Energy storage race: Has the monopoly of pumped-storage in Europe come to an end?

Highlights

• Energy-only markets do not incentivize investment in energy storage.

• Investments in compressed air have become competitive with pumped-storage.

• Markets promote daily pumped-storage installations rather than seasonal.

• Policy should reduce the financial risk associated with CAES, rather than subsidization.

• Interconnection may be a threat to energy storage.

Abstract

The rise of renewable energies has brought a new challenge in terms of the management of their intermittency. Pumped-storage hydroelectricity has served as the large-scale solution to the intermittency problem. However, flawed European spot markets and innovation are jeopardizing the future of this technology. This paper: 1) estimates historic revenues of 96 energy storage installations on 17 European electricity spot markets, 2) assesses how arbitrage revenue has evolved, and 3) compares the present value of new energy technologies (compressed air, batteries) with pumped-storage in energy-only markets. Results show that market openings to competition had led to revenue drops and convergence: all markets generate low income. Based on the findings: 1) energy storage requires revenue from other markets than spot ones 2) compressed air energy storage is competitive with pumped-storage, and 3) markets value daily pumped-storage installations rather than seasonal, where this technology keeps a technical comparative advantage. It means the current best pumped-storage installation design could not be the long-term one. We also highlight that further research should investigate if interconnection, a natural monopoly, competes with energy storage, which is open to competition.

Introduction

Electricity generation must match consumption at any given moment. Otherwise, it affects the frequency and may lead to blackouts. System operators must ensure enough flexibility, i.e. “the ability of a power system to maintain continuous service in the face of rapid and large swings in supply or demand” (Papaefthymiou et al., 2014, p.3). This is a challenging task, given that electricity generation fluctuations, especially in case of renewables. Photovoltaic panels stop supplying at night, wind turbines need specific weather conditions, and run-of-river hydropower relies on water seasonality. Therefore, increasing share of new renewable energy jeopardizes electric system reliability (Shafiullah et al., 2013).

The electricity system operator can address the intermittency problem using five main options (IEA, 2008). First, the energy generation can be reduced in case of an excess of supply, e.g. by braking turbines. This strategy is rarely applied where Feed-In-Tariff mechanisms guarantee a cost-based purchase price to renewable energy generation are in place. Operators have no economic incentive to stop their installations even during negative-price events. The second option is using backup technologies, such as gas turbines, which can generate electricity quickly to ensure supply follows demand. Demand-side management, e.g. through the introduction of information and communication technology (ICT) and smart grids is the third option. Interconnection can be used as the fourth option to balance supply and demand. When a grid covers a small geographical area, it is subject to homogenous meteorological and climatic conditions. Through interconnections, an integrated system can be formed over a larger area as big as a continent (e.g. Europe). Then, the undesirable (e.g. windy) conditions in part of the interconnected system can be compensated by desirable (e.g. cloudy) conditions in another part. The last option, which is the focus of this paper, is employing energy storage technologies (introduced in the Section 2.1) (IEA, 2008). Storage technologies are charged during off-peak hours to generate energy during peak times. However, the profitability of energy storage technologies has become questionable with the experienced growth in renewable energy development.

Various specific case studies in Europe showed that renewable energy and storage energy may be complementary from an economic perspective (Gomes et al., 2017, Khalilpour and Vassallo, 2016, Mulder et al., 2013). Connolly et al. (2012) showed that pumped-storage is a cost-effective way of stimulating wind penetration in the Irish market. Zafirakis et al. (2013) conducted a similar study in Greece and investigated the option of storing energy by compressing air (CAES). This technology was found to be only profitable in the German market if wind energy represents a large share of energy generation (Swider, 2007). Anagnostopoulos and Papantonis (2012) looked at the implementation of a pump system in an existing hydropower plant in Greece. They concluded that PSES becomes attractive as intermittent energy sources become more propagated. Iliadis and Gnansounou (2016) conducted an analysis of a Swiss PSES installation. They considered revenue from both day-ahead and intraday markets. Connolly et al. (2011) assessed the profitability of generic PSES installations in 13 electricity markets.

It is important to understand how the mature PSES is being threatened by newer technologies (IEA, 2014). Numerous studies have compared energy storage technologies in Europe. Some contrast their technical characteristics and capital costs (IEA, 2014, Kousksou et al., 2014, Lopes Ferreira et al., 2013, Evans et al., 2012, Dunn et al., 2011), however, they do not assess revenue and investment. Lund and Salgi (2009) compared the results of various energy storage technologies for the Danish electric system from a social planner's perspective. They also showed that CAES with an arbitrage-only revenue model is not profitable on the Noorpool market. Loisel (2012) showed that compressed air energy storage (CAES) is unprofitable in France, although it holds a social value. Finally, Kazempour et al. (2009) show that PSES is more profitable than NaS battery in Spain.

These studies provide a good understanding of the electric system dynamics; however, none analyses a broad set of technologies at a European level. They lack a meaningful comparison of the various technologies with consideration of all European electricity spot prices. The case specific results presented above could be further expanded upon to identify regional trends to tackle policy issues at continental level, which is getting increasingly interconnected.

Our study aims to assess whether arbitrage revenues alone, can attract investment in storage in Europe, whether situations converge in every market, and whether operators capitalize on their ability to export their flexibility to neighboring markets. Furthermore, this study provides insights into the tradeoffs between round-trip efficiency and power. This information will facilitate the evaluating the benefits of innovation, which generally improves efficiency.

This study is carried out from a techno-economic perspective. We simulated the operations of 96 generic energy storage installations on 17 European spot markets. A numerical algorithm maximizes the annual revenue (archived on Zenodo, Gaudard and Madani, 2017) to identify historical trends. We also compute the Present Analysis and Modified Internal Rate of Return (MIRR) of the most common bulk storage technologies in order to assess their profitability.

All models, including our model, have simplifying assumptions that need to be considered when interpreting their outputs. Despite its limitations, out model helps us develop a better understanding of operations in a large area and provides a dataset that is versatile. It therefore contributes to the emerging literature on the topic with its original perspective.