Fortnightly - Winter 2016

Utility-Scale Storage: Four Utilities, Four Strategies

William Atkinson 2016-01-25 05:20:34

In a report published in July of last year, Frost & Sullivan predicts great things for utility-scale energy storage. “This market is expanding rapidly,” the report states, “driven by impressive technological breakthroughs and growth in manufacturing capabilities.” Th e report cites a “rising profile” that has “caught the attention of governments, which are now rolling out favorable policy initiatives, such as subsidies, [and] preferential tariffs.” (See, Global Utility-scale, Grid-connected Battery Energy Storage Systems Market, July 21, 2015.) The market saw worldwide revenues of almost half a billion dollars in 2014 and is expected to earn almost eight-and-a-half billion by 2024. Approximately 430 megawatts of battery energy storage systems are currently in operation, while estimates suggest 10 to 12 gigawatts by 2024. The U.S. is expected to lead the way, followed by China, Japan, and Germany. “Battery storage has the ability to impart flexibility to the grid across a variety of end-use applications,” said Ross Bruton, energy and power research analyst for Frost & Sullivan, in a press release. As Burton explained further, the market’s greatest advantages come from several different applications: 1) time shifting of energy usage, 2) the firming up of energy from distributed and variable renewable resources, and 3) ancillary services, such as the rapid and shortterm balancing of electricity supply. Meanwhile, electric utilities are taking notice. These days, it’s rare for a U.S. utility not to be at least looking at energy storage, while many are actually involved in projects. Here, we look at four such utilities, each of which has become involved in energy storage for different reasons: • American Electric Power (a large investor-owned utility), • Green Mountain Power (a small IOU operating in Vermont), • Imperial Irrigation District (a publicly owned municipal entity in California), and • Kauai Island Utility Cooperative (Hawaii). American Electric Power Lisa M. Barton, executive vice president, transmission, for American Electric Power (AEP), testified on March 17, 2015, at a hearing held by the U.S. Senate Committee on Energy and Natural Resources that energy storage via battery technology could well prove a “game changer” for the electricity industry – “if implemented cost-effectively.” And AEP in fact has had a long and active involvement in energy storage. Ram Sastry, vice president, infrastructure and business continuity for AEP, notes that AEP first began looking at storage systems in the late 1990s: “First, we wanted to see if they would be reliable, and then second, to see if they would be affordable.” AEP’s first actual foray into large-scale energy storage came in 2002, according to Sastry, when it installed and began operating a large sodium-sulfur (NaS) battery unit from the Japanese company NGK as part of a demonstration project at an AEP office park in Gahanna, Ohio, near Columbus. Four years later, Appalachian Power, an operating unit of AEP, deployed a 1.2 megawatt NaS battery at its Chemical Station in Charleston, West Virginia, making it the first megawatt-class advanced energy storage technology to be used on a U.S. electric distribution system. The NAS Battery Division of NGK Insulators Ltd. provided the battery, and the Power Quality Products Division of S&C Electric Company provided the power electronics and served as system integrator. The peak-shaving unit is capable of supplying 7.2 megawatt-hours of energy, and the battery is expected to last 15 years, or 4,000 to 5,000 charge-discharge cycles at 90 percent of full energy capacity. The purpose of the project was to delay the need for equipment upgrades to the facility by six or seven years, allowing that capital expenditure to be deferred. In 2008, AEP rolled out three new battery storage projects, three months in a row. All of these were 2-megawatt, 12 megawatt-hour NaS storage systems, and all of them were designed for peak shaving and islanding. The first, which went in-service in October 2008, was at an AEP substation in Bluffton, Ohio. The second, a month later, was installed at an AEP substation in Milton, West Virginia. The third went on-line in December at an AEP substation in Churubusco, Indiana. Two years later, AEP’s Electric Transmission Texas installed a 4-megawatt NaS battery in Presidio, Texas, as a way to provide power backup in the event of an outage to AEP’s radial transmission line that served the community. The battery was assembled from 80 sodium-sulfur modules, 8,000 pounds each, and transported to the site by 24 trucks. Previously, when the transmission line had encountered an outage, the town had an immediate blackout, and its only alternative was to procure electricity from Mexico. Now, with the installation of the battery unit, in the event of an outage on the transmission line, the battery can supply four megawatts of uninterrupted power for up to eight hours. “The business case that we built