105 results found
Gambhir A, Green R, Grubb M, et al., 2021, How are future energy technology costs estimated? can we do better?, International Review of Environmental and Resource Economics, Vol: 15, Pages: 1-48, ISSN: 1932-1465
Making informed estimates of future energy technology costs is central to understanding the cost of the low-carbon transition. A number of methods have been used to make such estimates: extrapolating empirically derived learning rates; use of expert elicitations; and engineering assessments which analyse future developments for technology components’ cost and performance parameters. In addition, there is a rich literature on different energy technology innovation systems analysis frameworks, which identify and analyse the many processes that drive technologies’ development, including those that make them increasingly cost-competitive and commercially ready. However, there is a surprising lack of linkage between the fields of technology cost projections and technology innovation systems analysis. There is a clear opportunity to better relate these two fields, such that the detailed processes included in technology innovation systems frameworks can be fully considered when estimating future energy technology costs.Here we demonstrate how this can be done. We identify that learning curve, expert elicitation and engineering assessment methods already either implicitly or explicitly incorporate some elements of technology innovation systems frameworks, most commonly those relating to R&D and deployment-related drivers. Yet they could more explicitly encompass a broader range of innovation processes. For example, future cost developments could be considered in light of the extent to which there is a well-functioning energy technological innovation system (TIS), including support for the direction of technology research, industry experimentation and development, market formation including by demand-pull policies and technology legitimation. We suggest that failure to fully encompass such processes may have contributed to overestimates of nuclear cost reductions and under-estimates of offshore wind cost reductions in the last decade.
Green R, Staffell I, 2021, The contribution of taxes, subsidies and regulations to British electricity decarbonisation, Publisher: Elsevier
Great Britain’s carbon emissions from electricity generation fell by two-thirds between 2012 and 2019, providing an important example for other nations. This rapid transition was driven by a complex interplay of policies and events: investment in renewable generation, closure of coal power stations, raising carbon prices and energy efficiency measures. Previous studies of the impact of these simultaneous individual measures miss their interactions with each other and with exogenous changes in fuel prices and the weather. Here we use Shapley values, a concept from cooperative game theory, to disentangle these and precisely attribute outcomes (CO2 saved, changes to electricity prices and fossil fuel consumption) to individual drivers. We find the effectiveness of each driver remained stable despite the transformation seen over the 7 years we study. The four main drivers each saved 19–29 MtCO2 per year in 2019, reinforcing the view that there is no ‘silver bullet’, and a multi-faceted approach to deep decarbonisation is essential.
Halttunen K, Staffell I, Slade R, et al., 2020, Global assessment of the merit-order effect and revenue cannibalisation for variable renewable energy, Publisher: Elsevier
The rapid growth of wind and solar power has been a major driver for decarbonisation worldwide. They tend to reduce wholesale electricity prices, both the time-weighted average (the merit‑order effect) and their own output-weighted average (price cannibalisation). Whilst these effects have been widely observed, most previous studies focus on single countries. Here, we compare 37 electricity markets across Europe, North America, Australia and Japan and explore variations between them.Merit-order and cannibalisation effects are observed in nearly all countries studied. However, only in Germany, Spain, Poland, Portugal, Denmark and California can renewable output explain more than 10% of variation in wholesale electricity prices. The global average merit‑order effect is €0.68±€0.54 /MWh per percentage point increase in variable renewable energy penetration, and this falls with higher penetration. Revenues captured by wind farms decrease by 0.23% (€0.16 /MWh) for each percentage point increase of wind penetration and by 1.94% (€0.90 /MWh) for solar PV.
