Search

Funding Information: B.Z. acknowledges the funding from Whole System Energy Modelling (WholeSEM), University College London; Aalborg University, Denmark; and International Institute for Applied Systems Analysis (IIASA). The contribution of G.C.G. and P.E.D funded by the UK Engineering and Physical Research Council (EPSRC) through the Realising ES Technologies in Low-carbon Energy Systems (RESTLESS) project (EP/N001893/1). The authors would also like to thank Professor Richard Green (Imperial College London) and Professor Ramteen Sioshansi (Ohio State University) for useful suggestions, as well as Dina Subkhankulova (UCL) for data provision. Publisher Copyright: © 2021 The Author(s) Copyright: Copyright 2021 Elsevier B.V., All rights reserved. Share of solar photovoltaic (PV) is rapidly growing worldwide as technology costs decline and national energy policies promote distributed renewable energy systems. Solar PV can be paired with energy storage systems to increase the self-consumption of PV onsite, and possibly provide grid-level services, such as peak shaving and load levelling. However, the investment on energy storage may not return under current market conditions. We propose three types of policies to incentivise residential electricity consumers to pair solar PV with battery energy storage, namely, a PV self-consumption feed-in tariff bonus; “energy storage policies” for rewarding discharge of electricity from home batteries at times the grid needs most; and dynamic retail pricing mechanisms for enhancing the arbitrage value of residential electricity storage. We soft-link a consumer cost optimization model with a national power system model to analyse the impact of the proposed policies on the economic viability of PV-storage for residential end-users in the UK. The results show that replacing PV generation incentives with a corresponding PV self-consumption bonus offers return on investment in a home battery, equal to a 70% capital subsidy for the battery, but with one-third of regulatory costs. The proposed energy storage policies offer positive return on investment of 40% when pairing a battery with solar PV, without the need for central coordination of decentralized energy storage nor providing ancillary services by electricity storage in buildings. We find that the choice of optimal storage size and dynamic electricity tariffs are key to maximize the profitability of PV-battery energy storage systems.

Energy storage has been identified as a priority technology for innovation. However, the rapidly developing family of storage technologies will find it difficult, under the current regulatory regimes, to compete with conventional generators for the provision of electricity system services, and this is likely to impede innovation. This paper analyses and categorizes 16 investment barriers hindering the near-term deployment of energy storage technologies in electricity markets, which are related to four regulatory and public attitudes barriers. The most important regulatory barrier is the current classification of storage as a generation asset, despite it being unable to provide a positive net flow of electricity, which is used to justify double network usage charges. The merit order design of balancing and ancillary markets hampers the ability of storage technologies to recoup their relatively high capital cost, while capacity markets penalize their limited discharge duration. Network companies are in the best position to realize the system value of storage, but their ownership may only be acceptable if system operation is made independent of network operation. Current initiatives to address these issues include flexible connection agreements and the development of enhanced frequency response and aggregate fast reserve services. However, to remove the identified barriers, a market structure that valued the flexibility offered by storage, viewing it as complementing rather than competing with network and generation assets, would be required.

Funding Information: This research was funded by the UK Engineering and Physical Research Council ( EPSRC ) through the Realising Energy Storage Technologies in Low-carbon Energy Systems (RESTLESS) project ( EP/N001893/1 ), for which the authors are very grateful. The contribution by BZ have been partly supported by International Institute for Applied Systems Analysis (IIASA), and the RE-INVEST project “Renewable Energy Investment Strategies – A two-dimensional interconnectivity approach” funded by Innovation Fund, Denmark. The authors would also like to thank Professor Richard Green (Imperial College London) for useful suggestions. Publisher Copyright: © 2021 The Author(s) Distributed energy storage is a solution for increasing self-consumption of variable renewable energy such as solar and wind energy at the end user site. Small-scale energy storage systems can be centrally coordinated by “aggregation” to offer different services to the grid, such as operational flexibility and peak shaving. This paper shows how centralized coordination vs. distributed operation of residential electricity storage (home batteries) could affect the savings of owners. A hybrid method is applied to model the operation of solar photovoltaic (PV) and battery energy storage for a typical UK householder, linked with a whole-system power system model to account for long-term energy transitions. Based on results, electricity consumers can accumulate greater savings under centralized coordination by between 4 and 8% when operating no technology, by 3-11% with electricity storage alone, by 2-5% with stand-alone solar PV, while 0-2% with PV-battery combined. Centralized coordination of home batteries offers more optimized electricity prices in the system, and as such, higher private savings to all consumers. However, consumers without onsite energy technologies benefit more than PV-battery owners. Therefore, based on system-level benefits of aggregation, the regulator should incentivize prosumers with PV-battery, who are able to balance their electricity supply-demand even without central coordination, to let their storage be controlled centrally. Possible revenues of storage owners from ancillary services as well as the cost of aggregation (e.g., transaction fees charged by aggregators) are not considered in this analysis.

This study investigates the relationship between daily electricity spot price returns and both the crude oil spot price return (in US dollars) and the exchange rate return in six European countries (France, Germany, Italy, the Netherlands, Spain and the United Kingdom) during the time periods 2005-7 and 2008-11, i.e., before and after the contagion of the subprime crisis on European markets. The conditional mean and conditional variance are modeled by AR (1) GARCH (1,1) and AR (1) NGARCH (1,1). The performance superiority of the nonlinear asymmetric generalized auto regressive conditional heteroscedasticity (GARCH) model suggests that the leverage effect is well represented. In many cases, the level of returns in either the oil price or the exchange rate had little impact on the level of electricity price returns, but the volatility of these prices affected the volatility of electricity prices in all the European countries examined, except for the United Kingdom. However, in the succeeding time period (2008–11), the volatility of electricity prices in each of the countries studied, including the United Kingdom, was significantly and asymmetrically affected by both exchange rate and oil price returns. This volatility, or risk, has implications for the way in which low-carbon generators should be supported.