This paper examines the likely market for electrical energy storage from a market viewpoint, taking market prices as given and determining the extent to which a strategy of arbitrage across the day, buying at the lowest price times at night and selling at the highest times during the early evening, generates profits in the British context. The paper sets out the potential problems as the market moves to absorb increasing amounts of wind, then characterises the nature of prices, which reveals the importance of a strategy in which power is absorbed into store for a relatively few hours of the day and discharged over a relatively few hours. The paper models the ongoing costs of operation and compares them with revenues, but does not consider construction costs. It argues that additional incentives may need to be put into place in order to render storage over relatively longer periods more attractive.

The Symposium on Energy and Environmental Policy will bring together high ranking researchers in the field of energy economics. The meeting will examine various questions related to the low carbon alternatives (energy storage, RES-E, and shale gas), the markets and networks (energy losses, CO2 market design and distributed generation), and the environmental policies (RES-E promotion, consumption side policies, industrial policy for climate change mitigation, and environmental R&D investment).

This paper studies the effect of energy market integration (EMI) on foreign direct investment (FDI). EMIs diminish energy uncertainty and price volatility in the host country and affect FDI through two channels: first, by harmonizing energy prices and, second, by reducing price dispersion. FDI may, as a result, increase both within and outside the EMI area, through energy stability mechanisms and price mechanisms, respectively. An empirical application on a global dataset including bilateral FDI data, during 2003-2012, using the gravity equation, shows that the integration of Portugal and Spain’s electricity market in 2007 increased the amount of FDI’s participants. Additionally, a positive increase in FDI from neighboring countries (in this instance, France), albeit lower in magnitude, is observed.

A successful deployment of power generation coming from variable renewable sources (VRES-E), such as wind and solar photovoltaic, strongly depends on the economic cost of system integration. This paper, in seeking to look beyond the impact of RES-E generation on the evolution of the total economic costs associated with the operation of the electricity system, aims to estimate the sensitivity of balancing market requirements and costs to the variable and non-fully predictable nature of intermittent renewable generation. The estimations reported in this paper for the Spanish electricity system stress the importance of both attributes as well as power system flexibility when accounting for the cost of balancing services.

European energy markets have undergone a major transformation as they have advanced towards market liberalisation and it is vital that the details of these developments be carefully examined. The success of liberalisation is based on smart regulation, which has been capable of providing solutions to unforeseen events in the process. Our paper seeks to contribute to existing understanding of the unexpected consequences of the liberalisation process in the power system by examining a natural experiment that occurred in Spain in 2009. In that year, the electricity supply by distribution system operators (DSOs) disappeared. This positive change in retail market competition, as we demonstrate in this paper, has had an unexpected effect in terms of the system’s balancing requirements. We undertake a rigorous assessment of the economic consequences of this policy change for the whole system, in terms of its impact on final electricity prices.

In this paper we look at the relative merits of two capacity utilization regimes in the merchant electricity transmission network: Must offer (Mo) where the entire capacity installed is made available for transmission and Non Must Offer (NMo) where some capacity could be withheld. We look at two specific cases: (i) Demand for transmission varies across time, and (ii) Vertical integration is allowed between investors in transmission network and electricity generators. In the case of time-varying demand under Mo, we find that a monopolist may underinvest in transmission when compared to NMo, although NMo may lead to more capacity withholding. In the case of vertical integration, we find that when the market power is with the generators of the exporting node, without vertical integration no welfare-enhancing merchant investment would occur. Further, if the generators in the importing node have market power, which of the two regimes is welfare enhancing depends on the parameter values. In case vertical integration is better, then Mo is better than NMo. Finally, we also argue that the incentive to collude among various transmission network investors is mitigated with Mo in place.