97 results found
Biancardi A, Di Castelnuovo M, Staffell I, 2021, A framework to evaluate how European Transmission System Operators approach innovation, Energy Policy, Vol: 158, Pages: 112555-112555, ISSN: 0301-4215
Balcombe P, Staffell I, Kerdan IG, et al., 2021, How can LNG-fuelled ships meet decarbonisation targets? An environmental and economic analysis, Energy, Vol: 227, Pages: 1-12, ISSN: 0360-5442
International shipping faces strong challenges with new legally binding air quality regulations and a 50% decarbonisation target by 2050. Liquefied natural gas (LNG) is a widely used alternative to liquid fossil fuels, but methane emissions reduce its overall climate benefit. This study utilises new emissions measurements and supply-chain data to conduct a comprehensive environmental life cycle and cost assessment of LNG as a shipping fuel, compared to heavy fuel oil (HFO), marine diesel oil (MDO), methanol and prospective renewable fuels (hydrogen, ammonia, biogas and biomethanol). LNG gives improved air quality impacts, reduced fuel costs and moderate climate benefits compared to liquid fossil fuels, but with large variation across different LNG engine types. Methane slip from some engines is unacceptably high, whereas the best performing LNG engine offers up to 28% reduction in global warming potential when combined with the best-case LNG supply chain. Total methane emissions must be reduced to 0.8–1.6% to ensure climate benefit is realised across all timescales compared to current liquid fuels. However, it is no longer acceptable to merely match incumbent fuels; progress must be made towards decarbonisation targets. With methane emissions reduced to 0.5% of throughput, energy efficiency must increase 35% to meet a 50% decarbonisation target.
Auger T, Truby J, Balcombe P, et al., 2021, The future of coal investment, trade, and stranded assets, Joule, Vol: 5, Pages: 1462-1484, ISSN: 2542-4351
Coal is at a crossroads, with divestment and phase-out in the West countered by the surging growth throughout Asia. Global energy scenarios suggest that coal consumption could halve over the next decade, but the business and geopolitical implications of this profound shift remain underexplored. We investigate coal markets to 2040 using a perfect competition techno-economic model. In a well-below-2°C scenario, Europe, North America, and Australia suffer from over-capacity, with one-third of today’s mines becoming stranded assets. New mines are needed to offset retirements, but a new commodity cycle in the 2030s can be avoided. Coal prices decline as only the most competitive mines survive, and trade volumes fall to give more insular national markets. Regions stand to gain or lose tens of billions of dollars per year from reducing import bills or export revenues. Understanding and preparing for these changes could ease the transition away from coal following 150 years of dominance.
Halttunen K, Slade R, Staffell I, 2021, The future of the oil industry in a "Well Below 2 Degree" world: a company-level agent-based simulation, Energy, COVID, and Climate Change, 1st IAEE Online Conference, Publisher: IAEE
Johnson NJ, Gross R, Staffell I, 2021, Stabilisation wedges: measuring progress towards transforming the global energy and land use systems, Environmental Research Letters, Vol: 16, ISSN: 1748-9326
15 years ago, Pacala and Socolow argued that global carbon emissions could be stabilised by mid-century using a portfolio of existing mitigation strategies. We assess historic progress for each of their proposed mitigation strategies and convert this into the unit of 'wedges'. We show that the world is on track to achieve 1.5 ± 0.9 wedges relative to seven required to stabilise emissions, or 14 required to achieve net-zero emissions by mid-century. Substantial progress has been made in some domains that are not widely recognised (improving vehicle efficiency and declining vehicle use); yet this is tempered by negligible or even negative progress in many others (particularly tropical tree cover loss in Asia and Africa). By representing global decarbonisation efforts using the conceptually simple unit of wedges, this study helps a broader audience to understand progress to date and engage with the need for much greater effort over the coming decades.
