Electricity In Great Britain Research Articles

Predicting future GB heat pump electricity demand

To meet net zero carbon targets by 2050s, countries with cold winters, such as Great Britain (GB), will turn to low carbon domestic heating systems such as electric heat pumps. In this paper, a statistical model is developed using measured performance data from over 550 heat pumps installed in GB homes in 2012. The model is used to predict the additional load on the GB electricity generation and distribution infrastructure for various current and future (2050) climates, dwelling energy efficiencies and heat pump deployment scenarios. For a cold year in the 2020s, a 100% uptake of heat pumps in the existing GB dwelling stock gave a peak electricity demand for the heat pumps of 78 GW and an annual electricity demand of 189 TWh. When added to the other, existing electricity demand, this represents an increase in the GB peak electricity demand in excess of 100% and an annual electricity demand increase of around 60%. Making reasonable assumptions about heat pumps’ future efficiency and use, and the future climate and dwelling stock fabric efficiency, and assuming 80% heat pump uptake and no load shifting, the peak heat pump electricity demand for a cold year in the 2050s halved to 37 GW. By shifting demand for water and space heating the 2020s cold year peak demand reduced by 15%. The work provides a more robust estimate of future GB heat pump electricity demands than any previously available. The predicted future ramp rates, peak and annual total electricity demands, are lower than predicted by previous analysts.

A Day-Ahead Scheduling Model of Power Systems Incorporating Multiple Tidal Range Power Stations

With the global trend to exploit more renewable energy sources, tidal range energy has been gaining more attention recently. This power generation technology is expected to reduce the share of fossil fuels and provide flexibility to the power system. With a pioneering tidal range generation project just granted in Wales and more proposals planned in Great Britain, it is important to study how the incorporation of multiple tidal range power stations will affect power system operation. In this paper, the role of tidal range energy generation in the future Great Britain power system is investigated based on a day-ahead scheduling model of power system incorporating multiple tidal range power stations. In the proposed model, tidal range power stations situated at different sites operate flexibly and in coordination, supporting the power system to reach the minimum operating cost. A case study based on the Great Britain electricity transmission system in 2030 with one tidal barrage and one tidal lagoon was investigated. The results showed that the coordination of flexible tidal range power stations can reduce the power system's operating cost. Furthermore, the energy-storage feature of tidal range power stations can act as a stable source of flexibility in the power system.

Ancillary services in Great Britain during the COVID-19 lockdown: A glimpse of the carbon-free future

The COVID-19 pandemic led to partial or total lockdowns in several countries during the first half of 2020, which in turn caused a depressed electricity demand. In Great Britain (GB), this low demand combined with large renewable output at times, created conditions that were not expected until renewable capacity increases to meet emissions targets in coming years. The GB system experienced periods of very high instantaneous penetration of non-synchronous renewables, compromising system stability due to the lack of inertia in the grid. In this paper, a detailed analysis of the consequences of the lockdown on the GB electricity system is provided, focusing on the ancillary services procured to guarantee stability. Ancillary-services costs increased by £200m in the months of May to July 2020 compared to the same period in 2019 (a threefold increase), highlighting the importance of ancillary services in low-carbon systems. Furthermore, a frequency-secured scheduling model is used in the present paper to showcase the future trends that GB is expected to experience, as penetration of renewables increases on the road to net-zero emissions by 2050. Several sensitivities are considered, demonstrating that the share of total operating costs represented by ancillary services could reach 35%.

Incumbent lobbying as a barrier to forward-looking regulation: The case of demand-side response in the GB capacity market for electricity

The current transformation of energy systems around the world is fundamentally a policy-driven process, unlike previous socio-technical transitions. This article focuses on the challenges of constructing forward-looking policies for sustainable energy transitions in the presence of powerful incumbent interests, through an in-depth study of how the emerging option of demand-side response (DSR) was incorporated into the Capacity Market (CM) for electricity in Great Britain over the period 2010 to 2014. Drawing on extensive documentation related to the development of the CM rules and interviews with participants and close observers of the process, the paper provides an unusually detailed assessment of the influence of companies with large electricity generation assets. The evidence presented supports the hypotheses that these companies had influence through deploying public facing strategies, that they had been able to draw on close networks of contacts and networks with senior policy makers, and that the latter had internalised the ideas and interests of the former. Despite counter-lobbying by DSR firms and non-governmental organisations, institutional arrangements gave major generators an advantage in terms of access. The paper concludes by recommending the establishment of independent bodies to propose policies and monitor the process of their development during energy system transformations.

