Busting myths around baseload generation, LCOE and energy storage

In most places, renewable energy provides the least expensive form of new generation measured according “Levelized Cost of Electricity” (LCoE). LCoE measures the cost per unit of electrical energy produced ($/MWh). In Portugal, a power auction in July yielded €14.70/MWh. In the recent UK contracts-for-difference auction, one winning offshore wind power bid was for £39.65/MWh.

LCoE is a useful indicator when a high proportion of generation is from intrinsically-flexible generators such as hydropower or thermal generation from fossil fuels. LCoE is not useful when assessing the costs of an energy system powered mainly from renewables. Wind and sunshine are intermittent resources that do not correlate perfectly with demand. The intermittency brings additional costs.

To run an energy system largely from renewables, some major sources of flexibility are needed to reconcile the difference between the availability of natural resources for generation and the demand for power. The cost of providing the flexibility could exceed the cost of the primary generation by a substantial amount and therefore total system cost must be considered.

Thermo-mechanical energy storage (TMES) technologies such as compressed air energy storage, pumped heat energy storage, liquid air energy storage, pumped hydro etc. are well suited to play a major role in future energy systems that have high penetrations of renewables. This article addresses two grotesque misunderstandings in widespread circulation.

 Misunderstanding #1: Baseload generation is good

The idea that baseload is good tends to be purveyed by proponents of nuclear power. In most nuclear power plants, the marginal savings associated with reducing output power are very small. For all other thermal generation plants, fuel costs form a significant part of total cost. In a system powered fully by thermal power plants including some nuclear stations, optimal system operation would see the nuclear generators running at full power all of the time and other generators flexing to meet remaining demand – even if the LCoE for nuclear was higher than that for the combustion plant. The economic requirement that nuclear plant should generate at constant output reduces the utilization of other generators and increases their LCoE.

“Baseload” suggests reliability and this certainly has appeal. If the LCoE of nuclear generation was vanishingly low, this perception would be well-founded. However, with a high LCoE (the LCoE for Hinkley Point C is £92.50/MWh), “baseload” is bad. The remaining demand after baseload has been satisfied correlates even less well to the availability of generation resource.

Put simply, If renewable generation coupled with storage could be an economically viable solution for the demand remaining after a large slice of constant-power generation was already satisfied by inflexible nuclear power, then this combination solution would be even more cost-effective if scaled up to meet the entire need with no nuclear power. 

In short, inflexible “baseload generation” is bad, not good!

Misunderstanding #2: Large amounts of inter-seasonal energy storage will be needed in a system powered mostly with renewable energy.

The arguments supporting this misunderstanding rest on the observation that total energy demand in the UK is strongly seasonal – driven by heating requirements in winter. As shown by Wilson et al, the combined consumption of gas plus electricity in the colder half-year exceeds half of the total annual consumption by ~22%.

However, wind power in the UK is itself strongly seasonal and its once-per-year variation peaks in mid-winter – just like demand. In fact, the average power developed by a modern offshore wind turbine in UK waters during the colder half-year would exceed 50% of its total annual production by ~25% in an average year. Sinden highlighted this seasonality in 2007 for onshore wind turbines. If we were to replace all existing primary energy sources used for gas and electricity with offshore wind in the UK, we would find that we had an over-supply of energy in the colder half-year.

Taking an electrified transportation system into account also along with some penetration of heat-pumps for heating, improved insulation standards and strong growth of energy consumption for data-processing, it is clear that the seasonality of demand will decrease significantly in future. In that case, we can find a blend of solar power and wind power that almost-perfectly matches the once-per-year variation in demand.

The implications of the misunderstanding about inter-seasonal energy storage are very significant. Failing to appreciate and capitalize on the major seasonal variation of wind power in the UK leads to the conclusion that energy storage capacity much in excess of 100TWh would be needed for a largely-renewable UK.  This in turn prejudices towards conclusions that (a) gas combustion with CCS will be cost-effective in the future and (b) that extensive production of hydrogen will need to happen to absorb energy in summer and consume more in winter.

These conclusions have the secondary effect that the economic case for all TMES technologies is severely and unfairly damaged. In reality, a UK powered largely by renewables and having ~10TWh of TMES together with a slight (~5%?) over-capacity of renewable generation with the correct mix of solar and wind power is probably the cost-optimal solution for a secure, affordable and net-zero-CO2 energy system.

The author does not suggest that no long-term energy storage is required. Weather varies and our ability to predict it over timescales measured in years remains rather poor. It would be prudent to implement some long-term storage – probably ~25TWh. This might comprise some biomass in dry stores, some hydrogen in caverns and/or synthesised liquid fuels like ammonia in tanks.

The key point is that we should not aim to cycle this store frequently. The combination of good turnaround efficiency (typically 60% – 85%) and low cost per unit of energy storage capacity is what makes the TMES solutions preferable for handling most of the storage throughflow.  A set of turbines or fuel-cells rated at 300 MW would be sufficient to discharge a 25TWh store over one year and that will be seen to be the real role for long-term energy storage in the UK.

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Seamus Garvey is Professor of Dynamics at the University Of Nottingham. He has been interested in energy storage and the tight integration of energy storage with renewables since 2005 and has undertaken numerous projects in these areas. These have ranged from placing bags of compressed air deep under water, through exploring cavern-based compressed air energy storage with local solar thermal collection and, most recently, the use of heat pumping to integrate energy storage directly with offshore wind. Prof. Garvey is/has-been a principal investigator or co-investigator on research grants in these areas to a collective value of over £4M and has published over 40 papers in the area.

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