Green R, Staffell I, 2020, The Contribution of Taxes, Subsidies and Regulations to British Electricity Decarbonisation
Geske J, Green R, Staffell I, 2020, Elecxit: the cost of bilaterally uncoupling British-EU Electricity Trade, Energy Economics, Vol: 85, Pages: 1-16, ISSN: 0140-9883
The UK's withdrawal from the European Union could mean that it leaves the EU's Internal Energy Market for electricity (Elecxit). This paper develops methods to study the longer-term consequences of this electricity market disintegration, especially the end of market coupling. Before European electricity markets were coupled, different market closing times forced traders to commit to cross-border trading volumes based on anticipated market prices. Interconnector capacity was often under-used, and power sometimes flowed from high- to low-price areas. A model of these market frictions is developed, empirically verified on 2009 data (before French and British market coupling) and applied to estimate the costs of market uncoupling in 2030. A less efficient market and the abandonment of some planned interconnectors would raise generation costs by €700 m a year (2%) compared to remaining in the Internal Energy Market. This result is sensitive to how the British and French electricity systems develop over the coming decades. Economic losses are four times greater (€2700 m a year) if France retains substantial nuclear capacity due to its low marginal costs. Conversely, losses are reduced by two-thirds if UK weakens its decarbonisation ambitions, as lower carbon prices subsidise British fossil fuel generation, allowing electricity prices to converge with those in France. A Hard Elecxit would make British prices rise in three of our four scenarios, while those in France would fall in all of them.
Geske J, Green R, 2020, Optimal storage, investment and management under uncertainty: it is costly to avoid outages!, Energy Journal, Vol: 41, Pages: 1-28, ISSN: 0195-6574
We show how electricity storage is operated optimally when the load net of renewable output is uncertain. We estimate a diurnal Markov-process representation of how Germany’s residual load changed from hour to hour and design a simple dynamic stochastic electricity system model with non-intermittent generation technologies and storage. We derive the optimal storage, generator output and capacity levels. If storage capacity replaces some generation capacity, the optimal storage strategy must balance arbitrage (between periods of high and low marginal cost) against precautionary storage to ensure energy is available throughout a long peak in net demand. Solvingthe model numerically under uncertainty (only the transition probabilities to future loads are known), we compare the results to perfect foresight findings. The latter over-estimate the cost-saving potential of energy storage by 27%, as storage can take up arbitrage opportunities that would not be chosen if there was a need for precautionary storage.
Ward K, Green RJ, Staffell I, 2019, Getting prices right in structural electricity market models, Energy Policy, Vol: 129, Pages: 1190-1206, ISSN: 0301-4215
Electricity market models are widely employed to study the role, impacts and economic viability of new technologies. Sources of arbitrage, such as storage and transmission, are increasingly seen as essential for integrating higher shares of variable renewables. Understanding their operation and business case requires models which accurately represent time-series of wholesale electricity prices.We show that the prevailing assumption of generators bidding short-run marginal cost, such as in the merit order stack, substantially underestimates the spread and volatility of hourly wholesale prices. To compound this, the lack of transparent outputs from previous electricitymarket modelling studies makes it impossible to scrutinise the prevailing methods or provide a detailed inter-comparison.We demonstrate a simple modification to the short-run marginal cost approach that delivers improved variability in modelled prices: allowing generators to make a spread of bids, below cost for their first megawatts of capacity, above for their last. Using this model we demonstrate the impact of price variability on the operation and profitability of storage, highlighting the urgent need for greater awareness of this aspect of market model performance.
Geske J, Green R, Staffell I, 2019, Elecxit: The cost of bilaterally uncoupling british-EU electricity trade, Publisher: Energy Policy Research Group, University of Cambridge
The UK’s withdrawal from the European Union could mean that it leaves the EU Single Market for electricity (Elecxit). This paper develops methods to study the longer-term consequences of this electricity market disintegration, and in particular the end of market coupling. Before European electricity markets were coupled, different market closing times forced traders to commit to cross-border trading volumes based on anticipated market prices. Interconnector capacity was often under-used, and power sometimes flowed from high- to low-price areas. A model of these market frictions is developed, empirically verified on 2009 data (before market coupling) and applied to estimate the costs of market uncoupling in 2030. A less efficient market and the abandonment of some planned interconnectors would raise generation costs by €560m a year (1.5%) compared to remaining in the Single Electricity Market. Sixty percent (€300m) of these welfare losses occur in Great Britain.