for these five NaS systems was that we would be able to defer capital expenditure on building up the T&D infrastructure,” said Sastry. “They have been working very well for us.” AEP began to reconsider in 2010, however, as the cost of sodium-sulfur batteries began climbing, while lithium-ion batteries began to show potential. “Lithium-ion batteries are now a mature technology, and we have done some demonstration projects with lithium-ion batteries in community energy storage situations,” Sastry explains. In late 2015, seeking a more agnostic technology – one that could work well with any vendor – AEP invested $5 million as part of a $12.3 million round of funding by Greensmith Energy Management, a provider of grid-scale energy storage software. Sastry describes Greensmith as “a leading integrator of storage systems,” providing a technology platform to control and optimize batteries as a fleet on the distribution network. As of 2014, Greensmith was managing over one-third of the 62 megawatts of energy storage projects in the U.S. AEP in particular will gain access to Greensmith’s storage software platform, called GEMS, providing AEP with multiple options for energy storage deployment. AEP’s future plans, Sastry explains, will focus on costs and on identifying locations on its system where a prudent business case can be made to deploy batteries. “We believe that batteries currently make sense in three to five percent of scenarios,” he notes, where they can help to supply capacity, allow for shifting of peak loads, or help defer capital expenses for transmission or distribution (T&D). And Sastry points also benefits from “firming up” renewables. “Some ratio of pairing battery systems to renewables allows much more dispatchability of a renewables portfolio,” he adds. “The more tools we have, the better we are able to meet our needs and the needs of our customers. Ultimately, we see batteries acting as generation assets, as transmission assets, and as distribution.” Green Mountain Power Since becoming President and CEO of Green Mountain Power in 20008, Mary Powell has worked to reshape the utility from a traditional one to an energy services company – one that not only supplies power, but also sells heat pumps and insulation for homes, promotes the installation of residential solar, and will soon be offering the wildly-popular Tesla Powerwall batteries to homeowners to store excess power at home. And those aims are echoed by Josh Castonguay, GMP’s director of generation and renewable innovation. “Our broader goal for the grid, as he notes, “is to move toward a much more distributed energy model, That is, instead of focusing on a large power plant and long-distance transmission, we are continuing to move closer to load, doing so with solar, methane digesters, and other resources. Battery storage is a piece of our overall strategy going forward, as a way to help gain and maintain control and balance our loads.” The Stafford Hill Solar Farm, located in Rutland, Vermont, marks one of GMP’s most recent and representative projects. The town of Rutland in fact is seeking to become the “Solar Capital of New England.” The town already has an installed capacity of almost 8 megawatts of solar, the most per capita of any city in the six-state New England region. It is also attracting solar businesses to locate in the city. With the increasing frequency of major storms in the region, such as Tropical Storm Irene in 2011, which wreaked havoc on Vermont, including widespread power outages, GMP felt it was important to provide backup power after such storms. Stafford Hill Solar Farm combines solar, storage, and microgrid technologies. According to the U.S. Department of Energy, the project marks the first of its kind in the U.S. to establish a microgrid powered solely by solar and battery back-up. The project features 7,700 solar panels situated on 15 acres of land that were once home to a landfill, making it also the first known solar storage project in the country to repurpose brownfield land. “We partnered with Dynapower, a local company that specializes in designing and building special power electronics equipment for large scale solar and storage systems,” said Castonguay. The funding and the building of the project were coordinated by GMP, the Clean Energy States Alliance, the Stafford Technical Institute, groSolar, the Vermont Clean Energy Development Fund, the Vermont Energy Investment Corporation, and the Vermont Department of Public Service. The Rutland solar farm can generate 2.5 megawatts of electricity, enough to power 2,000 homes during full sun, or 365 homes year-round. It also includes 4 megawatts of battery storage. With the combination of solar and storage, the system allows the disconnection of an entire circuit from the grid during an emergency, such as a large storm, in order to provide power to an emergency community shelter situated at the Rutland High School. The project was completed in July 2015 and has been running successfully ever since, according to Castonguay. The future? “Looking forward several years, we