The solar and battery storage system will help match the electricity consumed by Google’s forthcoming data center campus in Mesa, Arizona. Energy not needed by the data center will be used to meet other SRP customer needs.

Also supporting Google is the newly developed Storey Energy Center, an 88-MW solar and battery storage system, located in Coolidge, Arizona. Both facilities are operated by subsidiaries of NextEra Energy Resources. SRP and NextEra Energy Resources’ under-development wind facility, Babbitt Ranch Energy Center, will also support Google. This is a 161-MW wind project, on Babbitt Ranches property in Coconino County, north of Flagstaff.

Google is pursuing net-zero emissions across its operations and value chain by 2030, supported by a goal to run its data centers and office campuses on 24/7 carbon-free energy. The Sonoran, Storey, and Babbitt Ranch projects contribute to these commitments by supporting the energy needs of Google’s future data center in Mesa, which the company announced in 2023 with plans to use air-cooled technology.

“We’re aiming for every Google campus to operate on clean electricity every hour of every day by 2030, including in Arizona where we are excited to put down roots with our first data center in the state currently under construction,” said Amanda Peterson Corio, Global Head of Data Center Energy, Google. “The collaboration with Salt River Project and NextEra is accelerating decarbonization in Arizona and our own carbon-free journey in the region.”          

Through its Integrated System Plan, SRP found it will need to at least double the number of power resources on its power system in the next 10 years as it completes the planned retirement of 2,600 MW of coal resources, and amid growing energy demand.

“These renewable energy centers will generate low-cost, homegrown energy and provide millions of dollars in additional revenue to both Maricopa and Pinal counties over the life of the projects,” said Anthony Pedroni, Vice President of Renewables and Storage Development at NextEra Energy Resources. “We are pleased to work with SRP and Google to bring online Arizona’s newest renewable energy centers.”  

Originally published in Renewable Energy World.

Prevalon brings experience from the BESS business at Mitsubishi Power – over 30 projects, and three gigawatt hours (GWh) of utility-scale battery energy storage systems (BESS) deployed globally. Mitsubishi Power says Prevalon will operate “with the agility of a startup.”

The new entity retains the current leadership team, technology and service offerings, employees, and other assets from the BESS global business at Mitsubishi Power. Prevalon will continue to offer the integrated end-to-end battery energy storage solution, renamed “Prevalon Battery Energy Storage Platform,” which has an energy management system that will also serve as the foundation for Prevalon’s remote monitoring and diagnostics service business.

“As the speed of the energy transition increases, it is imperative that advanced technology solutions such as battery energy storage keep pace,” said Bill Newsom, President and CEO, Mitsubishi Power Americas. “With the establishment of Prevalon, we are confident its dedicated focus on battery energy storage solutions and services will unlock more value in this business to keep pace with this hyper-growth battery energy storage market. This is an example of Mitsubishi Power’s commitment to aligning and structuring its businesses in a way that brings more value and targeted expertise to the ever-changing energy transition.”

The facility broke ground January 18 and is expected to be operational by April, 2025. It will provide Arizona Public Service (APS) customers with energy, support increased power demand, and will also store energy from solar power plants on its grid to use when it is needed, particularly in the summertime when extreme heat and electricity demand is high in Arizona. In May 2023, Strata forged a 20-year tolling agreement with APS.

“The successful financing for the Scatter Wash battery storage complex marks a significant step forward in our mission to drive the transition to clean energy,” said Markus Wilhelm, Chief Executive Officer of Strata Clean Energy. “This opportunity to collaborate with our financing partners to bring this critical project to fruition will create a lasting, sustainable impact on a region that struggles with grid challenges and extreme heat.”

The development of Scatter Wash is supported by the Investment Tax Credit (ITC) for standalone energy storage created by the Inflation Reduction Act (IRA) of 2022. Last year, Strata was one of the first to take advantage of the tax incentive for energy storage for two projects in Vermont.

Strata has more than 270 solar and storage projects completed, per the company, and it has been involved in the development and construction of 3,000 MW of solar energy and 3,200 MWh of utility-scale energy storage. Its current development pipeline contains 8,400 MW of solar capacity and 31,800 MWh of storage.