Sandys L, Hardy J, Rhodes A, et al., 2018, Redesigning Regulation: Powering from the future, Redesigning Regulation: Powering from the future, London, UK
The electricity sector is already going through unprecedented change, and new solutions to new challenges are ready to shape a transformed sector with new opportunities and new risks. The question is whether incremental change provided through issue specific changes, derogations or technology specific responses will unlock the new consumer and system advantages. Or should we recognise that the innovation in all parts of the system is totally transformative and changes the fundamentals of what the market is and what we need to regulate?Regulators and policy makers are currently sitting in the middle addressing the legacy concerns while looking hesitantly at the future. They have a choice – whether to try to squeeze the transformed system into the architecture of the past or to embark on a ‘managed’ revolution to embrace the new structure of the future of electricity.This report proposes regulatory actions needed to meet the challenges and opportunities of a transformed energy system – reimagining the market design, refocusing regulation, opening up consumer choice, and unlocking the power of supply-chain pressures while shaping a new ‘retailer’ market. In addition, it proposes much greater use of energy-system data, and a recalibration of security of supply to drive greater efficiencies and unlock demand reduction.
Jansen M, Staffell I, Green R, 2018, Daily marginal CO2Emissions eeductions from wind and solar generation, 15th Conference on the European Energy Market (EEM), Publisher: IEEE, ISSN: 2165-4093
This paper estimates the half-hourly and daily CO 2 emissions from electricity generation in Britain, and the influence that wind and solar output has on these. Emissions are inferred from the output of individual plants and their expected efficiency, accounting for the penalty of part-loading thermal generators. Empirical Willans lines are created for typical coal, oil and combined-cycle gas generators from the US CEMS database, giving the first fully-empirical treatment of the British power system. We compare regressions of half-hourly and daily emissions to estimate the impact of plant start-ups, which may not occur in the specific hours when wind and solar output drops, and thus may be mis-identified in half-hourly regressions. Our preliminary findings show that dynamic plant efficiency may reduce the carbon savings from wind by 5-12% and for solar by 0-6%. The effect is strengthening with increasing penetration.
Vorushylo I, Keatley P, Shah N, et al., 2018, How heat pumps and thermal energy storage can be used to manage wind power: a study of Ireland, Energy, Vol: 157, Pages: 539-549, ISSN: 0360-5442
Although energy for heating and cooling represents the largest proportion of demand, little progress towards meeting environmental targets has been achieved in these sectors. The recent rapid progress in integrating renewable energy into the electricity sector however, can help in decarbonising heat by electrification. This paper investigates the impacts and benefits of heat electrification in a wind dominated market by considering two options; with heat pumps, and with direct electric heating, both operated with energy storage. The Irish all-island electricity market is used as a case study. Modelling results reveal the significant potential of heat pump electrification, delivering at least two and three times less carbon emissions respectively, when compared with conventional options such as gas or oil for 20% of domestic sector of the All Ireland market. Heat electrification using direct, resistive heating systems is found to be the most carbon intensive method. Energy storage systems combined with heat pumps could deliver potentially significant benefits in terms of emissions reductions, efficient market operation and mitigating the impacts of variable renewable energy on baseload generation. The main barrier to heat electrification in the all island market is the absence of appropriate policy measures to support relevant technologies.
Green R, Jansen M, Staffell I, et al., 2018, Electricity, Wind and Carbon: What determines the emissions savings from wind power in Great Britain?, Conference on Renewable Energy and Electricity Markets
Sandys L, Hardy J, Green R, 2017, Reshaping Regulation: Powering from the Future, Reshaping Regulation: Powering from the Future, London, UK
The UK has a global reputation for being at the forefront of energy regulation. This report aims to welcome the dynamism, opportunities and transformation that our energy sector can achieve through a new set of regulatory principles that embraces the changing nature of energy, technology and primarily consumers. It does not examine incremental change or how to manage the “transition”. Instead, the report authors have designed their work around the destination rather than the journey - planning from the future. Instead of starting with the current system or incumbent thinking, they aim to shape the new system from a blank sheet of paper, taking into consideration the needs of the consumer through a set of guiding principles. The report recommendations require a culture shift that some of the existing players in the energy market will embrace, but others will resist. Some companies will change their culture, their recruitment and their business models; others will hold on to their existing models for dear life. This piece of work aims to complement the important and persuasive work being undertaken elsewhere, such as the Energy System Catapult’s Future Power System Architecture project, the Energy Networks Association Open Networks project and the various Ofgem projects, including its work on Insights for Future Regulation.
