74 results found
Tranberg B, Corradi O, Lajoie B, et al., 2019, Real-time carbon accounting method for the European electricity markets, Energy Strategy Reviews, Vol: 26, ISSN: 2211-467X
Electricity accounts for 25% of global greenhouse gas emissions. Reducing emissions related to electricity consumption requires accurate measurements readily available to consumers, regulators and investors. In this case study, we propose a new real-time consumption-based accounting approach based on flow tracing. This method traces power flows from producer to consumer thereby representing the underlying physics of the electricity system, in contrast to the traditional input-output models of carbon accounting. With this method we explore the hourly structure of electricity trade across Europe in 2017, and find substantial differences between production and consumption intensities. This emphasizes the importance of considering cross-border flows for increased transparency regarding carbon emission accounting of electricity.
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.
Balcombe P, Brierley J, Lewis C, et al., 2019, How to decarbonise international shipping: Options for fuels, technologies and policies, Energy Conversion and Management, Vol: 182, Pages: 72-88, ISSN: 0196-8904
International shipping provides 80–90% of global trade, but strict environmental regulations around NOX, SOX and greenhouse gas (GHG) emissions are set to cause major technological shifts. The pathway to achieving the international target of 50% GHG reduction by 2050 is unclear, but numerous promising options exist. This study provides a holistic assessment of these options and their combined potential to decarbonise international shipping, from a technology, environmental and policy perspective. Liquefied natural gas (LNG) is reaching mainstream and provides 20–30% CO2 reductions whilst minimising SOX and other emissions. Costs are favourable, but GHG benefits are reduced by methane slip, which varies across engine types. Biofuels, hydrogen, nuclear and carbon capture and storage (CCS) could all decarbonise much further, but each faces significant barriers around their economics, resource potentials and public acceptability. Regarding efficiency measures, considerable fuel and GHG savings could be attained by slow-steaming, ship design changes and utilising renewable resources. There is clearly no single route and a multifaceted response is required for deep decarbonisation. The scale of this challenge is explored by estimating the combined decarbonisation potential of multiple options. Achieving 50% decarbonisation with LNG or electric propulsion would likely require 4 or more complementary efficiency measures to be applied simultaneously. Broadly, larger GHG reductions require stronger policy and may differentiate between short- and long-term approaches. With LNG being economically feasible and offering moderate environmental benefits, this may have short-term promise with minor policy intervention. Longer term, deeper decarbonisation will require strong financial incentives. Lowest-cost policy options should be fuel- or technology-agnostic, internationally applied and will require action now to ensure targets are met by 2050.
Staffell I, Scamman D, Velazquez Abad A, et al., 2019, The role of hydrogen and fuel cells in the global energy system, Energy and Environmental Science, Vol: 12, Pages: 463-491, ISSN: 1754-5692
Hydrogen technologies have experienced cycles of excessive expectations followed by disillusion. Nonetheless, a growing body of evidence suggests these technologies form an attractive option for the deep decarbonisation of global energy systems, and that recent improvements in their cost and performance point towards economic viability as well. This paper is a comprehensive review of the potential role that hydrogen could play in the provision of electricity, heat, industry, transport and energy storage in a low-carbon energy system, and an assessment of the status of hydrogen in being able to fulfil that potential. The picture that emerges is one of qualified promise: hydrogen is well established in certain niches such as forklift trucks, while mainstream applications are now forthcoming. Hydrogen vehicles are available commercially in several countries, and 225,000 fuel cell home heating systems have been sold. This represents a step change from the situationof only five years ago. This review shows that challenges around cost and performance remain, and considerable improvements are still required for hydrogen to become truly competitive. But such competitiveness in the medium-term future no longer seems anunrealistic prospect, which fully justifies the growing interest and policy support for these technologies around the world.
