Anza Valley was in the dark.
The 2018 Cranston wildfire, which had torched homes, forced evacuations, and destroyed 13,000 acres in the region, had also incinerated the sole transmission line to
Anza Electric Cooperative, the main power provider for this high-desert community about 120 miles southeast of Los Angeles.
"That one line is our sole connection to the outside world," says Kevin Short, the co-op's general manager. "Our entire service area was out."
The outage lasted 10 scorching days from July into August—the longest and costliest in Anza's 67-year history. The co-op had to shell out about $1 million for generators to keep power flowing during transmission repairs.
The event marked a turning point for Anza. If they were going to deliver on their promise to provide reliable power, they would have to have more control over their generation.
With a grant from the U.S. Department of Energy, Anza began working with NRECA and Sandia National Laboratories on an energy storage strategy that will not only help the co-op meet a portion of its demand during such transmission failures but also let its nearly 5,000 members avoid some expensive summer peak charges.
"What we're trying to get out of this project is an island microgrid setup," Short says.
It's a strategy that's becoming increasingly common for co-ops.
"Battery storage is moving from a technology to a business model," says Venkat Banunarayanan, NRECA's senior director for distributed energy. "Electric cooperatives are using storage technology to fulfill different needs."
Business & Technology Strategies (BTS) group is developing energy storage guidelines, case studies, and reference materials and has worked with NRTC to help co-ops plan and build out battery projects.
Brad Seibert, vice president for next-generation energy at NRTC, says growing interest in energy storage reminds him of the time just before adoption of solar generation took off.
"Co-ops are saying, 'We better be out in front of this technology wave.'"
Shaving peaks in Colorado
United Power in Brighton, Colorado, says its new battery storage system—the largest in the state and one of the biggest owned and operated by an electric co-op—will save members up to $1 million a year.
"This is the beginning of a dramatic change, and that's good for consumer members," says Troy Whitmore, public affairs officer at the 87,000-meter co-op that serves Colorado's northern Front Range.
The co-op says the system, a sleek 4-MW/16-MWh Tesla lithium-ion powerpack array developed with NRTC storage partner ENGIE North America, will help dramatically cut peak demand and reduce capacity charges from its G&T.
"This will be a demand-reducing tool," Whitmore says. "Through battery storage, we will be bringing down our wholesale power costs."
A second key benefit will be better economics for intermittent renewable generation. The battery system will allow the co-op to fill in the "valleys" from an abrupt loss of these resources, like when weather causes a drop-off in wind or solar production.
"When wind blows at 3 a.m. or the sun shines early in the day, we can capture energy and not utilize it until 4 p.m. to 6 p.m., when we usually peak," Whitmore says. "Since the battery is charged during off-peak time periods, the power you're filling the battery with is less expensive than the power you're extracting from the battery. So when you release power from the battery, it's at a big savings."
Another driver toward energy storage? Competition.
Situated in Denver's northeast suburbs near an international airport, United Power foresees significant growth in its service territory where there are neighboring utilities.
"When new industry or a subdivision or call center is proposed, we need to be competitive," Whitmore says.
The ability to dispatch off-peak power during peak hours can keep rates economical, he says.
"Eighty percent of the cost of doing business is the wholesale power bill," Whitmore says. "Anything we can do to make that a little more reasonable will help the condition of co-ops and, ultimately, the end-use member."
Connexus Energy was facing a conundrum. Its members were asking for more renewable energy, but not if it meant increases in their monthly power bill.
Plummeting wind and solar energy prices brought the technology well within reach, but inherent intermittency meant the co-op couldn't guarantee any renewable generation capacity would actually help keep costs down.
As the 135,000-member co-op based in Ramsey, Minnesota, looked for solutions, it got some help from Washington, D.C. In 2015, the federal government decided to not only extend tax incentives for wind and solar but also apply an investment tax credit to battery storage systems that are charged using renewable energy.