Electricity market integration, decarbonisation and security of supply: Dynamic volatility connectedness in the Irish and Great Britain markets

Abstract This study investigates the volatility connectedness between the Irish and Great Britain electricity markets and how it is driven by changes in energy policy, institutional structures and political ideologies. We assess various aspects of this volatility connectedness including static (unconditional) vs dynamic (conditional), symmetric vs asymmetric characteristics between 2009 and 2018. We find that the volatility connectedness is time-varying and it is significantly affected by important events, policy reforms or market re-designs such as Brexit, oil price slump, an increasing share of renewables, and fluctuations in the exchange rates. Our asymmetric analysis shows that magnitude of the good volatility connectedness is marginally larger than that of the bad volatility connectedness. Our result suggests that good volatility levels would be even higher once the Irish market adopts the carbon price floor. Therefore, supporting renewable generation by setting an appropriate price of carbon in interconnected wholesale electricity markets will improve market integration.

Electricity Market Integration, Decarbonisation and Security of Supply: Dynamic Volatility Connectedness in the Irish and Great Britain Markets

This study investigates the volatility connectedness between the Irish and Great Britain electricity markets and how it is driven by changes in energy policy, institutional structures and political ideologies. We assess various aspects of this volatility connectedness including static (unconditional) vs dynamic (conditional), symmetric vs asymmetric characteristics between 2009 and 2018. We find that volatility connectedness is time varying and is significantly affected by important events, policy reforms or market re-designs such as Brexit, oil price slump, increasing share of renewables, and fluctuations in the exchange rates. Our asymmetric analysis shows that the magnitude of the good volatility connectedness is marginally larger than that of the bad volatility connectedness. Our result suggests that good volatility levels would be even higher once the Irish market adopts the carbon price floor. Therefore, supporting renewable generation by setting an appropriate carbon price in interconnected wholesale electricity markets will improve market integration.

Unpacking ‘regime resistance’ in low-carbon transitions: The case of the British Capacity Market

The ability of powerful incumbent actors to resist technological or institutional changes that threaten their vested interests is a core part of the literature on sustainable energy transitions, but more often asserted in general than tested in specific cases. This article presents analysis of a detailed study of the introduction of a Capacity Market (CM) for electricity in Great Britain in the period 2010–2011, using a process tracing approach. The study finds evidence to support the view that large electricity generators have a significant degree of structural power in relation to decision makers, that such companies did lobby the government through the CM policy process, and that the ideas deployed had an effect on the shape of the CM. However, there were also divisions amongst the large generating companies on whether they wanted a CM or not, and what its design should be. We also show that the institutional circumstances of the CM policy process were quite specific, giving opportunities for lobbying that may not be present in other cases. We conclude it is essential to have an analysis of incumbent power that is contingent on institutional context, the specific nature of interests and the deployment of ideas. To counter incumbent power and structural dependency during sustainable energy transformation, an independent but legitimate body is needed to the direction of policy.

Review of GB electricity distribution system's electricity security of supply, reliability and power quality in meeting UK industrial strategy requirements

The United Kingdom (UK) Government's 2017 Industrial Strategy outlines a bold plan centred on making the UK one of the most competitive places in the world to start or grow a business, building on the UK's strengths, extending excellence into the future, and closing the gap between the UK's best performing companies, industries, places and people, and those viewed as less productive. In the context of delivering this strategy, from power system reliability and power quality points of view, this study explores the various challenges and gaps in the Great Britain (GB) electricity distribution system, which is recognised as among the most complex forms of energy exchange that will become the backbone of the emerging digital economy and Industry 4.0. Additionally, the study also provides recommendations to address the identified challenges.

Risk Constrained Trading Strategies for Stochastic Generation with a Single-Price Balancing Market

Trading energy from wind and other forms of stochastic generation in competitive electricity markets is challenging due to the limited predictability of these resources. This paper examines the specific case of single-price balancing markets and derives risk-constrained strategies in a probabilistic framework, going beyond the trivial zero/max solution, which would have participants offer either zero or their maximum energy production based on a prediction of whether the system will be in net up- or down-regulation. The zero/max approach is unacceptable in reality as it exposes the participant to potentially huge imbalance charges, and would violate price taker assumption for a portfolio of significant size. Here, we propose several trading strategies that control risk by hedging against penalising balancing prices in favour of rewarding ones by contracting forecast generation plus some adjustment. These strategies are formulated in a probabilistic framework to address the presence of forecast uncertainty and asymmetric costs in balancing markets. A case study using data from the Great Britain electricity market is presented and it is shown that the proposed strategies are able to simultaneously increase revenue and reduce risk using risk-constrained strategies. Furthermore, the required forecasts of electricity prices and system length are produced using standard tools and widely available explanatory information and are found to have sufficient skill to increase revenue compared to not hedging.

