Lazard has published its annual set of updated cost reports on power generation, energy storage and hydrogen. In this year’s Updated Storage Cost Analysis – Version 7.0, the group analyzed 12 energy storage projects, three of which were US-based battery storage facilities coupled with solar power.
The first case study was a direct to network wholesale project, the second was integrated into a commercial-industrial (C&I) site, and the third was located in someone’s house. For wholesale and commercial analysis, two lithium-ion battery solutions and two flow batteries were considered; the residential site only considered 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 both wholesale and commercial projects.
Although somewhat less energy dense, chemical lithium-ion phosphate batteries are quickly becoming the preferred stationary battery technology due to their thermal simplicity, low price, and high availability. In the flux battery space, this author would like to get the folks at Lazard to consider adding an iron oxide flux product like ESS or Form Energy on the wholesale and commercial side, and the Redflow and Zinc8 for residential consideration.
The report raised concerns about future price stability and product availability as demand for battery products increases. Lazard cited the auto industry’s pressure on lithium-ion products, a trend with no end in sight. The report says cars now make up 75% of lithium-ion cells, although that number is expected to grow to 90% by 2030. And, while stationary storage will grow from its current market share by 5%, it will likely be less than 10% market share until 2030.
This suggests that while stationary energy storage will benefit from technological innovations funded primarily by transportation, it will likely be constrained by the vagaries of the automotive market.
Obviously, parallels can 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 lifetime non-subsidized discounted electricity costs (LCOE) ranged from 8.5 to 15.8 / kWh, 23.5 to 33.5 ¢ / kWh, and 41.6 to 62.1 / kWh, respectively.
The wholesale battery is located in the ERCOT region of Texas, the C&I unit is in CAISO California, and the residential unit is located in the Hawaiian power grid.
The wholesale facility in Corpus Christi, Texas is expected to have an internal rate of return of 29.1%. None of its cited revenues came from the direct sale of solar power in the market.
Wholesale PV + Storage, ERCOT (Corpus Christi, Texas)
The 50 MW / 200 MWh battery must be charged exclusively from a 50 MW AC coupled solar power plant for the first five years to benefit from the full investment tax credit. The analysis predicts an average annual revenue of $ 4,693 / kW for the three types of services provided by the battery. Each of these services only runs part of the time, although they may run simultaneously part of that time.
The largest cost to be covered by the sale of the system’s stored energy is hardware, with $ 62 of the $ 85 in revenue going to fund the cost of the equipment. About 11% of the costs are spent on purchasing electricity from the solar power plant.
Lazard suggested that once the incentives run out, the California C&I energy storage market will face difficult financial arguments. With the current incentives, however, the IRR of this solar plus storage office space is a respectable 23.4%.
C&I PV + Storage, PG&E (San Francisco, CA)
The project is coupled in direct current to a solar power station. The battery is used to charge the electricity demand of a large office space in San Francisco. Most of the project’s income comes from managing the bill for an hourly electricity tariff. The California market has cheap daytime electricity due to heavy solar power and expensive electricity in the early evening. Battery life shifts solar energy to use in the evening.
Without this change, economizing on autonomous solar power has become increasingly difficult. Lazard suggested that without the local incentive payment, saving batteries would also be difficult.
The study did not assign any technical value to the resilience provided by batteries in commercial or residential environments.
The solar + storage residential project in Hawaii currently derives all of its revenue from bill management; that is, to capture its energy from excess solar energy and sell it back to the grid when the sun goes down.
PV + residential storage, HECO (Honolulu, Hawaii)
This model works mainly because Hawaiians generate so much solar electricity that they are no longer allowed to export electricity to the grid. The state recently began paying solar power owners to add energy storage with the goal of giving the electricity grid access to distributed storage during peak demand periods.
Because electricity is expensive in Hawaii, the financial model works for batteries. In most states, however, home energy arbitrage does not produce enough revenue to pay for a battery. Future Lazard models could include utility capacity payments, like those in Hawaii or those recently announced in Utah.
And finally, in what will hopefully appear in future case studies, here is a list of “recent project activities” that were researched as Lazard developed their analysis:
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