Schmidt O, Melchior S, Hawkes A, et al., 2019, Projecting the Future Levelized Cost of Electricity Storage Technologies, Joule, Vol: 3, Pages: 81-100
© 2018 Elsevier Inc. The future role of stationary electricity storage is perceived as highly uncertain. One reason is that most studies into the future cost of storage technologies focus on investment cost. An appropriate cost assessment must be based on the application-specific lifetime cost of storing electricity. We determine the levelized cost of storage (LCOS) for 9 technologies in 12 power system applications from 2015 to 2050 based on projected investment cost reductions and current performance parameters. We find that LCOS will reduce by one-third to one-half by 2030 and 2050, respectively, across the modeled applications, with lithium ion likely to become most cost efficient for nearly all stationary applications from 2030. Investments in alternative technologies may prove futile unless significant performance improvements can retain competitiveness with lithium ion. These insights increase transparency around the future competitiveness of electricity storage technologies and can help guide research, policy, and investment activities to ensure cost-efficient deployment.
Ward KR, Staffell IL, 2018, Simulating price-aware electricity storage without linear optimisation, Journal of Energy Storage, Vol: 20, Pages: 78-91, ISSN: 2352-152X
Electricity storage could prove essential for highly-renewable power systems, but the ability to model its operation and impacts is limited with current techniques. Studies based on historic market prices or other fixed price time-series are commonplace, but cannot account for the impacts of storage on prices, and thus over-estimate utilisation and profits. Power systems models which minimise total system cost cannot model the economic dispatch of storage based on market prices, and thus cannot consider large aggregators of storage devices who are not perfectly competitive.We demonstrate new algorithms which calculate the profit-maximising dispatch of storage accounting for its price effects, using simple functional programming. These are technology agnostic, and can consider short-term battery storage through to inter-seasonal chemical storage (e.g. power-to-gas). The models consider both competitive and monopolistic operators, and require 1–10 s to dispatch GWs of storage over one year.Using a case study of the British power system, we show that failure to model price effects leads to material errors in profits and utilisation with capacities above 100 MW in a ∼50 G W system. We simulate up to 10 GW of storage, showing dramatically different outcomes based on ownership. Compared to a perfectly competitive market, a monopolistic owner would restrict storage utilisation by 30% to increase profits by 85%, thus reducing its benefit to society via smoothing demand and output from intermittent renewables by 20%.
Bosch J, Staffell I, Hawkes A, 2018, Temporally explicit and spatially resolved global offshore wind energy potentials, Energy, Vol: 163, Pages: 766-781, ISSN: 0360-5442
Several influential energy systems models (ESMs) indicate that renewable energy must supply a large share of the world's electricity to limit global temperature increases to 1.5 °C. To better represent the costs and other implications of such a transition, it is important that ESMs can realistically characterise the technical and economic potential of renewable energy resources. This paper presents a Geospatial Information System methodology for estimating the global offshore wind energy potential, i.e. the terawatt hour per year (TWh/yr) production potential of wind farms, assuming capacity could be built across the viable offshore area of each country. A bottom-up approach characterises the capacity factors of offshore wind farms by estimating the available wind power from high resolution global wind speed data sets. Temporal phenomena are retained by binning hourly wind speeds into 32 time slices per year considering the wind resource across several decades. For 157 countries with a viable offshore wind potential, electricity generation potential is produced in tranches according to the distance to grid connection, water depth and average annual capacity factor. These data can be used as inputs to ESMs and to assess the economically viable offshore wind energy potential, on a global or per-country basis.
Collins S, Deane P, Ó Gallachóir B, et al., 2018, Impacts of Inter-annual Wind and Solar Variations on the European Power System, Joule, Vol: 2, Pages: 2076-2090, ISSN: 2542-4351
Weather-dependent renewable energy resources are playing a key role in decarbonizing electricity. There is a growing body of analysis on the impacts of wind and solar variability on power system operation. Existing studies tend to use a single or typical year of generation data, which overlooks the substantial year-to-year fluctuation in weather, or to only consider variation in the meteorological inputs, which overlooks the complex response of an interconnected power system. Here, we address these gaps by combining detailed continent-wide modeling of Europe's future power system with 30 years of historical weather data. The most representative single years are 1989 and 2012, but using multiple years reveals a 5-fold increase in Europe's inter-annual variability of CO2 emissions and total generation costs from 2015 to 2030. We also find that several metrics generalize to linear functions of variable renewable penetration: CO2 emissions, curtailment of renewables, wholesale prices, and total system costs.