Using investment appraisal models in strategic negotiation: The cultural political economy of electricity generation

Although accepting that the Discounted Cash Flow model of investment appraisal has well known technical limitations, researchers have begun to explore its performative properties. This paper demonstrates how the Discounted Cash Flow model frames negotiations between actors around narratives of economization, marketization and financialization in a regulated industry. Reconnecting economics and politics, the theory of Cultural Political Economy is used to interpret and evaluate an empirical study of Great Britain's electricity generating industry. Although alternative imaginaries, based on political and employment goals, have historically influenced investment decision making in the industry, the current narrative of investment appraisal is dominated by Discounted Cash Flow models. These models have allowed industry players to construct imaginaries of an investment hiatus, leading to the possibility of future power cuts and blackouts, and a need for guaranteed prices.

Impact of storage competition on energy markets

We study how storage, operating as a price maker within a market environment, may be optimally operated over an extended period of time. The optimality criterion may be the maximisation of the profit of the storage itself, where this profit results from the exploitation of the differences in market clearing prices at different times. Alternatively it may be the minimisation of the cost of generation, or the maximisation of consumer surplus or social welfare. In all cases there is calculated for each successive time-step the cost function measuring the total impact of whatever action is taken by the storage. The succession of such cost functions provides the information for the storage to determine how to behave over time, forming the basis of the appropriate optimisation problem.We study particularly competition between multiple stores, where the objective of each store is to maximise its own income given the activities of the remainder. We show that, at the Cournot Nash equilibrium, multiple stores which between them have market impact collectively erode their own abilities to make profits: essentially each store attempts to increase its own profit over time by overcompeting at the expense of the remainder. We quantify this for linear price functions.We give examples throughout based on electricity storage and Great Britain electricity spot-price market data.

Benefits of demand-side response in combined gas and electricity networks

Active demand side response (DSR) will provide a significant opportunity to enhance the power system flexibility in the Great Britain (GB). Although electricity peak shaving has a clear reduction on required investments in the power system, the benefits on the gas supply network have not been examined. Using a Combined Gas and Electricity Networks expansion model (CGEN+), the impact of DSR on the electricity and gas supply systems in GB was investigated for the time horizon from 2010 to 2050s. The results showed a significant reduction in the capacity of new gas-fired power plants, caused by electricity peak shaving. The reduction of gas-fired power plants achieved through DSR consequently reduced the requirements for gas import capacity up to 90 million cubic meter per day by 2050. The cost savings resulted from the deployment of DSR over a 50-year time horizon from 2010 was estimated to be around £60 billion for the GB power system. Although, the cost saving achieved in the gas network was not significant, it was shown that the DSR will have a crucial role to play in the improvement of security of gas supply.

The value of conservation voltage reduction to electricity security of supply

In the specific event that there is not enough electricity being produced in the power market of Great Britain to meet demand, the system operator can use a set of mitigation tools to manage these supply shortfalls that are outside of normal operation of the market and that are used ahead of any controlled customer disconnections. Demand control is an emergency mitigation tool used by the system operator that instructs distribution network operators to implement voltage reduction across the electricity distribution system with the intent of achieving a reduction in customer's demand. The introduction of new low carbon generation and demand technologies in the electricity distribution networks, with fundamentally different technical and operating characteristics from the incumbent technologies, is likely to drive a dissimilar impact on the level of demand reduction that can be achieved through voltage reduction compared to those previously expected. Thus, there is a need to comprehensively understand the effectiveness of the voltage reduction in electricity distribution networks that can be realised through demand control events. The delivery of demand control can be achieved through conservation voltage reduction (CVR) techniques based on the principle of lowering the supply voltage to end-use consumers of electricity in order to reduce the energy consumption of some types of loads while maintaining customer service voltage within statutory limits. This paper presents a methodology to quantify and assess the value of CVR to security of supply of electricity systems. Specifically, it estimates the response of electricity demand to demand control events in the electricity distribution system to reduce customer's demand during periods of significantly low supply-demand margins. The methodology is applied to a network structure representative of the electricity distribution network of Great Britain and the value of CVR is estimated for individual distribution network feeders and for the distribution system over an annual load cycle. The analysis demonstrates that the response of demand to voltage reduction is relatively different from substation to substation, feeder to feeder and especially load to load. The CVR factor for the Great Britain electricity distribution network is assessed to vary on average from 0.81 in the summer season to 1.13 in the winter season. The CVR factors for the electricity distribution network of Great Britain are expressed in the form of a look up table to provide a simple framework for network operators to estimate the response of demand to voltage reduction/demand control events.

