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Seeking Consensus on the Internalized Costs of Mature Energy Storage Technologies
- Jul 7, 2018 8:48 pm GMT
What is meant by “internalized costs”?
Internalized costs are the costs which can be accurately accounted for in our current systems. In energy production, these costs typically consist of capital costs, financing costs, operation and maintenance costs, and exploration costs. Some energy options incur these costs in various stages such as extraction, transportation and refinement. Profits and taxes are excluded wherever possible in order to isolate the pure cost of production.
Internalized costs of energy storage
This article will cover three mature energy storage solutions: 1) thermal power plants, 2) pumped hydro storage and 3) compressed air energy storage (CAES). Pre-commercial technologies such as batteries and synthetic fuels will be covered in subsequent articles.
Thermal power plants
The neatly packaged chemical potential energy in fossil fuels offers the simplest energy storage solution through thermal power stations. This is also the most economical solution at low to medium penetrations of intermittent renewables. Costs stem from three main components which increase with the intermittent renewable energy penetration: 1) profile costs primarily from the underutilization of generating capacity, 2) balancing costs from imperfect forecasting and 3) grid-related costs from longer-distance transmission and congestion.
The profile costs in the above figure are primarily a function of the cost of the underutilized capital and the capacity credit of the intermittent renewable energy resource. Capacity credit is a measure of the ability of intermittent renewables to displace dispatchable capacity and is highly case-specific depending on the match between load and intermittent output. In general, increasing penetration of intermittent renewables causes underutilization of more expensive capital and also reduces the overall capacity credit, hence the increase in costs with increasing deployment.
Profile costs related to energy storage in fossil fuels are given below as a function of the capital costs of the underutilized generating capacity and the capacity credit. Other assumptions include fixed O&M costs of $20/kW/yr, a 30 year lifetime and 70% capacity factor of the backup plant and a 5% discount rate. Other smaller effects like decreased efficiency and increased wear on increasingly cycled plants are neglected. The figure is valid up to ~20% penetration where significant curtailment of intermittent renewables becomes necessary. The Excel datasheet used to create this figure can be accessed here.
General comments on energy storage economics
Before moving on, it can be useful to briefly discuss the most important factors influencing the economics of specialized energy storage technologies: capital costs and capacity utilization. Capacity utilization is an especially important issue in energy storage because of the trade-off between capacity factor and the spread between the price at which the storage facility can buy and sell electricity. At higher capacity factors, the initial capital investment will be better utilized, but the spread between the buying and selling price will also narrow.
Germany currently offers a good example of the type of buy-sell spreads available in a system with substantial intermittent renewable energy penetration. As shown from the graph below, a buy-sell spread of about €20/MWh is available for probably about 20% of the average day while spreads of €50/MWh are only available on isolated occasions.
It is important to note that spreads required for economic energy storage are generally larger than those available in the open market. This explains the very low penetration of mature energy storage technologies.
The USA has the most developed energy storage capacity with about 20 GW of pumped hydro capacity. However, calculations using the reported net-energy consumption of these facilities under the assumption of a 75% round-trip efficiency reveals a capacity factor of only 7.5%, indicating a very limited time-window where the buy-sell spread is sufficient for profitable operation.
Finally, it should be mentioned that numbers utilized in the remainder of this article are guided by data available from the reviews of Duke University and DNV.
Pumped hydro storage
After fossil fuels, the simplest and most mature storage options are pumped hydro storage (PHS) and compressed air energy storage (CAES). Both these storage options have been in operation for decades (although deployment is very small relative to total electricity generation).
The required breakeven buy-sell spread for PHS is given below. Additional assumptions include a 40 year plant lifetime, 5% discount rate, fixed O&M of $5/kW/yr, 75% round-trip efficiency, and an average electricity buying price of $30/MWh. The Excel datasheet used to create this figure can be accessed here.
As shown in the graph above, PHS can become economically viable to a limited extent if capital costs can be kept very low. For example, capital costs of $1000/kW and the US capacity factor of 7.5% would require a spread of just over $100/MWh which does occasionally present itself. It is therefore clear that PHS is a very simple energy storage option which can be economically viable at very low penetrations as a peak-load generator or provider of additional short-term grid services. It should be mentioned, however, that PHS is strongly limited by geography and can have sizable environmental impacts.
Compressed air energy storage (CAES)
CAES facilities can be either diabatic (heat generated during compression is lost) or adiabatic (heat generated during compression is retained). In general, diabatic designs are simpler, but less efficient. Only diabatic facilities are currently in operation although the first adiabatic facility should go online in Germany around 2016.
The breakeven spread for CAES is given below under the assumptions of a 30 year plant lifetime, 5% discount rate, fixed O&M of $10/kW/yr, 60% round-trip efficiency, and an average electricity buying price of $30/MWh.
It is clear that CAES performs very similarly to PHS and can therefore also play a significant part in future energy storage markets. The main drawback of currently mature diabatic CAES technology is that it is dependent on natural gas to replenish the energy lost during compression in order to effectively drive a gas turbine. Adiabatic CAES can be a standalone energy storage solution, but will be substantially more expensive. CAES is also limited by geography, although much less so than PHS.
If you have a number that differs significantly from the estimates given above, please add it in the comments section below together with an explanation and a reference.
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