Mehlig D, ApSimon H, Staffell I, 2021, The impact of the UK’s COVID-19 lockdowns on energy demand and emissions, Environmental Research Letters, Vol: 16, Pages: 1-9, ISSN: 1748-9326
Around the world, efforts to contain the COVID-19 pandemic have profoundly changed human activity, which may have improved air quality and reduced greenhouse gas emissions. We investigated the impact of the pandemic on energy demand and subsequent emissions from electricity and gas throughout 2020 in the UK. The daily pattern of electricity demand changed in both lockdowns, with weekday demand shifting to that of a typical pre-pandemic weekend. Energy demand in 2020 was modelled to reveal the impact of the weather and the pandemic. The first lockdown reduced demand by 15.6% for electricity and 12.0% for commercial gas, whereas the second lockdown produced reductions less than half. Domestic gas demand did not change during the first lockdown, but increased by 6.1% in the second, likely due to increased domestic heat demand. The changes in demand for gas resulted in little change to overall gas consumption emissions during the pandemic. For electricity, large emission reductions occurred during the two lockdowns: up to 22% for CO2, 47% for NO¬x ¬, and 29% for PM2.5. Yet, the largest CO2 emission reduction for electricity in 2020 (25%) occurred before the pandemic, which happened during a warm and stormy spell with exceptional wind generation. These observations suggest that future similar changes in activity may result in little change for gas demand and emissions. For electricity, emission reductions through changes in energy demand are made possible by the generation mix. To enable further emission reductions in the future, the generation mix should continue to decarbonise. This will yield emission reductions in both times of lowered energy demand, but more importantly, during times of high renewable output.
Gholami MB, Poletti S, Staffell I, 2021, Wind, rain, fire and sun: Towards zero carbon electricity for New Zealand, Energy Policy, Vol: 150, Pages: 112109-112109, ISSN: 0301-4215
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.
Saint-Drenan Y-M, Besseau R, Jansen M, et al., 2020, A parametric model for wind turbine power curves incorporating environmental conditions, Renewable Energy, Vol: 157, Pages: 754-768, ISSN: 0960-1481
A wind turbine’s power curve relates its power production to the wind speed it experiences. The typical shape of a power curve is well known and has been studied extensively. However, power curves of individual turbine models can vary widely from one another. This is due to both the technical features of the turbine (power density, cut-in and cut-out speeds, limits on rotational speed and aerodynamic efficiency), and environmental factors (turbulence intensity, air density, wind shear and wind veer). Data on individual power curves are often proprietary and only available through commercial databases. We therefore develop an open-source model for pitch regulated horizontal axis wind turbine which can generate the power curve of any turbine, adapted to the specific conditions of any site. This can employ one of six parametric models advanced in the literature, and accounts for the eleven variables mentioned above. The model is described, the impact of each technical and environmental feature is examined, and it is then validated against the manufacturer power curves of 91 turbine models. Versions of the model are made available in MATLAB, R and Python code for the community.
Jansen M, Staffell I, Kitzing L, et al., 2020, Offshore wind competitiveness in mature markets without subsidy, Nature Energy, Vol: 5, Pages: 614-622, ISSN: 2058-7546
Offshore wind energy development has been driven by government support schemes; however, recent cost reductions raise the prospect of offshore wind power becoming cheaper than conventional power generation. Many countries use auctions to provide financial support; however, differences in auction design make their results difficult to compare. Here, we harmonize the auction results from five countries based on their design features, showing that offshore wind power generation can be considered commercially competitive in mature markets. Between 2015 and 2019, the price paid for power from offshore wind farms across northern Europe fell by 11.9 ± 1.6% per year. The bids received in 2019 translate to an average price of €51 ± 3 MWh−1, and substantially different auction designs have received comparably low bids. The level of subsidy implied by the auction results depends on future power prices; however, projects in Germany and the Netherlands are already subsidy-free, and it appears likely that in 2019 the United Kingdom will have auctioned the world’s first negative-subsidy offshore wind farm.
Kozarcanin S, Hanna R, Staffell I, et al., 2020, Impact of climate change on the cost-optimal mix of decentralised heat pump and gas boiler technologies in Europe, Energy Policy, Vol: 140, Pages: 1-13, ISSN: 0301-4215
Residential demands for space heating and hot water account for 31% of the total European energy demand. Space heating is highly dependent on ambient conditions and susceptible to climate change. We adopt a techno-economic standpoint and assess the impact of climate change on decentralised heating demand and the cost-optimal mix of heat pump and gas boiler technologies. Temperature data with high spatial resolution from nine climate models implementing three Representative Concentration Pathways from IPCC are used to estimate climate induced changes in the European demand side for heating. The demand side is modelled by the proxy of heating-degree days. The supply side is modelled by using a screening curve approach to the economics of heat generation. We find that space heating demand decreases by about 16%, 24% and 42% in low, intermediate and extreme global warming scenarios. When considering historic weather data, we find a heterogeneous mix of technologies are cost-optimal, depending on the heating load factor (number of full-load hours per year). Increasing ambient temperatures toward the end-century improve the economic performance of heat pumps in all concentration pathways. Cost optimal technologies broadly correspond to heat markets and policies in Europe, with some exceptions.