J.P. Morgan and Nomura acted as coordinating lead arrangers and joint bookrunners. J.P. Morgan also fulfilled roles as administrative agent, depositary agent, and collateral agent. The financing was further supported by U.S. Bancorp Impact Finance and CoBank as coordinating lead arrangers with the Korea Development Bank and Norddeutsche Landesbank as joint lead arrangers. Furthermore, Siemens and Regions contributed as lenders in this transformative project, and U.S. Bancorp Impact Finance was also the primary tax equity investor.

Originally published in Renewable Energy World.

The announcement follows the release of initial data from the group which said it found that there were no reported injuries and no harmful levels of toxins detected following fires at battery energy storage systems in Jefferson, Orange, and Suffolk Counties last summer.

15 draft recommendations have been proposed by the working group after completing an examination of the existing FCNYS and other energy storage fire safety standards. They are meant to address preventative and responsive measures as well as best practices. They include proposed requirements related to peer review of project permit application packages, emergency response planning, and local fire department training.

The working group said the recommendations identify ways to further improve the regulatory framework for BESS operation in New York and are intended to apply to lithium-ion BESS exceeding 600 kilowatt-hours (kWh). The recs were developed with a focus on outdoor systems, BESS in dedicated-use buildings, and other grid-scale battery energy storage systems. They will be considered by the New York State Code Council for inclusion in the next edition of the FCNYS an an effort to improve the deployment of safety standards in the state.

The creation of the working group was announced last summer after a fire at an energy storage system in Warwick burned for multiple days in June; the next month, a battery fire at a solar farm in Jefferson County raised concerns of possible air contamination and an energy storage system at an East Hampton substation caught fire.

State agencies began immediate inspections of energy storage sites, and the working group was created with the intent to help prevent fires and ensure emergency responders have the necessary training and information to prepare and deploy resources in the event of a fire.

In 2019, New York state committed to adding 3,000 MW of Energy Storage by 2030, among other energy and climate goals, as part of the Climate Leadership and Community Protection Act.

“The battery energy storage industry is enabling communities across New York to transition to a clean energy future, and it is critical that we have the comprehensive safety standards in place,” Governor Kathy Hochul said. “Adopting the Working Group’s recommendations will ensure New York’s clean energy transition is done safely and responsibly.”

The Working Group includes State agency officials from the New York State Division of Homeland Security and Emergency Services, New York State Office of Fire Prevention and Control, New York State Energy Research and Development Authority (NYSERDA), New York State Department of Environmental Conservation, Department of Public Service and the Department of State, as well as BESS safety industry experts with the objectives of investigating the recent failure events, inspecting current installations and identifying gaps in codes and industry best practices.

Additionally, the working group said it is concluding negotiations with the impacted facilities’ battery manufacturers and utility companies to secure Root Cause Analysis (RCA) reports for the Warwick, East Hampton, and Chaumont fires. Subject matter experts will review and analyze the reports once they are made available.

The Working Group said it has also partnered with subject matter experts to inspect all operational battery systems above 300 kW in New York, which accounts for the majority of commercial battery systems in service across the state. Inspections are currently underway and are expected to be complete by the second quarter of 2024. The goal of these inspections is to revise the current evaluation checklists and best practices available for use by New York State and others prior to energizing battery energy storage systems and to incorporate lessons learned from the battery fires while enhancing emergency response measures.

Originally published in Renewable Energy World.

The transition to renewable energy—solar, wind, and battery storage—is creating a cleaner generation portfolio but also adding much complexity to generation and dispatching flexibility. This creates increased electric system reliability risk, especially during winter when renewable resources are less available.

Unlike conventional power units, the output of renewable generators may be strongly influenced over a wide geographical area from natural phenomena. Common weather events, such as long winter nights, a string of calm, cloudy days, or even a snowstorm, which may only marginally affect conventional units, if at all, can cause large decreases in intermittent generation output.

This article examines some of the most important aspects of these issues, and it outlines some of the economic concerns as our society moves further from fossil fuels as a means of generating electricity.

