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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 can make key contributions to balancing future low-carbon energy systems by providing a variety of energy system services, with batteries expected to be widely deployed as costs fall with innovation. This paper assesses whether synergies exist between two of the most significant of these services, fast frequency response and energy arbitrage, if a battery energy storage system (BESS) is used to deliver both. A techno-economic model is developed to simulate 600 possible fast frequency response availability windows. Results show that two distinct synergies exist between the two services. The first synergy accounts for the possibility of charging outside the deadband for delivering fast frequency response. We propose an innovative state-of-charge management strategy to exploit this synergy. The second synergy results from energy arbitrage revenues being highly concentrated around peak times, which can enable a battery system to capture most of the arbitrage revenues without an excessive reduction in revenues from capacity provision with enhanced frequency response. The combination of these two synergies means that a battery system could increase its operating profits by 25% by delivering arbitrage and frequency response alternately. This result is shown to be statistically robust using historical data. A battery system able to discharge for 1.5–2 h at its full power rating will most most likely optimise these synergies.

The adoption of solar photovoltaic and electrical energy storage by end users depends on their economic attractiveness, which is typically assessed with metrics of future cash flow such as Net Present Value (NPV). Yet analyses using NPV typically do not account for the evolution towards low-carbon electricity systems in the short and long term. We show this to be of critical importance for accurately calculating the profitability of these technologies. By linking an energy system model with a power system model, we observe substantial differences between NPV estimates calculated with and without representing potential evolutions of the electricity system. Our results suggest that not accounting for short- and long-run changes in the electricity system could underestimate the NPV of an investment in photovoltaic and storage by around 20%, especially in scenarios with high levels of renewables, moderate flexibility, and high electrification in the energy system. Using system-dependent cash flow metrics can havea major impact on end-users' energy technology profitability.

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.

Cost pass-through (CPT) rates give a useful perspective of market competition. This article studies how input costs of electricity generation are passed through to the wholesale price in Great Britain between 2015 and 2018. Our empirical results fail to reject the null hypothesis of 100% CPT rates for gas costs and EUA prices (and coal costs for most hours), suggesting a competitive British wholesale electricity market in most hours. We observe a higher CPT rate for coal costs in peak and off-peak periods. This is due to coal plants usually bidding at rates somewhat lower than marginal costs during off-peak periods in order to dispatch at their minimum load to avoid the costs of shutting down and starting back up. Instead, during peak periods the rate of capacity utilisation is high and marginal coal plants tend to exercise their market power, resulting in a higher CPT rate for coal costs. We extend the argument by assessing coal plants’ bidding and find evidence of coal plants exercising market power in hours with high residual demand, generating extreme prices.

Interconnectors have value for Britain, providing access to cheaper Continental power, security of supply, and managing increased renewables, prompting proposals for substantial new interconnectors. The EU Target Electricity Model requires interconnector market coupling via Day Ahead and IntraDay Markets. We examine the efficiency and value of uncoupled and coupled trading for the four DC interconnectors to GB, over different timescales from year ahead to intraday, and the social costs and benefits not reflected in the private benefits. Because the GB carbon tax is not replicated abroad it transfers some €65 m./yr to the foreign interconnector part-owners and creates distortions when trade flows change. IFA and BritNed have a commercial value of about €500 million/yr, create additional infra-marginal surplus of €25 m./yr, but suffer €30 m./yr deadweight loss from the asymmetric GB carbon tax. The island of Ireland was coupled in Oct 2018, dramatically reducing trading inefficiency. While further investment in interconnectors appears socially profitable, it is important to harmonise carbon taxes across the EU. If GB leaves the EU and is uncoupled, some of these trading gains would be sacrificed, but other financial markets may alleviate the cost of Brexit, making policies to enhance liquidity desirable.

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.