Connexus started working on a plan for a solar/storage solution, and by the end of 2018 had launched a 10-MW PV system that can charge 15 MW of lithium-ion batteries. The co-op partnered with ENGIE North America to deliver the solar energy and signed a 25-year, fixed-fee contract for energy storage with NextEra Energy Resources, which owns the batteries.
"We listened to our members," says Greg Ridderbusch, the co-op's CEO. "We will discharge stored solar energy during peak hours when energy costs are the highest. This will help us save in power supply costs."
Ridderbusch says the energy management model they're using could be a template for co-ops nationwide. It offsets the risks of battery ownership and requires no up-front capital.
The co-op plans to discharge the batteries four to six times a month, says Brian Burandt, Connexus vice president for power supply and business development.
Burandt says the system will reduce the need to add new generation, substations, and transmission.
"Several co-ops are watching our project," Burandt says. "Some are dipping a toe in water. The battery adds a whole new dimension of savings."
Can small batteries in the homes of co-op members in different states be aggregated to create a utility-scale energy storage solution?
Four Midwest co-ops served by
Dairyland Power Cooperative have launched a pilot program to find out.
The co-ops will control 16-kWh energy-storage systems at 10 member-consumer sites to test their effectiveness in shedding load and their impact on time-of-use rates. The co-ops also will examine any difference between substation-based storage and residential storage.
Jo-Carroll Energy in Elizabeth, Illinois, and Wisconsin cooperatives
Richland Electric in Richland Center and
Oakdale Electric in Oakdale are installing two battery systems each in their service territories.
MiEnergy Cooperative in Rushford, Minnesota, has installed four battery systems at members' homes in Minnesota City and Winona, Minnesota, and in Decorah and Ridgeway, Iowa.
While the co-ops will get experience with storage and help with peak demand, participating members will have use of the backup power systems in their homes.
"This is an opportunity to learn more about the future of battery technology and how to use it in our distribution system and how to benefit our members," says MiEnergy CEO Brian Krambeer.
Dairyland Power in La Crosse, Wisconsin, will do an internal analysis of the battery storage aggregation test later this year.
"Dairyland is supportive of our cooperatives' efforts to investigate behind-the-meter energy storage," says Jeff Springer, manager of energy efficiency and technology at the G&T. "We hope to learn more by working on this pilot."
Atlanta-based Sonnen built the batteries and is providing training and technical support.
Trusted energy storage advisor
As interest in home battery systems increases and costs decrease,
Central Electric Power Cooperative (G&T), which serves South Carolina's 20 electric distribution co-ops, is studying up for its role as trusted energy storage advisor.
Central Electric wants to understand the value of residential battery systems for members and how storage impacts the co-op business model, says Scott Hammond, the Columbia-based G&T's member programs manager.
They're currently evaluating two battery systems connected to rooftop solar arrays at homes served by
Coastal Electric in Walterboro and
Berkeley Electric in Moncks Corner. The batteries are charged by the panels and then discharged by the G&T to meet household demand.
The Coastal system, which Central Electric purchased, comprises 6 kW of solar energy with 24 kWh of storage. The Berkeley project involves 6 kW of solar with 18 kWh of storage.
This winter, Central Electric will control the batteries from 6 a.m. to 9 a.m. with the goal to displace as much peak energy as it can within the three-hour window, Hammond says. The batteries can discharge between 6 and 8 kWh during monthly control periods.
"We will see how the battery systems work with winter peaks. We are trying to optimize how it runs when it runs," says Hammond, calling it a bit of a "cat and mouse game" with renewable resources. "When solar is producing, we try to maximize that value."
The co-op is also studying the effects of battery capacity decline over time.
"With a battery, you've got an expensive capital investment," Hammond says. "You want to know what it looks like over the course of a few years."
Installed battery systems offer clear flexibility and demand savings. But what about the upfront investment and ownership costs?
Vermont Electric Cooperative (VEC) is trying out an innovative solution it hopes will deliver maximum benefits with minimal risk.