Winter wind droughts could become catastrophic

A winter “Wind Drought” over a wide geographic area, such as the one that impacted the 15-state Midcontinent Independent System Operator (MISO) region on January 28-30, 2020, could lead to future capacity shortages. During the 2020 event, wind output was less than one percent of nameplate for 39 consecutive hours (Figure 1).

 At that time, the system had 20.2 GW of nameplate wind capacity but lost nearly all of it during the wind drought. This occurred during what is typically the coldest time of the year. Imagine a night during a future wind drought where there is no solar, little wind and depleted batteries. 

Another example comes from Winter Storm Uri, as shown below.

Reduced renewable capacity, combined with inadequate freeze protection in some locations, caused rolling blackouts and even long-term power outages during a period of extreme cold weather.

Winter brings decreased solar availability

As winter advances each year, the days grow shorter and nights longer with increasing latitude (Figure 3).

The combination of shorter days with widespread cloud cover and fog, as is often experienced during winter, greatly decreases solar output. Furthermore, snow cover, especially in the northern parts of the United States, can impact wide areas, reducing solar output for days or even weeks in some locations.

Combined wind and solar intermittency can bring substantial capacity risks. Below are some general statistics from the mid-latitudes of the United States:

• Wind operates at roughly 40+% capacity factor.
• Solar operates at roughly 20% capacity factor.
• Wind is below 20% capacity ~20% of the time.
• Solar is below 20% capacity ~73% of the time.
• Combined wind and solar is below 20% capacity ~11% of the time.

Any calm night or calm cloudy day can create a potential capacity shortfall. This may become increasingly critical as we move away from conventional generation resources.

Increased winter load during extremely cold weather

During cold waves, the load curve both increases in magnitude and flattens due to increased heating demand. This is evidenced by the actual MISO load curve during Winter Storm Elliott shown in Figure 4.

Such uniform high load factors leave little room for charging Battery Energy Storage Systems (BESS) or electric vehicle batteries.  The changeover from natural gas to electrical home heating systems, as is advocated by some, will further increase and flatten the winter peak load curve per the energy needed during nighttime hours.

Electrification impacts

Electrification, in the context of this article, is defined as electrifying home, commercial, and industrial building heating systems and providing the energy for automobiles and trucks. Continued conversion to electricity will result in very large increases in both annual energy use and peak demand, especially winter peak demand. 

Three main choices exist for residential and small commercial electric heating systems:

• Resistance heat: Resistance heat is 100% efficient; each kWH provides 3413 BTU of heat.
• Air source heat pump: Air source heat pumps are usually twice as efficient as resistance heat. However, efficiency decreases with decreasing ambient temperature. Backup resistance heating is usually necessary at temperatures below ~20^oF.
• Ground source (geothermal) heat pump: Ground source heat pumps are approximately three times as efficient as resistance heaters. However, they are also the most expensive configuration per the need for subterranean ground loops. Supplemental resistance heat is usually necessary when ambient temperatures reach 0^oF.

During the extreme cold of winter peak days, most electric heating systems will operate in resistance heat mode. This in turn will significantly increase the demand, creating a “needle peak” electric demand. The load curve shown in Figure 4 will become even flatter and grow in magnitude as electric heating systems run nearly continuously. For example, consider the changeover from a common 100,000 BTU, 95% efficient gas furnace to an air source heat pump with 25 kW of backup resistance electric heat. The gas system would have provided 95,000 net BTU of heat per hour to the house. On a winter peak day, the electric-resistance backup would only provide (25 kWH) (3413 BTU/kWH) = 85,325 BTU/H, much less than the 95,000 net BTU of the gas system. Thus, the resistance heat would likely run continuously, increasing the peak-day load and load factor.

Another serious issue with electrical heating is the high cost of electricity relative to the price of natural gas. Consider a natural gas cost of $1.00/therm and electricity cost of 10 cents per kWH, both very reasonable values. The gross cost of gas heat would be $10.00/MMBTU, while the cost of resistance electric heat would be approximately 3 times higher, $29.70/MMBTU. Not to be discounted are the high capital costs of service upgrades, new HVAC systems, new appliances, and wiring upgrades. The utilities’ distribution and transmission systems would also likely need to be upgraded which may result in higher electric rates. These costs may make electrification prohibitively expensive and uneconomical.