Green RJ, 2017, The Future of Electricity: A Market with Marginal Costs of Zero?, International Association for Energy Economics 15th European Conference
Geske J, Green R, Chen Q, et al., 2017, Smart Demand Side Management: Storing energy or storing consumption - it is not the same!, 14th International Conference on the European Energy Market (EEM), Publisher: IEEE, ISSN: 2165-4077
Green RJ, 2017, Electricity, Wind and Carbon, Supergen Wind General Assembly, April 2017
Presentation at the Supergen Wind General Assembly, April 2017
Green RJ, 2017, Renewables, storage and the new electricity landscape, 6th ELAEE Conference
Green RJ, Staffell IL, 2017, “Prosumage” and the British electricity market, Economics of Energy and Environmental Policy, Vol: 6, Pages: 33-49, ISSN: 2160-5882
Domestic electricity consumers with PV panels have become known as “prosumers”; some of them also have energy storage and we have named the combination “prosumage”. The challenges of renewable intermittency could be offset by storing power, and many engineering studies consider the role and value of storage which is properly integrated into the ‘smart grid’. Such a system with holistic optimal control may fail to materialise for regulatory, economic, or behavioural reasons. We therefore model the impact of naïve prosumage: households which use storage only to maximise self-consumption of PV, with no consideration of the wider system. We find it is neither economicfor arbitrage nor particularly beneficial for shaving peaks and filling troughs in national net demand. The extreme case of renewable self-sufficiency, becoming completely independent of the grid, is still prohibitively expensive in Britain and Germany, and even in a country like Spain with a much better solar resource.
Green RJ, 2017, Evidence, and Supplementary Evidence, submitted to the House of Lords Economic Affairs Committee inquiry on The Economics of UK Energy Policy
This contains two memoranda of evidence submitted to the committee, before and after I gave oral evidence in October 2016
Green RJ, Pudjianto D, Staffell I, et al., 2016, Market Design for Long-Distance Trade in Renewable Electricity, Energy Journal, Vol: 37, Pages: 5-22, ISSN: 0195-6574
While the 2009 EU Renewables Directive allows countries to purchase some of their obligation fromanother member state, no country has yet done so, preferring to invest locally even where load factors arevery low. If countries specialised in renewables most suited to their own endowments and expandedinternational trade, we estimate that system costs in 2030 could be reduced by 5%, or €15 billion a year,after allowing for the costs of extra transmission capacity, peaking generation and balancing operationsneeded to maintain electrical feasibility.Significant barriers must be overcome to unlock these savings. Countries that produce more renewablepower should be compensated for the extra cost through tradable certificates, while those that buy fromabroad will want to know that the power can be imported when needed. Financial Transmission Rightscould offer companies investing abroad confidence that the power can be delivered to their consumers.They would hedge short-term fluctuations in prices and operate much more flexibly than the existingsystem of physical point-to-point rights on interconnectors. Using FTRs to generate revenue fortransmission expansion could produce perverse incentives to under-invest and raise their prices, sorevenues from FTRs should instead be offset against payments under the existing ENTSO-Ecompensation scheme for transit flows. FTRs could also facilitate cross-border participation in capacitymarkets, which are likely to be needed to reduce risks for the extra peaking plants required.
Green RJ, 2016, Storage in the energy market, Energy Transitions 2016
Geske J, Green R, 2016, Optimal storage investment and management under uncertainty It is costly to avoid outages!, 8th IEEE International Power Electronics and Motion Control Conference (IPEMC-ECCE Asia), Publisher: IEEE, Pages: 524-529
Subject of this analysis is to show how storage is operated optimally under renewable and load uncertainty in the electricity system context. We estimate a homogeneous Markov Chain representation of the residual load in Germany in 2014 on an hourly basis and design a very simple dynamic stochastic electricity system model with non-intermittent generation techno-logies and storage. We compare these results to perfect foresight findings and identify a significant over estimation of the storage potential under perfect foresight.
Geske J, Green R, 2016, Optimal storage investment and management under uncertainty, 2016 IEEE 8th International Power Electronics and Motion Control Conference, IPEMC-ECCE Asia 2016, Pages: 524-529
© 2016 IEEE. Subject of this analysis is to show how storage is operated optimally under renewable and load uncertainty in the electricity system context. We estimate a homogeneous Markov Chain representation of the residual load in Germany in 2014 on an hourly basis and design a very simple dynamic stochastic electricity system model with non-intermittent generation technologies and storage. We compare these results to perfect foresight findings and identify a significant over estimation of the storage potential under perfect foresight.