Heuberger CF, Rubin ES, Staffell L, et al., 2018, Power capacity expansion planning considering endogenous technology cost learning (vol 204, pg 831, 2017), APPLIED ENERGY, Vol: 220, Pages: 974-974, ISSN: 0306-2619
Heuberger CF, Staffell I, Shah N, et al., 2018, Impact of myopic decision-making and disruptive events in power systems planning, Nature Energy, Vol: 3, Pages: 634-640, ISSN: 1520-8524
The delayed deployment of low-carbon energy technologies is impeding energy system decarbonization. The continuing debate about the cost-competitiveness of low-carbon technologies has led to a strategy of waiting for a ‘unicorn technology’ to appear. Here, we show that myopic strategies that rely on the eventual manifestation of a unicorn technology result in either an oversized and underutilized power system when decarbonization objectives are achieved, or one that is far from being decarbonized, even if the unicorn technology becomes available. Under perfect foresight, disruptive technology innovation can reduce total system cost by 13%. However, a strategy of waiting for a unicorn technology that never appears could result in 61% higher cumulative total system cost by mid-century compared to deploying currently available low-carbon technologies early on.
Joos M, Staffell IL, 2018, Short-term integration costs of variable renewable energy: Wind curtailment and balancing in Britain and Germany, Renewable and Sustainable Energy Reviews, Vol: 86, Pages: 45-65, ISSN: 1364-0321
Britain and Germany saw unprecedented growth of variable renewable energy (VRE) in the last decade. Many studies suggest this will significantly raise short-term power system operation costs for balancing and congestion management. We review the actual development of these costs, their allocation and policy implications in both countries.Since 2010, system operation costs have increased by 62% in Britain (with a five-fold increase in VRE capacity) and remained comparable in Germany (with capacity doubling). Within this, balancing costs stayed level in Britain (–4%) and decreased substantially in Germany (–72%), whilst congestion management costs have grown 74% in Britain and 14-fold in Germany. Curtailment costs vary widely from year to year, and should fall strongly when ongoing and planned grid upgrades are completed. Curtailment rates for wind farms have risen to 4–5% in Germany and 5–6% in Britain (0–1% for offshore and 15–16% for onshore Scottish farms).Policy debates regarding the balancing system are similar in both countries, focussing on strengthening imbalance price signals and the extent that VRE generators bear the integration costs they cause. Both countries can learn from each other's balancing market and imbalance settlement designs. Britain should reform its balancing markets to be more transparent, competitive and open to new providers (especially VRE generators). Shorter trading intervals and gate closure would both require and enable market participants (including VRE) to take more responsibility for balancing. Germany should consider a reserve energy market and move to marginal imbalance pricing.
Staffell IL, Wilson IAG, 2018, Rapid fuel switching from coal to natural gas through effective carbon pricing, Nature Energy, Vol: 3, Pages: 365-372, ISSN: 1520-8524
Great Britain’s overall carbon emissions fell by 6% in 2016, due to cleaner electricity production. This was not due to a surge in low-carbon nuclear or renewable sources; instead it was the much-overlooked impact of fuel switching from coal to natural gas generation. This Perspective considers the enabling conditions in Great Britain and the potential for rapid fuel switching in other coal-reliant countries. We find that spare generation and fuel supply-chain capacity must already exist for fuel switching to deliver rapid carbon savings, and to avoid further high-carbon infrastructure lock-in. More important is the political will to alter the marketplace and incentivize this switch, for example, through a stable and strong carbon price. With the right incentives, fuel switching in the power sector could rapidly achieve on the order of 1 GtCO2 saving per year worldwide (3% of global emissions), buying precious time to slow the growth in cumulative carbon emissions.