Beyond residential and commercial heating issues, the increase in the number of electric vehicles will require added electricity for charging. During cold weather, batteries are less efficient and require additional charging. This issue is greatly exacerbated by electric heaters (mostly resistance type) that rapidly consume EV battery capacity and reduce driving distance between recharging.

Battery energy storage has limitations

A major factor that still limits renewable energy development is electrical storage. For example, a typical lithium-ion battery energy storage system (BESS) has approximately 85% cumulative efficiency. Thus, a standard 100 MW, 4-hour BESS needs 400 MWh to charge but only returns 340 MWh to the grid upon discharging. Furthermore, a BESS requires auxiliary power, even in standby mode, to maintain temperature. Therefore, batteries are a net load on the system.

For comparison of BESS capacity to coal storage, consider a typical 500 MW coal unit burning Illinois coal with 30 days of coal storage. Suppose the unit operates at 70% capacity factor. It would produce (500 MW) (0.70) (720 H) = 252,000 MWh of energy per month. If the unit had a net heat rate of 10,000 BTU/kWh and burned coal with a heating value of 10,000 BTU/lb, the required coal storage becomes 126,000 tons. (252,000 MWh * 10,000 BTU/Kwh * 1000 kWh/MWh * 1 lb/10,000 BTU * 1 ton/2000 lb = 126,000 tons.)  At $50/ton, the inventory value of this coal reserve would be $6.3 million.

Now let us calculate the number of batteries needed to store the same amount of energy. Assume 100 MW, 4-hour lithium-ion batteries with 85% efficiency and two charging/discharging cycles per day. Each battery would produce 680 MWh/day and 20,400 MWh per month.  Thus, it would take 13 batteries (rounded up from 12.353) to store the same energy as available from the coal storage.

It is also important to point out that the battery system does not, in fact, produce the electricity. The production must come from another source. The 252,000 MWh supplied by the batteries would require 296,471 MWh for charging.  The energy losses calculate to 44,471 MWh per month. Assuming a capital cost of $1000/kW for each BESS, the 13-100 MW batteries would cost $1.3 billion. This is 206 times the cost of coal energy! 

So, while retiring fossil fuel plants is a primary goal in the efforts to slow down climate change, the economics are very problematic without significant improvement in energy storage technologies. Also critical, as the discussion below further illustrates, is grid reliability.

Future renewable risks

The combination of lower solar output due to shorter and cloudier days and snow-covered panels in certain locations, limited storage capacity and duration, and the possibility of extended wind droughts over large areas can put the electrical system at great risk during the winter. Conversely, renewable sources tend to create the most energy during low load periods. This leads to excess electricity that must be stored, transmitted, or curtailed.

Possible solutions

1. Build a more robust transmission system including interregional high-voltage direct current (HVDC) ties joining the Eastern Interconnection with the Western interconnection and Texas Interconnection.

–Opens new and diverse markets for sales and purchases.

-Geographic diversity lessens the impacts of winter storms.

2. Dedicate some renewable energy for electrolysis of water into green hydrogen and oxygen.

–Don’t connect these units to the electric grid.

–Solves interconnection queue backlogs.

–Solves congestion problems.

3. What to do with the hydrogen?

–Store it for later or even seasonal use.

–Use it at the point of production (Advanced hydrogen-fueled combined cycle plants, Reciprocating internal combustion engines, Fuel cell power plants, Fusion reactors, Fuel cell EVs)

-Transport it via pipelines.

Conclusions

The transition to renewables still requires a fleet of conventional, dispatchable resources for grid reliability. Keeping some coal plants around with their valuable but inexpensive coal storage reserves may not be a bad idea. Carbon capture and sequestration (CCS) may evolve into a viable method to continue fossil plant operation, but many questions exist regarding CCS technology and long-term influences of carbon sequestration.

References

MISO is the Midcontinent Independent System Operator www.misoenergy.org

Figure 3 comes from daylight hours map – Search Images (bing.com)

About the Author: Karl Kohlrus, P.E. graduated from the University of Illinois at Urbana-Champaign with B.S. degrees in Engineering Physics and Electrical Engineering and a master’s in business administration. Karl worked for 31 years in the Planning Department at City Water, Light and Power in Springfield, Illinois performing generation and transmission planning studies. He has since worked for over 12 years as Planning Engineer at Prairie Power, Inc.