Embodied carbon dioxide of network assets in a decarbonised electricity grid

Calculating carbon dioxide (CO2) emissions associated with electricity is a key component in the field of Life Cycle Assessment (LCA), but is often cited as challenging due to the complex nature of electricity systems despite its importance to the outcome. While calculating the operational CO2 emissions associated with electricity generation is an active research field, the embodied CO2 emissions, typically referred to as embodied carbon, of network assets has far less representation in the literature. This paper focuses on the CO2 emissions aspect of LCA to calculate the embodied CO2 of network assets in relation to the operational grid CO2 over time. Several functional units are defined: CO2 per operational year, CO2 per asset cost, CO2 per functional unit of electricity (kWh) and the relationship between embodied emissions and operational emissions in an electricity system over time. Hybrid functional units are then applied in order to better attribute the embodied carbon to the network functions. The hybrid functional units involve network asset lifetime and the issue of temporal horizons. Several suitable horizons are suggested and the comparison of results highlight the importance of the timeframe on results. The relationship between temporal horizons and environmental discounting is discussed and recommendations are made on the appropriate level of discounting depending on the temporal horizon and the purpose of the LCA. The paper uses data from the Great Britain electricity system where planned investment in network assets is £12bn at distribution level (Dx) and £16.4bn at transmission level (Tx) over the next eight years. By using GB network data for embodied carbon, demand and asset data, as well as data from the decarbonisation of electricity generation, indicative results are provided into the way in which embodied carbon impacts could change over time, showing that by 2035, the embodied carbon of the transmission network could contribute almost 25% of total emissions associated with electricity. On a regional basis, DNO level network assets could reach anywhere between 40% and 130%. This network data is also used to show that new network investment could account for up to 6.5% of DNO level network embodied carbon when front loaded during the RIIO-ED1 period.

Challenges of Primary Frequency Control and Benefits of Primary Frequency Response Support from Electric Vehicles

As the integration of wind generation displaces conventional plants, system inertia provided by rotating mass declines, causing concerns over system frequency stability. This paper implements an advanced stochastic scheduling model with inertia-dependent fast frequency response requirements to investigate the challenges on the primary frequency control in the future Great Britain electricity system. The results suggest that the required volume and the associated cost of primary frequency response increase significantly along with the increased capacity of wind plants. Alternative measures (e.g. electric vehicles) have been proposed to alleviate these concerns. Therefore, this paper also analyses the benefits of primary frequency response support from electric vehicles in reducing system operation cost, wind curtailment and carbon emissions.

Role of power-to-gas in an integrated gas and electricity system in Great Britain

Power-to-gas (PtG) converts electricity into hydrogen using the electrolysis process and uses the gas grid for the storage and transport of hydrogen. Hydrogen is injected into a gas network in a quantity and quality compatible with the gas safety regulations and thereby transported as a mixture of hydrogen and natural gas to demand centres. Once integrated into the electricity network, PtG systems can provide flexibility to the power system and absorb excess electricity from renewables to produce hydrogen. Injection of hydrogen into the gas network reduces gas volumes supplied from terminals.In order to investigate this concept, hydrogen electrolysers were included as a technology option within an operational optimisation model of the Great Britain (GB) combined gas and electricity network (CGEN). The model was used to determine the minimum cost of meeting the electricity and gas demand in a typical low and high electricity demand day in GB, in the presence of a significant capacity of wind generation. The value of employing power-to-gas systems in the gas and electricity supply system was investigated given different allowable levels of hydrogen injections. The results showed that producing hydrogen from electricity is capable of reducing wind curtailment in a high wind case and decreasing the overall cost of operating the GB gas and electricity network. The northern part of GB was identified as a suitable region to develop hydrogen electrolysis and injection facilities due to its vicinity to a significant capacity of wind generation, as well as the existence of gas network headroom capacity, which is expected to increase as a result of depletion of UK domestic gas resources.