Pfenninger S, Hirth L, Schlecht I, et al., 2017, Opening the black box of energy modelling: Strategies and lessons learned, Energy Strategy Reviews, Vol: 19, Pages: 63-71, ISSN: 2211-467X
The global energy system is undergoing a major transition, and in energy planning and decision-making across governments, industry and academia, models play a crucial role. Because of their policy relevance and contested nature, the transparency and open availability of energy models and data are of particular importance. Here we provide a practical how-to guide based on the collective experience of members of the Open Energy Modelling Initiative (Openmod). We discuss key steps to consider when opening code and data, including determining intellectual property ownership, choosing a licence and appropriate modelling languages, distributing code and data, and providing support and building communities. After illustrating these decisions with examples and lessons learned from the community, we conclude that even though individual researchers' choices are important, institutional changes are still also necessary for more openness and transparency in energy research.
Staffell IL, Pfenninger S, 2017, The increasing impact of weather on electricity supply and demand, Energy, Vol: 145, Pages: 65-78, ISSN: 0360-5442
Wind and solar power have experienced rapid cost declines and are being deployed at scale. However, their output variability remains a key problem for managing electricity systems, and the implications of multi-day to multi-year variability are still poorly understood. As other energy-using sectors are electrified, the shape and variability of electricity demand will also change. We develop an open framework for quantifying the impacts of weather on electricity supply and demand using the Renewables.ninja and DESSTINEE models. We demonstrate this using a case study of Britain using National Grid's Two Degrees scenario forwards to 2030.We find the British electricity system is rapidly moving into unprecedented territory, with peak demand rising above 70 GW due to electric heating, and intermittent renewable output exceeding demand as early as 2021. Hourly ramp-rates widen by 50% and year-to-year variability increases by 80%, showing why future power system studies must consider multiple years of data, and the influence of weather on both supply and demand. Our framework is globally applicable, and allows detailed scenarios of hourly electricity supply and demand to be explored using only limited input data such as annual quantities from government scenarios or broader energy systems models.
Schmidt O, Gambhir A, Staffell IL, et al., 2017, Future cost and performance of water electrolysis: An expert elicitation study, International Journal of Hydrogen Energy, Vol: 42, Pages: 30470-30492, ISSN: 0360-3199
The need for energy storage to balance intermittent and inflexible electricity supply with demand is driving interest in conversion of renewable electricity via electrolysis into a storable gas. But, high capital cost and uncertainty regarding future cost and performance improvements are barriers to investment in water electrolysis. Expert elicitations can support decision-making when data are sparse and their future development uncertain. Therefore, this study presents expert views on future capital cost, lifetime and efficiency for three electrolysis technologies: alkaline (AEC), proton exchange membrane (PEMEC) and solid oxide electrolysis cell (SOEC). Experts estimate that increased R&D funding can reduce capital costs by 0–24%, while production scale-up alone has an impact of 17–30%. System lifetimes may converge at around 60,000–90,000 h and efficiency improvements will be negligible. In addition to innovations on the cell-level, experts highlight improved production methods to automate manufacturing and produce higher quality components. Research into SOECs with lower electrode polarisation resistance or zero-gap AECs could undermine the projected dominance of PEMEC systems. This study thereby reduces barriers to investment in water electrolysis and shows how expert elicitations can help guide near-term investment, policy and research efforts to support the development of electrolysis for low-carbon energy systems.
Heuberger CF, Rubin ES, Staffell I, et al., 2017, Power Generation Expansion Considering Endogenous Technology Cost Learning, 27th European Symposium on Computer Aided Process Engineering, Publisher: Elsevier
We present a mixed-integer linear formulation of a long-term power generation capacityexpansion problem including endogenous learning of technology investment cost. Weconsider a national-scale power system composed of up to 2000 units of 15 differentpower supply technologies, including international interconnectors for electricity importand export, and grid-level energy storage. We reformulate the non-convex learning curvemodel into a piecewise linear representation of the cumulative investment cost as a functionof cumulative installed capacity. The model is applied to a power system representativeof Great Britain for the years 2015 to 2050. We find that the consideration oftechnology cost learning rate influences the optimal capacity expansion and has systemicimplications on the profitability of the power units.