Contact information: 

Email kkohlrus@comcast.net

Phone 217-891-4870

The Pike County Battery Energy Storage Project will be located at AES Indiana’s Petersburg Generating Station in Pike County, IN. The grid-connected storage system will provide 200 MW of installed capacity and 800 MWh of dispatchable energy. This system is expected to be operational by December 2024 and online during the MISO 2024-2025 winter season.

“For the past decade, AES Indiana has been on a journey to move to cleaner, more efficient, and cost-effective energy solutions,” said Ken Zagzebski, President & CEO of AES Indiana. “In 2022, we filed our boldest sustainability plan to date with the IURC and this announcement demonstrates our progress toward the commitment to a balanced and responsible energy transition.”

AES Indiana’s sustainability commitments include adding up to 1,300 MW of wind, solar, and battery energy storage from new procurements in the next five years. Its total renewable and energy storage capacity is expected to grow from 400 MW currently in operation to 2,200 MW by 2027.

“Using advanced technologies like energy storage with our current systems increases reliability for our customers,” said Ken Zagzebski, President & CEO of AES Indiana. “As AES Indiana accelerates a cleaner energy future, energy storage helps grid operators efficiently balance the supply and demand of electricity quickly and accurately.”

Two states — California and Texas — account for the vast majority of installed battery storage capacity in the U.S., which has grown from 1.6 GW in 2020 to more than 14 GW by the end of 2023. The trajectory is only expected to continue.

“There was nothing. Now, we’re chasing our…” said Sai Moorty, principal of market design and development at ERCOT, the Texas grid operator.

Moorty joined a panel of regional grid operators at POWERGEN International 2024 in New Orleans alongside CAISO market design sector manager Danny Johnson and Michael DeSosio, a consultant who previously served as the director of market design at NYISO.

Battery storage growth in ERCOT can be largely attributed to a streamlined permitting and interconnection process, as opposed to procurement mandates in states like California and New York.

And while batteries have captured much of ERCOT’s ancillary services market, sustained growth could be predicated on market adjustments, Moorty said. Price volatility in energy-only ERCOT creates uncertainty for developers, while the surge in predominately 1-hour batteries creates operational challenges for the grid operator.

Moorty said a capacity construct, which is under consideration, may be the key to incentivizing longer-duration battery storage development.

“We have good scarcity pricing, our price gaps are really high, but do they last long enough to justify the additional capital investment?” Moorty said. “Lacking (capacity payments), we’re going to have to wait.”

Other potential pitfalls concern state of charge requirements, which determine the amount of power that must be stored in a battery at a given time.

Moorty acknowledges that a state of charge rule issued by ERCOT last year may be viewed by some battery storage developers as discriminatory to the technology. He said the rule is the product of rapid growth and an imperative to adapt to an evolving grid.

“We just don’t have experience with batteries,” Moorty added. “In ERCOT, we’re playing catch up right now.”

California, the U.S. leader in battery storage deployment with 7.3 GW of nameplate installed capacity, is the country’s most formidable market, thanks to capacity payments, broad participation opportunities, and a sizeable procurement mandate.

There are still “significant” challenges facing grid operators, according to Johnson of CAISO. State of charge management tops the list, he said.

“It’s finding the right balance of flexibility for asset owners to utilize and bid-in their assets as they see fit, while also ensuring that, as a grid operator, those assets will be able to perform as dispatched and we can maintain reliability,” Johnson added.

Another, forward capacity planning for battery storage, still eludes grid operators.

The traditional process of adding up total capacity to meet peak load in the coldest or hottest times of the year doesn’t easily incorporate an asset like battery storage, which has to charge in order to serve the grid.

“The traditional stack analysis goes out the window with storage,” Johnson said. “You have to make sure that they have the ability to discharge the energy. When are you charging? How does that get factored into capacity planning?”

New York State’s 194 MW of installed battery capacity pales in comparison to the totals boasted by California and Texas. But near-term capacity constraints, paired with a 3,000 MW energy storage target, present attractive opportunities for developers.