Technical benefits of energy storage and electricity interconnections in future British power systems

There are concerns that the GB (Great Britain) electricity system may not be able to fully absorb increasing levels of variable renewables with consequent implications for emission reduction targets.1 This study considers the technical benefits of additional energy storage and interconnections in future GB electricity systems. Initially a reference model of the GB electricity system was developed using the EnergyPLAN tool. The model was validated against actual data and was confirmed to accurately represent the GB electricity system. Subsequently, an analysis of four possible scenarios, for the years 2020 and 2030, has been performed and the maximum technically feasible wind penetration calculated. Finally, the level of interconnection and energy storage has been varied to assess the technical benefits to the operation of a 2030 GB electricity system. We conclude that increasing levels of interconnection and energy storage allow a further reduction in the primary energy supply and an increase in maximum technically feasible wind penetration, permitting the system emissions intensity to be reduced from 483 gCO2/kWh in 2012 to 113 gCO2/kWh in 2030. Increasing the levels of interconnection and energy storage has significant technical benefits in the potential future GB systems considered.

The potential for bioenergy crops to contribute to meeting GB heat and electricity demands

AbstractThe paper presents a model system, which consists of a partial equilibrium model and process‐based terrestrial biogeochemistry models, to determine the optimal distributions of both Miscanthus (Miscanthus × giganteus) and short rotation coppice willow (SRC) (Salix. viminalis L. x S. viminalis var Joruun) in Great Britain (GB), as well as their potential contribution to meet heat and electricity demand in GB. Results show that the potential contribution of Miscanthus and SRC to heat and electricity demand is significant. Without considering farm‐scale economic constraints, Miscanthus and SRC could generate, in an economically competitive way compared with other energy generation costs, 224 800 GWh yr−1 heat and 112 500 GWh yr−1 electricity, with 8 Mha of available land under Miscanthus and SRC, accounting for 66% of total heat demand and 62% of total electricity demand respectively. Given the pattern of heat and electricity demand, and the relative yields of Miscanthus and SRC in different parts of GB, Miscanthus is mainly favoured in the Midlands and areas in the South of GB, whereas SRC is favoured in Scotland, the Midlands and areas in the South of GB.

Experiences of the Electricity System Operator Incentive Scheme in Great Britain

National Grid is the electricity system operator in Great Britain and has an unique feature in so far as it is one of the world’s few for-profit system operators. In addition, the commercially orientation of the British market rules means that nearly every action taken by National Grid to operate the system has a cost associated to it. Based on those factors and in order to encourage National Grid to seek continuous improvements and drive for efficient and economic system operation, the regulator (Ofgem) offers an incentive scheme, whereby a target is agreed annually and any savings in relation to this target are shared between consumers and National Grid in the form of a profit. It is in National Grid’s best interest to have mechanisms to mitigate the impacts of volatility in the costs it faces as system operator so that it can implement cost saving actions without the risk of windfall losses (or gains) arising from sudden changes in uncontrollable drivers. The purpose of this paper is to share the experiences of National Grid in the operation of Great Britain's electricity system, with a special interest on the mechanisms created to manage the associated costs in response to the incentive scheme. It does so by describing the market operation in Great Britain and the costs drivers impacting National Grid’s system operation and illustrating the steps recently taken by National Grid to propose volatility mitigation mechanisms. It concludes with the rationale and expected results from the latest proposals as consulted with the industry for introduction in the incentive scheme starting on 1st April 2011. It is worth noting that with this work, the authors wish to both share the experience with other system operators and regulators in the world, as well as give British market participants an insight on the inner workings of National Grid.

Valuing diversity in energy supply

There is renewed interest in the role of supply diversity in promoting energy security. This paper explores ways of valuing diversity. A possible incentive mechanism for promoting diversity which takes account of underlying “disparities” between different technology options is developed. The mechanism provides a way of trading off cost and diversity and results in an “efficient” cost-diversity frontier by analogy with financial portfolio theory. If all technologies are believed to be equally disparate, the appropriate mechanism is a “levy” imposed on market share. If the technologies are not equally disparate, the levy needs to be adjusted by technology-specific multipliers that take account of levels of disparity and patterns of market share. The analysis is applied to two stylised situations. In the long-run equilibrium case, the implications of both different patterns of disparity and different values attached to diversity are investigated. The paper also explores the implications of applying such a mechanism to the current Great Britain electricity system. The implications in terms of financial flows, for both the market as a whole and for individual operators, are investigated. Finally, the appropriateness of such a mechanism in the light of other policy goals, and possible future research directions, is discussed.