systems, and integration with energy storage. APS has since built upon the Solar Partner program to add battery storage installations in the greater Phoenix area. The utility installed two identical 2 MW/2 megawatt-hour (MWh) lithium ion batteries specifically sited in different locations along a feeder, one near a substation and another in the middle of the feeder. Having two identical batteries allows APS to evaluate the locational value of storage as it related to its position, voltage control, and power quality along feeders that have a significantly higher deployment of residential solar generation. John Pinho, the project manager for the installation and one of APS’s storage experts, walked us through one of the sites. After explaining some of the enhancements that were made to the system to ensure its longevity and integrity, Pinho said that redundancy and low risk are two critical considerations for utilities, particularly when researching a new technology. Battery storage is still a relatively new product, so it’s imperative that utility investments in this technology are delivering the most value for customers. Through this pilot project, APS has gained valuable insights, such as how advanced inverters coupled with battery storage systems can be leveraged as an operational tool. APS’s recent announcement of a power purchase agreement with First Solar for a 65-MW solar farm, coupled with a 50-MW, 135-MWh battery storage project, reflects the utility’s continued commitment to utility-scale investments in renewable energy. This project will be the largest battery storage project in Arizona and is designed specifically to serve as peaking capacity to fit APS’s long summer peak. Managing the Distribution Grid Behind the scenes, APS’s investments in information technology systems, GIS mapping, and technology on the ground, such as advanced switches, make the utility’s Distribution Operations Center (DOC) a state-of-the-art facility. The DOC is responsible for monitoring APS’s distribution grid down to the feeder level in real time, collecting valuable data on how this system operates. The greater visibility the DOC provides allows APS to track and respond to outages more efficiently and ultimately improves quality of service, as well as positioning the company to move to the interconnected application platform approach. Inside of APS’s Distribution Operations Center, the SEPA team examines its state-of-the-art monitoring systems. As seen at the DOC, the technical evolution utilities are facing will also radically influence the type of work their employees do on a daily basis, particularly those involved in the physical operation and maintenance of the grid. Advances in the safety mechanisms on live wires, as well as the technology that detects and relays this information, means that fewer line workers have to be put in harm’s way. However, fewer technicians are needed in the field now that the grid can seemingly repair itself instantaneously. Certainly, customers will experience fewer outages and therefore greater reliability. But as the operations for the DOC become more digitized, requiring employees with data-monitoring skills, what will happen to the line staff trained in the physical, on-the-ground labor? After viewing the DOC, we also visited the Energy Control Center (ECC), APS’s transmission side of the house, where we saw television monitors showing the veins and blinking flashes of the transmission grid stretching across Arizona. We asked the head of the ECC if he thought that these roles would change with the influx of new technology. Based on his response, although technology can provide greater visibility into the systems that manage the grid, an essential human-to-human element will still be needed to maintain the grid. Investing in technology that supports the DOC and ECC seems easier to justify, given the focus on reliability and need to have real-time insight to maintain the grid. On the other hand, weighing the retirement of nonrenewable generation in coordination with the addition of more solar, storage, or wind generation onto the system is arguably more complex. What is APS doing to prepare for the transition away from non-renewable assets The reality is that utilities are having to weigh the transition to renewables in the context of their existing investments, as well as their current and future investments that support the greater deployment of renewable energy. The view from the Ocotillo Power plant in Tempe, AZ. The construction in the foreground is of the natural gas combustion turbines that are set to replace the retiring power plant as part of the Ocotillo Modernization Project. APS’s Ocotillo Power Plant was originally built on farmland in Tempe, but standing on the scaffolding surrounding one of its turbines, I could see how Phoenix’s urban sprawl has now completely surrounded it. Built in the 1960s, the plant’s two natural-gas turbines are set to be replaced by five combustion turbines, also running on natural gas, beginning in the summer of 2019. Natural gas’s drop in price, as well as the ability for such plants to ramp up quickly in response to the rapid decline in solar generation at dusk, have contributed to the business case for these plants. However, the recent moratorium from Arizona regulators on natural gas plant construction means that the Ocotillo plant upgrade could be the last. The future of the Palo Verde nuclear plant poses similar questions regarding its sustained value to the grid. As the largest carbon-free generating asset in APS’s portfolio and as a major stabilizer to the grid’s frequency fluctuations, a strong case can be made for extending its life. However, this plant’s generation is primarily baseload, which is no longer price-competitive in a market that favors the deployment of flexible, low-cost resources. In addition, the decline of nuclear construction across the country and the bankruptcy of some of the industry’s largest developers, such as Westinghouse Electric Corp, have contributed to the concerns we heard onsite regarding the future of the plant. Some machine parts are no longer readily available or manufactured to the same quality standards, and in an effort to keep operations running seamlessly, the facility has turned to in-house skilled labor for necessary onsite maintenance and repairs. Contrasting with those legacy assets, APS’s Punkin Center battery storage project — located 90 miles northeast of Phoenix — illustrates