DeSocio, who now leads the consultancy Luminary Energy, said an indexed energy storage credit construct under consideration in New York is a good start. The program would marry capacity payments with energy arbitrage, which at present isn’t economically attractive enough to incentivize storage deployment in the state.

DeSocio advised developers to avoid New York’s retail market, which treats batteries as native load, triggering demand charges.

“There is a whole lot of pressure to get new resources built,” DeSocio said. “The opportunity for storage is two-fold: maximize wholesale revenues (capacity and ancillary services) and offtakers.”

The company says the demonstration provided insights into the capabilities of fuel cell systems to power multi-megawatt data centers, ensuring uninterrupted power supply to meet 99.999% uptime requirements.

The demonstration was conducted in a “challenging” environment, Caterpillar said, at 6,086 ft (1,855 m) above sea level and in below-freezing conditions. The project simulated a 48-hour backup power event at Microsoft’s data center in Cheyenne, Wyoming, where a hydrogen fuel cell was integrated into a data center electrical plant to support its critical load.

A Caterpillar Microgrid Controller was used to operate two Cat Power Grid Stabilization 1260 battery energy storage systems along with the 1.5 MW hydrogen fuel cell. Caterpillar led the project, providing the overall system integration, power electronics, and microgrid controls.

“This successful collaboration with Microsoft and Ballard demonstrates the potential of hydrogen fuel cells to help data centers address their critical power needs while reducing their emissions,” said Jaime Mineart, senior vice president of Caterpillar Electric Power.

Unlocking Hydrogen’s Power Potential is an educational track at the POWERGEN International® exhibition and summit, which serves as an education, business and networking hub for electricity generators, utilities, and solution providers engaged in power generation. Join us from January 23-25, 2024, in New Orleans, Louisiana!

The project was supported and partially funded by the U.S. Department of Energy Hydrogen and Fuel Cell Technologies Office (DOE) under the H2@Scale initiative, which aims to advance affordable hydrogen production, transport, storage, and utilization in multiple energy sectors. During the demonstration, the DOE’s National Renewable Energy Laboratory also analyzed safety, techno-economics, and greenhouse gas (GHG) impacts.

“This project’s success provides an opportunity for hyperscale providers to drive innovations in the sustainability of power generation technologies,” said Sean James, senior director of data center research at Microsoft. “The research and findings of the hydrogen fuel cell demonstration will help us towards our goal of becoming carbon negative by 2030.”

The facility is expected to become operational in April 2025, and is meant to provide Arizona Public Service (APS) customers with energy, support increased power demand, and store renewable energy from solar power plants on its grid to use when it is needed, particularly in the summertime when extreme heat and electricity demand is high in Arizona.

Tesla’s Megapack 2XL, a fully integrated battery system featuring advanced battery technology, software, and power conversion systems, will be used throughout the project.

“Arizona is one of the fastest growing states in the country and reliable and affordable power is critical for APS customers, especially during our hottest summer days,” said Jacob Tetlow, Executive Vice President of Operations at APS. “These batteries will help us continue to serve our customers with a balanced and diverse power supply.”

Energy Storage Deployments is an educational track at the POWERGEN International® exhibition and summit, which serves as an education, business and networking hub for electricity generators, utilities, and solution providers engaged in power generation. Join us from January 23-25, 2024, in New Orleans, Louisiana!

Strata entered into a 20-year tolling agreement with APS for its Scatter Wash battery storage complex last year. This award resulted from the All-Source RFP APS conducted in May of 2022, which was initiated to meet the growing needs of residential and business customers with affordable, reliable, and clean electricity. Under the terms of the agreement, Strata will build, own, and operate the Scatter Wash battery storage complex as part of the firm’s growing portfolio of clean-energy assets.

The development of Scatter Wash is supported by the Investment Tax Credit (ITC) for standalone energy storage created by the Inflation Reduction Act (IRA) of 2022. Last year, Strata was one of the first to take advantage of the tax incentive for energy storage for two projects in Vermont.

Strata has over 270 solar and storage projects completed, the company said, and it has been involved in the development and construction of 3,000 MW of solar energy and 3,200 MWh of utility-scale energy storage. Its current development pipeline has 8,400 MW of solar capacity and 31,800 MWh of storage.

