Lazard released its annual set of levelized cost reports on electricity generation, energy storage, and hydrogen. In this year’s Levelized Cost of Storage Analysis – Version 7.0, the group analyzed 12 energy storage projects, three of which were U.S.-based battery storage facilities coupled with solar power.
The first case study was a direct-to-grid wholesale project, the second was integrated into a commercial-industrial (C&I) site, and the third was located in someone’s home. For the wholesale and commercial analysis, two lithium ion and two flow battery solutions were considered; the residential site considered only lithium ion models.
The case studies, however, focused on a single battery chemistry. Based on the pricing, it appears that lithium technologies were chosen for the wholesale and commercial projects.
Despite being somewhat less energy dense, lithium ion phosphate chemistry batteries are fast becoming the preferred stationary battery technology due to their thermal simplicity, low price, and high availability. In the flow battery space, this author would like to nudge the Lazard folks to consider adding an iron-oxide flow product from the likes of ESS or Form Energy on the wholesale and commercial side, and the Redflow and Zinc8 for residential consideration.
The report raised concerns over future pricing stability and product availability as demand for battery products increases. Lazard cited the automotive industry’s squeeze on lithium ion products, a trend with no end in sight. The report stated that cars today account for 75% of lithium ion cells, although that number is expected to reach 90% by 2030. And, while stationary storage will grow from its current market share of 5%, it will likely fall short of a 10% market share through 2030.
This suggests that even though stationary energy storage will benefit from the technological innovations funded primarily by transportation, it will likely be constrained by the whims of the auto market.
Clearly, parallels may be drawn between the energy storage industry, the computer chip industry, and the solar cell industry.
The three solar plus storage projects — wholesale, C&I, residential — had solar volumes of 50 MW, 50 kW and 6 kW. The four hour batteries were rated at 100 MW, 1 MW and 10 kW. Their respective lifetime unsubsidized levelized costs of electricity (LCOE) had ranges of 8.5-15.8¢/kWh, 23.5-33.5¢/kWh, and 41.6-62.1¢/kWh, respectively.
The wholesale battery is located in the Texas ERCOT region, the C&I unit is in California’s CAISO, and the residential unit is located in the Hawaiian power grid.
The Corpus Christi, Texas wholesale facility was projected to have an internal rate of return of 29.1%. None of its cited revenues came from selling solar directly to the market.
Wholesale PV+Storage, ERCOT (Corpus Christi, Texas)
The 50 MW/200 MWh battery must charge exclusively from an AC-coupled 50 MW solar power plant for the first five years to qualify for the full Investment Tax Credit benefit. The analysis forecast an average annual revenue of $4,693/kW for the three types of services the battery provides. Each of these services run only part of the time, although they may run concurrently some of that time.
The largest of the costs to be covered by selling the system’s stored energy is hardware, with $62 of the $85 in revenue going to finance the price of the equipment. Around 11% of the costs go toward buying electricity from the solar power plant.
Lazard suggested that after incentives run out, the California C&I energy storage market will face some challenging financial arguments. With the current incentives, however, the IRR of this office space solar-plus-storage is a respectable 23.4%.
C&I PV+Storage, PG&E (San Francisco, California)
The project is DC-coupled to a solar power plant. The battery is used to load shape the electricity demand of a large San Francisco office space. Most of the project’s revenue comes from bill management of a time-of-use electricity tariff. The California market has cheap daytime electricity due to heavy solar, and expensive early evening electricity. The battery time shifts the solar power to be used in the evening period.
Without this shift, the economics of standalone solar have been getting progressively more challenging. Lazard suggested that without the local incentive payment, battery economics would be challenging as well.
The study did not assign any technical value to the resiliency provided by the batteries in either the commercial or residential settings.
The residential solar+storage project located in Hawaii currently gets all of its revenue from bill management; that is, capturing its energy from excess solar power, and selling it back to the grid when the sun is down.
Residential PV+Storage, HECO (Honolulu, Hawaii)
This model works primarily because Hawaiians produce so much solar electricity that they’re no longer allowed to export electricity to the grid. The state recently started to pay solar owners to add energy storage in an attempt to give the power grid access to distributed storage during periods of peak demand.
Because electricity is expensive in Hawaii, the financial model works out for batteries. In most states, however, home energy arbitrage does not produce sufficient revenue to pay off a battery. Future models from Lazard may include capacity payments from utilities, like those in Hawaii or like those recently announced in Utah.
And finally, in what may hopefully appear in future case studies, here is a list of “recent project activity” which was researched while Lazard was developing their analysis:
- Flow: SDG&E and Sumitomo Electric have partnered to install a 2 MW / 8 MWh vanadium redox flow battery in California
- Thermal: Vantaa Energy intends to deploy 90 GWh of thermal storage in Finland in 2022
- Mechanical: Hydrostor has proposed a 200 MW / 1,600 MWh CAES project in New South Wales, Australia (Hydrostor In Canada)
- Other: Form Energy and Great River Energy have partnered to install a 1 MW / 150 MWh aqueous air battery in Minnesota with a target in-service data of 2023
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