LCOS – A Key Metric for Cost of Energy Storage
Dec 19, 2019
By Ronald F. Cascone and Pat Sonti
The paradigm of typical economic analyses of process plants with captive power generation facilities is built around a cost of production (COP) or cost of electricity (COE) analysis. These are both modelling methodologies for evaluating the economic viability of chemical and energy conversion processes and facilities against competing technologies and the prevailing market price for the product(s). These traditional COP or COE analysis are familiar to most in the chemical and hydrocarbon energy industries. The analyses are performed for various regions of the world, and under varying assumptions, including modelling sensitivity of the outcomes to various assumptions and physical parameters. These COPs or COEs are however, “snapshots in time” and do not tell the complete story of the operations and lifecycle of the entire process in a time sequence from start to end of life of a project, as does a financial pro-forma. For the global energy utility industry, which typically works on a business model of a franchise or concession from the public to provide electricity and related ancillary services on a monopoly basis, a current snapshot of economics is not enough, but requires economic lifecycle analysis more like a pro-forma over the energy plant or facility’s useful life. This type of techno-economic analysis is known as levelized cost of electricity (LCOE) for power generation facilities, or for energy storage projects, levelized cost of storage (LCOS), as modelled for a longer period of say, twenty or thirty years.
The “Black Box”
Plants and Facilities
To better understand the cost metrics of COP, COE, LCOE, and LCOS in the most basic terms, think of a chemical plant, refinery, or power generation facility as a “black box” into which some chemicals and/or hydrocarbons are fed along with other ingredients. Together with the materials fed, other key inputs or “stuff” is fed, such as utilities such as electricity, steam, water, and inert gas. The labor costs are added, as well as the costs of other requirements such as insurance, security, waste disposal, etc. The Capex of the facility, both the direct process equipment and supporting systems such as required to handle utilities, shipping, and security are obtained and allocated to a ratio of debt and equity financing. Depreciation of the equipment investment is added in as a cost. The other project costs, such as construction management are accounted for. The processes in the “black box” convert the feedstock(s) into products and byproducts, which must have a higher value than the costs of the raw materials, other inputs, and financing for this activity to make any sense. The margin on sales can be calculated using market prices of the output product streams. For the case of captive or grid interconnected power generation facilities, the products and byproducts can include electric power, steam, and other ancillary services. Typically, electricity markets are regulated by federal and/or state government agencies driven by competitive power tariffs for power generation, transmission, and distribution to wholesale and retail customers.
Battery Energy Storage System
For a battery energy storage system (BESS) project, a similar “black box” approach can be utilized for costs and techno-economic evaluations, except that the “inputs” are essentially electricity as available (non-dispatchable), plus Capex. The additional costs, typically very small, can include maintenance labor and materials, insurance, and possibly some minor chemicals and operating labor costs. The output is dispatchable electricity. That is, what goes in is electricity, but electricity that is generated stochastically (randomly, potentially not when needed). Coming out is dispatchable electricity (available on-demand). Because it is available on demand, the output electricity is more valuable (higher priced) than the input, which may have little or no value at times. In fact, there have been occasions in Germany and elsewhere during which generators actually made payments to off-takers of the electricity generated when not needed to avoid upsetting the grid. The price arbitrage across the “black box” in the conversion of non-dispatchable or excess electricity generation to dispatchable is the primary economic benefit of the storage system.
The cost metric of LCOS is basically the “all-in” cost to design, construct, and utilize the BESS over the course of its useful economic life cycle. In particular, this includes the fixed and variable O&M costs, effects of the battery technology’s degradation over time (i.e., decreased output), etc. When comparing a BESS against an alternative resource (e.g., flow batteries versus Li-Ion or lead acid), the LCOS is the preferred unit of measurement. In principle, as shown in Figure 1, the LCOS calculation for energy storage is analogous to the LCOE calculation for power generation facilities, but uses charging cost as the input “fuel” cost and takes the discharged electricity instead of generated electricity.
- Capitalt = Total Capex in year t
- O&Mt = Fixed O&M costs in year t
- Fuelt = Charging cost in year t
- MWht = The amount of electricity discharged in MWh in year t (measure for the capacity factor)
- (1+r) - t = The discount factor for year t
Many energy storage technologies are impacted by degradation – including batteries. In particular, energy utilities as well as commercial and industrial (C&I) facilities have relatively little experience with the effect of degradation on battery life, especially with the newer battery chemistries. Accordingly, estimates for the energy portion of the LCOS (i.e., the divisor in the LCOS ratio) are likely to become more precise in the coming years as more large-scale BESS operational data becomes available for detailed evaluation.
Figure 2 illustrates the typical cost structure of LCOS.
LCOS Driven by End-Use Applications
Large-scale BESS can be effectively utilized in behind-the-meter (BTM) and/or front-of-the-meter (FTM) applications. For example, the BTM end-use applications generally pertain to C&I facilities and domestic residential customers, with or without integration of solar photovoltaics (PV) and/or wind power. Given that each of these end-use cases requires a distinct battery module capacity (in MWh) and cycling schedule, their respective LCOSs differ somewhat. As the LCOS of the different battery technologies and chemistries varies, defining the end-use application becomes critical to ensure the optimal techno-economics and cost benefit analysis. Battery technologies can have various end-use applications and that can lead to selecting one specific battery technology over another. These include system reliability, economic dispatch, and locational value. Some battery technologies are a viable choice for durations from a few minutes to over 4 hours, which can include peaking capacity, energy, arbitrage, and T&D deferral.
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