how APS has turned to battery storage in lieu of a transmission and distribution (T&D) upgrade. APS had considered a traditional 20-mile T&D upgrade to address strains on its wires. After evaluating several options, the utility elected the battery storage approach, which penciled out at half of the cost of the T&D upgrade and can be deployed elsewhere for future grid needs. Additionally, APS is striving to adopt innovative technological approaches and lay the foundation for developing advanced energy management techniques — including possible virtual power plants. For example, APS’s Solar Innovation Study is pairing energy storage units with home energy management systems to create an optimized system of distributed energy resources that work in concert with the grid and maintain the comfort of participating customers. Making the most of the market and encouraging customers to do the same For now, a platform approach appears to be one solution to managing the grid’s maintenance. However, a key element to making this platform approach a success is for APS to create incentives and price signals to promote customers’ adoption of smart technologies, and to align their consumption behavior with the system outputs. For example, APS is in a lucrative position with its proximity to California’s wholesale electricity market. California is still learning how to best manage the excess solar energy generated on the grid, and at certain times of the year, APS is paid to use this excess energy from the Energy Imbalance Market (EIM). While this unique business opportunity may not last forever, APS sees it as a chance to incentivize customers through concepts like “reverse demand response,” that is, incentivizing customers to shift their energy usage to align with the influx of cheap power from the EIM. Because APS is a vertically integrated utility, it passes along 100 percent of the cost savings from these purchases directly to APS customers –something that not all investor-owned utilities can offer. APS had just rolled out a new rate increase to customers before our arrival, and we had a chance to visit the Customer Care Center and speak to the staff who interact with APS customers on a daily basis. APS is trying to offer more advanced options for its customers – like a pilot residential technology rate – but it’s not clear whether all customers have the same level of engagement or education about how these rates function. Several of the staff at the Call Center explained that APS has rolled out new features, including a mobile app, but some customers are still not as engaged as they could be. For utilities like APS, which are trying to get savvier about customer choices, are they also responsible for educating customers? Customers may not need to know exactly how their electricity is generated, but with the proliferation of technology and emphasis on user-centered designs, how can utilities continue to convey to their customers the value that they offer? What is on the horizon? APS is one example of how a vertically integrated utility is transitioning to a clean energy future. The utility’s focus has been on continuing to keep energy costs low for consumers, while still delivering reliable service. When pushed to operate a grid with an increasing penetration of renewable generation, both behind and in front of the meter, the transition can be challenging, particularly when balancing the move away from historically less-flexible generation. A key focus should be ensuring that what utilities invest in today will continue to provide value for the long term, but also that these assets are what utilities will need to effectively operate a rapidly transforming grid. APS’s Paloma Solar Plant in Gila Bend. This 17 MW farm consists of 275,000 of First Solar’s thin film photovoltaic panels. In addition, as utilities such as APS continue to evolve, they will have new opportunities to engage with consumers and deliver new grid value. In order to realize these opportunities and address new demand, the workforce behind utilities’ success will continue to evolve as well. Ongoing research is essential to understanding how utilities can incorporate new technologies to ensure value to customers and the grid, and sharing insights and best practices from this work will be critical to the ongoing success of these transitions. These were some of the thoughts that I pondered while standing in the middle of APS’s Paloma Solar plant, which compared to Palos Verde was very quiet, with only the humming of inverters reaching my ears when a breeze blew through. Like other utilities across the country, APS is actively engaged in an industry transition that provides significant challenges and no easy answers. What was exciting for me and the SEPA team was seeing this process up close, in all its technical innovation and human complexity. We at SEPA are grateful to APS for allowing us the opportunity to explore the inner workings of their utility and engage with them in a dialogue about what the transition to a renewable future looks like from their perspective. The SEPA team posing with APS Manager of Renewable Energy, Ray Brooks, dressed in APS attire. From left to right: Ryan Edge, Rachel Henderson, Jared Leader, Spencer Schecht, Ray Brooks (APS), Erika Myers, John van Zalk, Nick Esch, and Janine Fiasconaro. Share Share on TwitterShare on FacebookShare on LinkedIn About the Author Rachel Henderson Manager, Executive Affairs Rachel Henderson joined SEPA in 2016 as Manager of Executive Affairs. In this role, she supports the SEPA Board of Directors and Utility Executive Exchange Forum, an executive-level group that provides opportunities for utilities to engage with their peers on the topics of distributed energy resources and the evolving utility business model. Prior to joining SEPA, she worked for CSRA supporting the Federal Energy Regulatory Commission as Lead of the Program Management Office for a large IT contract. She has experience conducting public health research and implementing community-based projects in Appalachia and Cape Town, South Africa. Rachel served as a Spring 2017 Fellow in the Clean Energy Leadership Institute (CELI) in Washington D.C., a leadership development organization dedicated to building a diverse community of professionals to advance innovative clean energy solutions. Rachel has a Bachelor of Arts in Anthropology and Global Development with a concentration in Public Health from the University of Virginia.