Heuberger C, Staffell I, Shah N, et al., 2017, An MILP modeling approach to systemic energy technology valuation in the 21st Century energy system, 13th International Conference on Greenhouse Gas Control Technologies, Publisher: Elsevier, Pages: 6358-6365, ISSN: 1876-6102
New cannot be measured with old. The transformation of the electricity system from a network of fossil-based dispatchable power plants to one with large amounts of intermittent renewable power generation, flexible loads and markets, requires a concurrent development of new evaluation tools and metrics. The focus of this research is to investigate the value of power technologies in order to support decision making on optimal power system design and operation. Technology valuation metrics need to consider the complexity and interdependency of environmental and security objectives, rather than focusing on individual cost-competitiveness of technologies outside of the power system. We present the System Value as a new technology valuation metric, based on a mixed-integer linear program (MILP) formulation of a national-scale electricity system. The Electricity System Optimization model is able to capture detailed technical operation of the individual power plants as well as environmental and security requirements on the system level. We present a case study on the System Value of onshore wind power plants in comparison with Carbon Capture and Storage (CCS) equipped gas-fired power plants in a 2035 UK electricity system. Under the given emission constraints, the deployment of both technologies reduce total system cost of electricity generation. In the case of CCS-equipped power plants the reductions in total system cost are 2 to 5 times higher than for the deployment of onshore wind capacity.
Heuberger C, Staffell I, Shah N, et al., 2017, What is the Value of CCS in the Future Energy System?, 13th International Conference on Greenhouse Gas Control Technologies, Publisher: Elsevier, Pages: 7564-7572, ISSN: 1876-6102
Ambitions to produce electricity at low, zero, or negative carbon emissions are shifting the priorities and appreciation for new types of power generating technologies. Maintaining the balance between security of energy supply, carbon reduction, and electricity system cost during the transition of the electricity system is challenging. Few technology valuation tools consider the presence and interdependency of these three aspects, and nor do they appreciate the difference between firm and intermittent power generation. In this contribution, we present the results of a thought experiment and mathematical model wherein we conduct a systems analyses on the effects of gas-fired power plants equipped with Carbon Capture and Storage (CCS) technology in comparison with onshore wind power plants as main decarbonisation technologies. We find that while wind capacity integration is in its early stages of deployment an economic decarbonisation strategy, it ultimately results in an infrastructurally inefficient system with a required ratio of installed capacity to peak demand of nearly 2.. Due to the intermittent nature of wind power generation, its deployment requires a significant amount of reserve capacity in the form of firm capacity. While the integration of CCS-equipped capacity increases total system cost significantly, this strategy is able to achieve truly low-carbon power generation at 0.04 tCO2/MWh. Via a simple example, this work elucidates how the changing system requirements necessitate a paradigm shift in the value perception of power generation technologies.
Heuberger C, Rubin ES, Staffell I, et al., 2017, Power Capacity Expansion Planning Considering Endogenous Technology Cost Learning, Applied Energy, Vol: 204, Pages: 831-845, ISSN: 0306-2619
We present an power systems optimisation model for national-scale power supply capacity expansion considering endogenous technology cost reduction (ESO-XEL). The mixed-integer linear program minimises total system cost while complying with operational constraints, carbon emission targets, and ancillary service requirements. A data clustering technique and the relaxation of integer scheduling constraints is evaluated and applied to decrease the model solution time. Two cost learning curves for the different power technologies are derived: one assuming local learning effects, the other accounting for global knowledge spill-over. A piece-wise linear formulation allows the integration of the exponential learning curves into the ESO-XEL model. The model is applied to the UK power system in the time frame of 2015 to 2050. The consideration of cost learning effects moves optimal investment timings to earlier planning years and influences the competitiveness of technologies. In addition, the maximum capacity build rate parameter influences the share of power generation significantly; the possibility of rapid capacity build-up is more important for total system cost reduction by 2050 than accounting for technology cost reduction.