Originally published in Renewable Energy World.

The Kapolei Energy Storage facility on Oahu, Hawaii is now operational, according to Plus Power. The company is calling it the most advanced grid-scale battery energy storage system in the world.

“This is a landmark milestone in the transition to clean energy,” said Brandon Keefe, Plus Power’s Executive Chairman and co-founder. “It’s the first time a battery has been used by a major utility to balance the grid: providing fast frequency response, synthetic inertia, and black start. This project is a postcard from the future — batteries will soon be providing these services, at scale, on the mainland.” 

The KES battery project, located on eight acres of industrial land on the southwest side of Oahu near Honolulu, uses 158 Tesla Megapack 2 XL lithium-ion iron phosphate batteries, each roughly the size of a shipping container. It can offer the grid 185 MW of total capacity and 565 MWh of electricity, acting as an electrical “shock absorber” often served by combustion-powered peaker plants — responding in the blink of an eye (250 milliseconds), rather than the several minutes it takes combustion plants to come online.

“KES is an important part of a portfolio of resources that work together to provide reliability and energy security on Oahu’s isolated island grid,” said Jim Alberts, senior vice president and chief operations officer of Hawaiian Electric. “Energy storage technology that responds quickly to constantly changing conditions is an essential tool for us to use to manage the grid and operate it as efficiently as possible.”

“This is the first time a standalone battery site has provided grid-forming services at this scale – this is a critical application for high renewable penetration grids supplied by 185 MW of Megapack inverters,” said Mike Snyder, Sr Director, Tesla Megapack.

Customer-sited solar power has become so abundant that Hawaiian Electric must regularly ‘curtail’ or turn off large volumes of existing utility-scale solar and wind to keep the electric system in balance. 

Hawaiian Electric’s modeling found that in its first five years in operation, the KES battery plant will allow the utility to reduce curtailment of renewable energy by 69% and integrate 10% more new utility-scale renewables than previous models had allowed while providing for the continued rapid growth of individually-owned renewables such as rooftop solar.   

According to Hawaiian Electric, the project will also save its customers money. The Hawaiian Electric filing for KES estimated it will reduce electric bills by an average of $0.28 per month over a 20-year contract life. 

The battery plant’s specifications include: 

• 135 MW / 540 MWH of capacity and energy
• 50 MW / 25 MWH of additional ‘fast frequency response’ to help keep the electric grid stable 
• ‘Virtual inertia’ to replicate the power-smoothing function of a spinning turbine 
• ‘Black start’ capabilities, which will support grid recovery in the event of a blackout 

The KES plant interconnects near three of Hawaiian Electric’s critical power generation facilities, enabling KES to support the reboot of those power plants in the event of an island-wide emergency, otherwise known as ‘black start’ capability.  

“No one has used batteries to provide such a diverse range of grid-forming services at this scale before in the world,” Keefe said. 

The KES batteries will help replace the grid capacity formerly provided by an AES coal power plant less than a mile away. That plant once produced up to one-fifth of the electricity on Oahu, home to nearly a million of Hawaii’s 1.5 million people and Army, Navy, Air Force, and Marine Corps bases that require reliable power. The coal plant closed in September 2022.  

Plus Power operates multiple KES-sized projects, and has a rapidly growing development portfolio of large-scale battery systems with 10 gigawatts of projects in transmission queues across 28 states and Canada, with over $1.8 billion in project financings announced in October 2023. 

“Plus Power is in the business of solving hard climate problems,” said Keefe. “Our projects, like KES, help our customers provide affordable, reliable, clean electricity on hot summer afternoons and cold winter nights, while enabling the decarbonization of the electric grid.”

By June 2024, Plus Power will be operating seven additional large-scale battery energy storage plants across Arizona and Texas, for a total of 1325 MW / 3500 MWh. 

“This project provides another example of Hawai’i’s leadership in the clean energy transition,” said Mark B. Glick, Hawai’i’s Chief Energy Officer. “The grid modernization strategies employed by Plus Power support a cleaner, more reliable, and more affordable energy system.”