Le Varlet T, Schmidt O, Gambhir A, et al., 2020, Comparative life cycle assessment of lithium-ion battery chemistries for residential storage, Journal of Energy Storage, Vol: 28, ISSN: 2352-152X
Residential storage deployment is expected to grow dramatically over the coming decade. Several lithium-ion chemistries are employed, but the relative environmental impacts of manufacturing them is poorly understood. This study presents a cradle-to-gate life cycle assessment to quantify the environmental impact of five prominent lithium-ion chemistries, based on the specifications of 73 commercially-available battery modules used for residential applications. Three impact categories (global warming potential, cumulative energy demand and mineral resource scarcity) are analysed across two functional units (storage capacity and lifetime energy delivered). Most chemistries have embodied carbon footprints of around 200 kg CO2e per kWh of useable storage capacity, which corresponds to 43–84 g CO2e per kWh of lifetime energy delivered with daily cycling operation. Energy delivered on energy invested is also calculated at values of 2–4, which falls to 0.54–0.66 with the energy for charging included (cf. a round-trip efficiency of 82–89%). Environmental impact depends more on cycling frequency than chemistry choice, and none of the battery chemistries convincingly outperforms the others. Cells only constitute a third to a half of the environmental impact, which is comparable to the inverter. Routes to making residential lithium-ion battery systems more environmentally benign include reducing the reliance on cobalt, nickel and copper, increasing the specific useable energy, developing comprehensive recycling initiatives, and maximising the utilisation (cycle frequency) once in operation.
Vinca A, Parkinson S, Byers E, et al., 2020, The NExus Solutions Tool (NEST) v1.0: an open platform for optimizing multi-scale energy&#8211;water&#8211;land system transformations, Geoscientific Model Development, Vol: 13, Pages: 1095-1121, ISSN: 1991-959X
The energy–water–land nexus represents a critical leverage future policies must draw upon to reduce trade-offs between sustainable development objectives. Yet, existing long-term planning tools do not provide the scope or level of integration across the nexus to unravel important development constraints. Moreover, existing tools and data are not always made openly available or are implemented across disparate modeling platforms that can be difficult to link directly with modern scientific computing tools and databases. In this paper, we present the NExus Solutions Tool (NEST): a new open modeling platform that integrates multi-scale energy–water–land resource optimization with distributed hydrological modeling. The new approach provides insights into the vulnerability of water, energy and land resources to future socioeconomic and climatic change and how multi-sectoral policies, technological solutions and investments can improve the resilience and sustainability of transformation pathways while avoiding counterproductive interactions among sectors. NEST can be applied at different spatial and temporal resolutions, and is designed specifically to tap into the growing body of open-access geospatial data available through national inventories and the Earth system modeling community. A case study analysis of the Indus River basin in south Asia demonstrates the capability of the model to capture important interlinkages across system transformation pathways towards the United Nations' Sustainable Development Goals, including the intersections between local and regional transboundary policies and incremental investment costs from rapidly increasing regional consumption projected over the coming decades.