Schmidt O, Hawkes A, Gambhir A, et al., 2017, The future cost of electrical energy storage based on experience rates, Nature Energy, Vol: 2
Grams CM, Beerli R, Pfenninger S, et al., 2017, Balancing Europe's wind power output through spatial deployment informed by weather regimes., Nature Climate Change, Vol: 7, Pages: 557-562, ISSN: 1758-678X
As wind and solar power provide a growing share of Europe's electricity1, understanding and accommodating their variability on multiple timescales remains a critical problem. On weekly timescales, variability is related to long-lasting weather conditions, called weather regimes2-5, which can cause lulls with a loss of wind power across neighbouring countries6. Here we show that weather regimes provide a meteorological explanation for multi-day fluctuations in Europe's wind power and can help guide new deployment pathways which minimise this variability. Mean generation during different regimes currently ranges from 22 GW to 44 GW and is expected to triple by 2030 with current planning strategies. However, balancing future wind capacity across regions with contrasting inter-regime behaviour - specifically deploying in the Balkans instead of the North Sea - would almost eliminate these output variations, maintain mean generation, and increase fleet-wide minimum output. Solar photovoltaics could balance low-wind regimes locally, but only by expanding current capacity tenfold. New deployment strategies based on an understanding of continent-scale wind patterns and pan-European collaboration could enable a high share of wind energy whilst minimising the negative impacts of output variability.
Heuberger CF, Staffell I, Shah N, et al., 2017, The changing costs of technology and the optimal investment timing in the power sector
Vijay A, Fouquet N, Staffell IL, et al., 2017, The value of electricity and reserve services in low carbon electricity systems, Applied Energy, Vol: 201, Pages: 111-123, ISSN: 1872-9118
Decarbonising electricity systems is essential for mitigating climate change. Future systems will likely incorporate higher penetrations of intermittent renewable and inflexible nuclear power. This will significantly impact on system operations, particularly the requirements for flexibility in terms of reserves and the cost of such services. This paper estimates the interrelated changes in wholesale electricity and reserve prices using two novel methods. Firstly, it simulates the short run marginal cost of generation using a unit commitment model with post-processing to achieve realistic prices. It also introduces a new reserve price model, which mimics actual operation by first calculating the day ahead schedules and then letting deviations from schedule drive reserve prices. The UK is used as a case study to compare these models with traditional methods from the literature. The model gives good agreement with and historic prices in 2015. In a 2035 scenario, increased renewables penetration reduces mean electricity prices, and leads to price spikes due to expensive plants being brought online briefly to cope with net load variations. Contrary to views previously held in literature, a renewable intensive scenario does not lead to a higher reserve price than a fossil fuel intensive scenario. Demand response technology is shown to offer sizeable economic benefits when maintaining system balance. More broadly, this framework can be used to evaluate the economics of providing reserve services by aggregating decentralised energy resources such as heat pumps, micro-CHP and electric vehicles.
Heuberger C, Staffell I, Shah N, et al., 2017, A systems approach to quantifying the value of power generation and energy storage technologies in future electricity networks, Computers & Chemical Engineering, Vol: 107, Pages: 247-256, ISSN: 0098-1354
A new approach is required to determine a technology's value to the power systems of the 21st century. Conventional cost-based metrics are incapable of accounting for the indirect system costs associated with intermittent electricity generation, in addition to environmental and security constraints. In this work, we formalise a new concept for power generation and storage technology valuation which explicitly accounts for system conditions, integration challenges, and the level of technology penetration. The centrepiece of the system value (SV) concept is a whole electricity systems model on a national scale, which simultaneously determines the ideal power system design and unit-wise operational strategy. It brings typical Process Systems Engineering thinking into the analysis of power systems. The model formulation is a mixed-integer linear optimisation and can be understood as hybrid between a generation expansion and a unit commitment model. We present an analysis of the future UK electricity system and investigate the SV of carbon capture and storage equipped power plants (CCS), onshore wind power plants, and grid-level energy storage capacity. We show how the availability of different low-carbon technologies impact the optimal capacity mix and generation patterns. We find that the SV in the year 2035 of grid-level energy storage is an order of magnitude greater than that of CCS and wind power plants. However, CCS and wind capacity provide a more consistent value to the system as their level of deployment increases. Ultimately, the incremental system value of a power technology is a function of the prevalent system design and constraints.