are asking ourselves what things might look like if half of our customers are on solar, including some who have actually disconnected from the grid,” he said. “How do we want to be involved in this evolution? We absolutely see storage as being a key piece of it.” In addition, he added, the technology is improving, in that density is increasing, footprints are becoming smaller, and costs are coming down. “I think the growth of storage technology and its popularity will be similar to what has happened to solar PV over the last decade,” he said. Imperial Irrigation District The growth of utility-scale energy storage gained momentum in California following the state’s 2015 mandate (Assembly Bill 2514) requiring the state’s three IOUs – San Diego Gas & Electric, Pacific Gas & Electric, and Southern California Edison – to bring 1.325 gigawatts of energy storage on-line by 2020. Nevertheless, one of the first utilities in the state to take steps toward large-scale energy storage was not one of the three giant IOUs, but the smaller-sized Imperial Irrigation District (IID), which operates as California’s the third largest public power utility, and the nation’s largest irrigation district. Since IID is not an IOU and is thus not subject to AB-2514, why did it get involved in storage? The impetus for the utility’s interest in energy storage was the result of a September 2011 blackout that started in Arizona, when an Arizona utility accidentally shut down a transmission line, sending more power than expected into an IID transmission line, and shutting it down. The outage cut a wide swath through southern California and left 2.7 million customers without power, at a time when temperatures swelled into the triple digits (a high of 114 degrees) and customers were left without air conditioning. As part of its settlement with the U.S. Federal Energy Regulatory Commission over any possible role it might have had in causing the blackout, IID agreed to invest in battery technology to help prevent future outages. “We actually began exploring battery storage options in 2013,” said Carl Stills, IID’s energy manager. The result is the $38 million Battery Energy Storage System (BESS) Project, able eventually to store 30 megawatts of power and deliver approximately 20 megawatts to the grid, making it one of the largest battery storage systems in the western United States. BESS will be built by Coachella Energy Storage Partners (CESP), the general contractor, based in Imperial, California. General Electric will provide the equipment, including lithiumion batteries with inverters, plant controls, transformers, and medium-voltage switchgear. ZGlobal has been selected as the engineer for the project. The project will be located about 100 miles east of San Diego, in a metal frame building that will be insulated and air conditioned to ensure optimal battery performance, and will house the batteries, mounting racks, and electronic equipment. A separate room will house the electronic controls, inverters and rectifiers. The electrical interconnect will include a substation to connect the BESS step-up transformer and high-side 92-kV breaker to the generator tie line for IID’s El Centro Generating Station Unit 32. The connections also will provide isolation and relay protection. IID sees BESS as providing four benefits. The first is power balancing. And as IID serves as its own balancing authority, power balancing is the priority of the project. “As a balancing authority, we have operational requirements, which include ACE [Area Control Error] and integration of renewables and spinning reserves,” said Stills. Second is solar integration. For example, the battery will help bring at least 50 megawatts of new solar power onto the grid (the 30-megawatt Midway II project in Calipatria, and the 20-megawatt SunPeak 2 project near Niland), with the battery storage providing the generated solar at night or on cloudy days. “The IID service territory is home to some of the more robust renewable energy resources in the country,” said Stills. “Located within the state of California, with its aggressive renewable portfolio requirements, we recognized that batteries would complement our solar and intermittent resource integration.” Third is spinning reserve. “We saw batteries as a means to further reduce fossil fuel needs by replacing some of the spinning reserves that would normally require natural gas,” said Stills. Fourth is power restoration. “The batteries add another level of reliability to our system,” said Stills. “Should an outage or issue occur, we could use the batteries to black-start our El Centro Generating Station, one of our main internal sources of generation.” These four services – balancing, solar integration, spinning reserve, and power restoration – could of course be provided by a traditional generating unit. But the battery system will be able to provide these services with a much shorter ramp time. Without the battery, IID would need to procure another gas unit, get it permitted, and then burn fossil fuels. Construction of BESS began in 2015 