Vinca A, Parkinson S, Byers E, et al., 2020, The Nexus Solutions Tool (NEST): An open platform for optimizingmulti-scale energy-water-land system transformations, Geoscientific Model Development, ISSN: 1991-959X
<jats:p>Abstract. The energy-water-land nexus represents a critical leverage future policies must draw upon to reduce trade-offs between sustainable development objectives. Yet, existing long-term planning tools do not provide the scope or level of integration across the nexus to unravel important development constraints. Moreover, existing tools and data are not always made openly available or are implemented across disparate modeling platforms that can be difficult to link directly with modern scientific computing tools and databases. In this paper, we present the Nexus Solutions Tool (NEST): a new open modeling platform that integrates multi-scale energy-water-land resource optimization with distributed hydrological modeling. The new approach provides insights into the vulnerability of water, energy and land resources to future socioeconomic and climatic change and how multi-sectoral policies, technological solutions and investments can improve the resilience and sustainability of transformation pathways while avoiding counterproductive interactions among sectors. NEST can be applied at different spatial and temporal resolutions, and is designed specifically to tap into the growing body of open access geospatial data available through national inventories and the earth system modeling community. A case study analysis of the Indus River Basin in South Asia demonstrates the capability of the model to capture important interlinkages across system transformation pathways towards the United Nations' Sustainable Development Goals, including the intersections between local and regional transboundary policies and incremental investment costs from rapidly increasing regional consumption projected over the coming decades. </jats:p>
Gardiner D, Schmidt O, Heptonstall P, et al., 2020, Quantifying the impact of policy on the investment case for residential electricity storage in the UK, Journal of Energy Storage, Vol: 27, ISSN: 2352-152X
Electrical energy storage has a critical role in future energy systems, but deployment is constrained by high costs and barriers to ‘stacking’ multiple revenue streams. We analyse the effects of different policy measures and revenue stacking on the economics of residential electricity storage in the UK. We identify six policy interventions through industry interviews and quantify their impact using a techno-economic model of a 4kWh battery paired with a 4kW solar system. Without policy intervention, residential batteries are not currently financially viable in the UK. Policies that enable access to multiple revenue streams, rather than just maximising PV self-consumption, improve this proposition. Demand Load-Shifting and Peak Shaving respectively increase the net present value per unit of investment cost (NPV/Capex) by 30% and 9% respectively. Given projected reductions in storage costs, stacking these services brings forward the break even date for residential batteries by 9 years to 2024, and increases the effectiveness of policies that reduce upfront costs, suggesting that current policy is correctly focused on enabling revenue stacking. However, additional support is needed to accelerate deployment in the near term. Combining revenue stacking with a subsidy of £250 per kWh or zero-interest loans could make residential storage profitable by 2020.
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.
Bosch J, Staffell I, Hawkes AD, 2019, Global levelised cost of electricity from offshore wind, Energy, Vol: 189, Pages: 116357-116357, ISSN: 0360-5442
There is strong agreement across the energy modelling community that wind energy will be a key route to mitigating carbon emissions in the electricity sector. This paper presents a Geospatial Information System methodology for estimating spatially-resolved levelised cost of electricity for offshore wind, globally. The principal spatial characteristics of capital costs are transmission distance (i.e. the distance to grid connection) and water depth, because of the disparate costs of turbine foundation technologies. High resolution capacity factors are estimated from a bottom-up estimation of global wind speeds calculated from several decades of wind speed data. A technology-rich description of fixed and floating foundation types allows the levelised cost of electricity to be calculated for 1 × 1 km grid cells, relative to location-specific annual energy production, and accounting for exclusion areas, array losses and turbine availability. These data can be used to assess the economically viable offshore wind energy potential, globally and on a country basis, and can serve as inputs to energy systems models.
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.
Kozarcanin S, Andresen GB, Staffell I, 2019, Estimating country-specific space heating threshold temperatures from national gas and electricity consumption data, Energy and Buildings, Vol: 199, Pages: 368-380, ISSN: 0378-7788
Pollet BG, Kocha SS, Staffell I, 2019, Current status of automotive fuel cells for sustainable transport, Current Opinion in Electrochemistry, Vol: 16, Pages: 90-95, ISSN: 2451-9103
Automotive proton-exchange membrane fuel cells (PEMFCs) have finally reached a state of technological readiness where several major automotive companies are commercially leasing and selling fuel cell electric vehicles, including Toyota, Honda, and Hyundai. These now claim vehicle speed and acceleration, refueling time, driving range, and durability that rival conventional internal combustion engines and in most cases outperform battery electric vehicles. The residual challenges and areas of improvement which remain for PEMFCs are performance at high current density, durability, and cost. These are expected to be resolved over the coming decade while hydrogen infrastructure needs to become widely available. Here, we briefly discuss the status of automotive PEMFCs, misconceptions about the barriers that platinum usage creates, and the remaining hurdles for the technology to become broadly accepted and implemented.
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.
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, ISSN: 2542-4351
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.
This data is extracted from the Web of Science and reproduced under a licence from Thomson Reuters. You may not copy or re-distribute this data in whole or in part without the written consent of the Science business of Thomson Reuters.