The co-op has signed a 10-year agreement beginning June 30, 2019, to lease up to 400 MWh of storage per year from a utility-scale lithium-ion battery system owned by Viridity Energy Solutions.
About the size of two tractor-trailers, the 1-MW/4-MWh battery system will be installed beside VEC's substation in Hinesburg, Vermont.
Craig Kieny, manager of power planning at the Johnson-based co-op, says his team has studied state and regional power markets for nearly two years and is confident in forecasting periods of peak demand to call on its leased storage.
The 400-hour window under the agreement will allow the co-op to achieve a pretty high success rate of picking the correct day and hour of the peak, he says.
"If we operate the leased energy perfectly, we could experience annual savings of nearly $100,000," Kieny says.
VEC CEO Rebecca Towne says she expects battery prices will fall over the next decade as manufacturers gain more expertise and battery capacity grows. She says the lease arrangement will allow the co-op to gain experience with energy storage without being distracted by installation and maintenance concerns.
"Being able to store energy … allows us to be flexible and nimble as our industry moves to more intense management of both supply and demand. With this battery system, VEC will be able to seize new value—in real dollars and cents—for our members."
Called to serve
When the nation's largest ammunition terminal needed resilient electricity and a renewable energy source, the U.S. Army called the local electric cooperative.
Brunswick Electric Membership Corporation serves more than 93,000 meters in its southeast corner of North Carolina, but not the Military Ocean Terminal Sunny Point, which is tucked just inside the mouth of the Cape Fear River.
The installation does rely on a feed from Brunswick EMC whenever there's an interruption from its primary source of power, Duke Energy, the investor-owned utility headquartered in Charlotte.
The co-op, based in Shallotte, owns and operates 1.2 MW of solar energy plus a substation on the north end of the base. And in 2017, the co-op installed 840 kWh of battery storage. The lithium-ion system can provide the base up to 210 kilowatts per hour for four hours.
Now the co-op is preparing to build a 1-MW microgrid for the base that will include 1,000 kW of diesel generation and additional battery capacity of 950 kWh.
"When we complete the microgrid, Sunny Point will have that for a third option," says Lewis Shaw, Brunswick EMC's vice president of engineering & operations. "In case of emergency conditions, in the event Duke is not available to supply Sunny Point power and Brunswick is not available, the microgrid would island itself for terminal consumption."
The co-op is also working on a residential energy storage project that will involve a self-contained microgrid to power a new subdivision of 33 homes in Shallotte. There will be a centrally located community solar field and a lithium-ion battery station in the neighborhood where each house will also have rooftop PV panels.
The first house is expected to be occupied in first quarter of 2019.
'INVESTING IN THE FUTURE'
Back in the southeastern California desert, Anza Electric is racing the clock to shore up the vulnerabilities the Cranston fire exposed.
A 3-MW lithium-ion battery is in the works, as is a 1.5-MW solar plant that can operate in parallel with the electricity coming over its lone transmission line.
Such an energy storage system "could get us through the majority of outages we experience," says CEO Short.
Anza buys its power from
Arizona Electric Power Cooperative, but it's delivered via a single radial transmission line owned by Southern California Edison. The investor-owned utility lost about 100 poles to the Cranston blaze.
Anza plans to use its new battery system, which will sit next to its solar farm, for more than just outage management.
"We'll be able turn it on and use it when we are looking for lower-cost options than we can get in the market at the time," Short says.
But job number one will be providing reliable electricity, even as the threat of wildfires in the region appears to be on the rise.
"We will have outages in the future," he wrote in an open letter to co-op members this fall. "You can absolutely depend on that. You can also depend on us doing our best to make sure that these events are as limited in scope and duration as is humanly possible."
Short notes that building new baseload generation, like a combined-cycle turbine, is not an option for the co-op since the state passed a mandate for zero-carbon generation by 2045.
"We need stored solar power available when it's needed," Short says. "We see the battery as investing in the future."