Bosch J, Staffell, Hawkes AD, 2017, Temporally-explicit and spatially-resolved global onshore wind energy potentials, Energy, Vol: 131, Pages: 207-217, ISSN: 0360-5442
Several influential energy systems models indicate that renewable energy must provide a significant share of the world's electricity to limit global temperature rises to below 2 °C this century. To better represent the costs and other implications of this shift, it is important that these models realistically characterise the technical and economic potential of renewable energy technologies. Towards this goal, this paper presents the first temporally-explicit Geospatial Information System (GIS) methodology to characterise the global onshore wind energy potential with respect to topographical features, land use and environmental constraints. The approach combines the hourly NASA MERRA-2 global wind speed data set with the spatially-resolved DTU Global Wind Atlas. This yields high resolution global capacity factors for onshore wind, binned into seasonal and diurnal time-slices to capture the important temporal variability. For each country, the wind power generation capacity available for various capacity factor ranges is produced, and made freely available to the community. This data set can be used to assess the economically viable wind energy potential on a global or per-country basis, and as an input to various energy systems models.
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.
Staffell IL, 2017, Measuring the progress and impacts of decarbonising British electricity, Energy Policy, Vol: 102, Pages: 463-475, ISSN: 1873-6777
Britain’s ambitious carbon targets require that electricity be immediately and aggressively decarbonised, so it is reassuring to report that electricity sector emissions have fallen 46% in the three years to June 2016, their lowest since 1960. This paper analyses the factors behind this fall and the impacts they are having.The main drivers are: demand falling 1.3% per year due to efficiency gains and mild winters; gas doubling its share to 60% of fossil generation due to the carbon price floor; and the dramatic uptake of wind, solar and biomass which now supply up to 45% of demand. Accounting conventions also play their part: imported electricity and biomass would add 5% and 2% to emissions if they were included.The pace of decarbonisation is impressive, but raises both engineering and economic challenges. Falling peak demand has delayed fears of capacity shortage, but minimum net demand is instead becoming a problem. The headroom between inflexible nuclear and intermittent renewables is rapidly shrinking, with controllable output reaching a minimum of just 5.9 GW as solar output peaked at 7.1 GW. 2015 also saw Britain’s first negative power prices, the highest winter peak prices for six years, and the highest balancing costs.
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.
Pfenninger S, DeCarolis J, Hirth L, et al., 2016, The importance of open data and software: Is energy research lagging behind?, Energy Policy, Vol: 101, Pages: 211-215, ISSN: 0301-4215
Energy policy often builds on insights gained from quantitative energy models and their underlying data. As climate change mitigation and economic concerns drive a sustained transformation of the energy sector, transparent and well-founded analyses are more important than ever. We assert that models and their associated data must be openly available to facilitate higher quality science, greater productivity through less duplicated effort, and a more effective science-policy boundary. There are also valid reasons why data and code are not open: ethical and security concerns, unwanted exposure, additional workload, and institutional or personal inertia. Overall, energy policy research ostensibly lags behind other fields in promoting more open and reproducible science. We take stock of the status quo and propose actionable steps forward for the energy research community to ensure that it can better engage with decision-makers and continues to deliver robust policy advice in a transparent and reproducible way.
Hdidouan D, Staffell IL, 2016, The impact of climate change on the levelised cost of wind energy, Renewable Energy, Vol: 101, Pages: 575-592, ISSN: 1879-0682
Society's dependence on weather systems has broadened to include electricity generation from wind turbines. Climate change is altering energy flows in the atmosphere, which will affect the economic potential of wind power. Changes to wind resources and their upstream impacts on the energy industry have received limited academic attention, despite their risks earning interest from investors.We propose a framework for assessing the impact of climate change on the cost of wind energy, going from the change in hourly wind speed distributions from radiative forcing through to energy output and levelised cost of electricity (LCOE) from wind farms. The paper outlines the proof of concept for this framework, exploring the limitations of global climate models for assessing wind resources, and a novel Weibull transfer function to characterise the climate signal.The framework is demonstrated by considering the UK's wind resources to 2100. Results are mixed: capacity factors increase in some regions and decrease in others, while the year-to-year variation generally increases. This highlights important financial and risk impacts which can be adopted into policy to enhance energy system resilience to the impacts of climate change. We call for greater emphasis to be placed on modelling wind resources in climate science.
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