Green RJ, Staffell, 2016, Electricity in Europe: exiting fossil fuels?, Oxford Review of Economic Policy, Vol: 32, Pages: 282-303, ISSN: 1460-2121
There are many options for generating electricity with low carbon emissions, and the electrification of heatand transport can decarbonise energy use across the economy. This places the power sector at the forefrontof any move away from fossil fuels, even though fossil-fuelled generators are more dependable and flexiblethan nuclear reactors or intermittent renewables, and vital for the second-by-second balancing of supply anddemand. Renewables tend to supplement, rather than replace, fossil capacity, although output from fossilfuelledstations will fall and some will have to retire to avoid depressing wholesale power prices. At times oflow demand and high renewable output prices can turn negative, but electricity storage, long-distanceinterconnection and flexible demand may develop to absorb any excess generation. Simulations for GreatBritain show that while coal may be eliminated from the mix within a decade, natural gas has a long-termrole in stations with or without carbon capture and storage, depending on its cost and the price of carbon.
Green RJ, 2015, Markets, Governments and Renewable Energy, Renewable Energy Finance Powering the Future, Editors: Donovan, Publisher: Imperial College Press, Pages: 105-129, ISBN: 9781783267767
But now clean energy is the safe bet for investors, as is argued in Renewable Energy Finance: Powering the Future, edited by Dr Charles Donovan, Principal Teaching Fellow at Imperial College Business School.With a foreword by Lord Brown and ...
Green RJ, staffell I, Hamilton IG, 2015, The residential energy sector, Domestic Microgeneration Renewable and Distributed Energy Technologies, Policies and Economics, Editors: Staffell, Brandon, Hawkes, Brett, Publisher: Routledge, Pages: 18-48, ISBN: 9781317448853
1 Overview Whilst the primary use of microgeneration is to service the energy demands of a building or a community, microgeneration technologies could also play a role in wider energy networks such as communal heating schemes or (more ...
Staffell I, Green R, 2015, Is There Still Merit in the Merit Order Stack? The Impact of Dynamic Constraints on Optimal Plant Mix, IEEE Transactions on Power Systems, Vol: 31, Pages: 43-53, ISSN: 1558-0679
The merit order stack is used to tackle a wide variety of problems involving electricity dispatch. The simplification it relies on is to neglect dynamic issues such as the cost of starting stations. This leads the merit order stack to give a poor representation of the hourly pattern of prices and under-estimate the optimal level of investment in both peaking and inflexible baseload generators, and thus their run-times by up to 30%. We describe a simple method for incorporating start-up costs using a single equation derived from the load curve and station costs. The technique is demonstrated on the British electricity system in 2010 to test its performance against actual outturn, and in a 2020 scenario with increased wind capacity where it is compared to a dynamic unit-commitment scheduler. Our modification yields a better representation of electricity prices and reduces the errors in capacity investment by a factor of two.
Green RJ, Strbac, 2015, Storage in the energy market, IEEE Power and Energy Society General Meeting 2015
Green RJ, Staffell I, 2015, Evidence on Wind Farm Performance Decline in the UK, Evidence on Wind Farm Performance Decline in the UK
Onshore wind farms in the UK have aged at about the same rate as other kinds ofpower station. The average wind farm has an annual load factor of about 28% whenfirst commissioned, which declines by about 0.4 percentage points per year. After 15years, the load factor would have fallen to 23%. This ageing does not appear to havemade developers replace their farms early. Forty out of the first forty-five windfarms commissioned in the UK were still operating at this age; four had beenrepowered. Taking this deterioration into account raises the levelised cost ofelectricity by around 9% over a 24-year lifespan, discounting at 10 per cent a year.This is a summary of the peer-reviewed paper “How does wind farm performancedecline with age?” published in Renewable Energy, vol. 65, pp 775-786, which isavailable to download from http://tinyurl.com/wind-decline.
Green RJ, Staffell I, 2015, Storage in the electricity market, International Ruhr Energy Conference 2015
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