and is scheduled to begin commercial operation in the third quarter of 2016. But IID sees a future for battery storage beyond the BESS project, according to Stills. “Depending on what happens with California’s renewable energy portfolio standard, we may be interested in adding additional storage options to our system,” he said. Overall, Stills sees a promising future for energy storage: “I believe that batteries and other forms of energy storage will be very important to the grid as a whole, especially as utilities continue to integrate additional intermittent resources, especially solar and wind, into their portfolios, and as storage options become more economical and more commercially viable.” Kauai Island Utility Cooperative Kauai Island Utility Cooperative (Lihu’e, Hawaii), a member-owned cooperative serving 33,000 customers, represents still another utility studying energy storage: in this case, whether pumped storage might serve as economically as a “battery” to store the energy generated by the cooperative’s solar arrays, as well as the thousands of rooftop solar photovoltaic systems now in place. KIUC’s President and CEO, David Bissel explains why: “We began looking very seriously at energy storage more than two years ago, when it became clear that we were going to have an abundance of relatively inexpensive solar available during the day. We wanted to figure out how we could move some of that to our peak demand period from 5 p.m. to 10 p.m., which is our most expensive period for generating power, since we are burning oil.” As recently as 2009, KIUC’s generation mix was 91 percent oil and nine percent hydro. But by 2015 the mix was 62 percent oil, 17 percent solar, 12 percent biomass, and nine percent hydro. By 2023, the utility would like to see 36 percent of capacity coming from solar+storage, with 34 percent oil/gas, 18 percent hydro, and 12 percent biomass. The company predicts that solar generation will soon supply 50 percent of its daytime energy demand. However, as KIUC sees it, if the solar energy generated a mid-day can be stored to be used at night, then even larger solar arrays can be built economically, providing the utility and its customers with inexpensive energy around the clock. After conducting research on storage options, KIUC settled on pumped hydro storage. The system will pump water uphill to a storage pond, and then allow it to run back downhill at night through a turbine to generate energy, when demand can’t be met by solar. The hydro turbine would replace the utility’s expensive and environmentally unfriendly oil-fired power generation. It could generate about 25 megawatts of energy at night and provide 250,000 kWh of daily storage, making it possible to power down the utility’s older and less efficient oil-fired generators. Preliminary estimates put the cost of the project at between $55 million and $65 million. “This technology is available today, and it is in use around the world,” said Bissell. “We don’t have to wait for some technological breakthrough to efficiently move and store solar power. “We will make a site selection sometime in 2016 and then decide if we will move ahead. This would be a 100-year project, something that would provide power for pennies per kWh once it’s paid for.” In the meantime, KIUC isn’t shy about moving ahead with storage projects in other ways. In September 2015, it signed a power purchase agreement with SolarCity for electricity from the first utility-scale solar array and battery storage system designed to supply power to the grid in the evening, when demand is highest. (SolarCity designs, manufactures, installs, maintains, monitors, leases, and sells solar energy systems to residential, commercial, government, utility, and industrial customers in the U.S.) “We’ve been investigating energy storage options for more than two years, and price has always been the biggest challenge,” said Bissell. “This is a breakthrough project on technology and on price that enables us to move solar energy to the peak demand hours in the evening and reduce the amount of fossil fuel we’re using. Pending state and county approvals, the SolarCity project will be situated on 50 acres next to KIUC’s Kapaia power plant. The 52 megawatt-hour battery system will feed up to 13 megawatts of electricity onto the grid to “shave” the amount of conventional power generation that is needed to meet the evening peak. And under the terms of the 20-year contract, KIUC will pay SolarCity a lower rate than the current cost of conventional generation, and only slightly more than the cost of energy from KIUC’s two existing 12-megawatt solar arrays, the output of which is currently available only during the day. CEO Bissel touts both projects: “We believe that both pumped storage hydro and the SolarCity project could provide a strong foundation for our efforts to move closer to energy independence and lower our customers’ bills.” William Atkinson is a freelance writer whose work has appeared frequently in Public Utilities Fortnightly.

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