The impact of climate change on the levelised cost of wind energy

AbstractSociety'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

Audit of the BID3 Pan European Market Model for National Grid

National Grid Electricity Transmission (NGET) has procured a new pan-European electricity market model from Pöyry, BID3, to assist in new requirements for the Integrated Transmission Planning and Regulation Project (ITPR) and Electricity Market Reform (EMR). These require two main distinct functions for the new software: an assessment of within-GB constraint costs; and an assessment of likely interconnector flows

Comparison of Fuel Consumption and Fuel Cell Degradation Using an Optimised Controller

The Energy Management Strategy (EMS) of any hybrid vehicle is responsible for determining the operating state of many components on board the vehicle and therefore has significant effect on the fuel economy, emissions, ageing of components and vehicle drive-ability. It is generally accepted that Stochastic Dynamic Programming (SDP) can be used to produce a near-optimal control strategy provided that an accurate Markov model of the drive-cycle is available, and the cost function used for the optimisation is representative of the true running cost of the vehicle. The vast majority of research in this field focussing solely on the optimisation of the fuel economy, however for a fuel cell hybrid vehicle, the degradation of the fuel cell contributes significantly to the overall running cost of the vehicle, and should therefore be included in calculation of the running cost during the optimisation process. In this work, an optimised controller using SDP is developed for a campus passenger vehicle in order to minimise the lifetime cost of both fuel consumption and fuel cell degradation. The vehicle is then simulated over a number of typical journeys obtained from data logging during its use on the University of Birmingham's campus. It is shown that the expected lifetime cost due to fuel cell degradation massively outweighs the cost of the fuel consumed

Streamlining Energy Transition Scenarios to Key Policy Decisions

Uncertainties surrounding the energy transition often lead modelers to present large sets of scenarios that are challenging for policymakers to interpret and act upon. An alternative approach is to define a few qualitative storylines from stakeholder discussions, which can be affected by biases and infeasibilities. Leveraging decision trees, a popular machine-learning technique, we derive interpretable storylines from many quantitative scenarios and show how the key decisions in the energy transition are interlinked. Specifically, our results demonstrate that choosing a high deployment of renewables and sector coupling makes global decarbonization scenarios robust against uncertainties in climate sensitivity and demand. Also, the energy transition to a fossil-free Europe is primarily determined by choices on the roles of bioenergy, storage, and heat electrification. Our transferrable approach translates vast energy model results into a small set of critical decisions, guiding decision-makers in prioritizing the key factors that will shape the energy transition

Current status of fuel cell based combined heat and power systems forresidential sector

Combined Heat and Power (CHP) is the sequential or simultaneous generation of multiple forms of usefulenergy, usually electrical and thermal, in a single and integrated system. Implementing CHP systems inthe current energy sector may solve energy shortages, climate change and energy conservation issues.This review paper is divided into six sections: thefirst part defines and classifies the types of fuel cellused in CHP systems; the second part discusses the current status of fuel cell CHP (FC-CHP) around theworld and highlights the benefits and drawbacks of CHP systems; the third part focuses on techniques formodelling CHP systems. The fourth section gives a thorough comparison and discussion of the two mainfuel cell technologies used in FC-CHP (PEMFC and SOFC), characterising their technical performance andrecent developments from the major manufacturers. Thefifth section describes all the main componentsof FC-CHP systems and explains the issues connected with their practical application. The last partsummarises the above, and reflects on micro FC-CHP system technology and its future prospects

What is the Value of CCS in the Future Energy System?

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

Cost and thermodynamic analysis of wind-hydrogen production via multi-energy systems

With rising temperatures, extreme weather events, and environmental challenges, there is a strong push towards decarbonization and an emphasis on renewable energy, with wind energy emerging as a key player. The concept of multi-energy systems offers an innovative approach to decarbonization, with the potential to produce hydrogen as one of the output streams, creating another avenue for clean energy production. Hydrogen has significant potential for decarbonizing multiple sectors across buildings, transport, and industries. This paper explores the integration of wind energy and hydrogen production, particularly in areas where clean energy solutions are crucial, such as impoverished villages in Africa. It models three systems: distinct configurations of micro-multi-energy systems that generate electricity, space cooling, hot water, and hydrogen using the thermodynamics and cost approach. System 1 combines a wind turbine, a hydrogen-producing electrolyzer, and a heat pump for cooling and hot water. System 2 integrates this with a biomass-fired reheat-regenerative power cycle to balance out the intermittency of wind power. System 3 incorporates hydrogen production, a solid oxide fuel cell for continuous electricity production, an absorption cooling system for refrigeration, and a heat exchanger for hot water production. These systems are modeled with Engineering Equation Solver, and analyzed based on energy and exergy efficiencies, and on economic metrics like levelized cost of electricity (LCOE), cooling (LCOC), refrigeration (LCOR), and hydrogen (LCOH) under steady-state conditions. A sensitivity analysis of various parameters is presented to assess the change in performance. Systems were optimized using a multi-objective method, with maximizing exergy efficiency and minimizing total product unit cost used as objective functions. The results show that System 1 achieves 79.78 % energy efficiency and 53.94 % exergy efficiency. System 2 achieves efficiencies of 55.26 % and 27.05 % respectively, while System 3 attains 78.73 % and 58.51 % respectively. The levelized costs for micro-multi-energy System 1 are LCOE = 0.04993 $/kWh, LCOC = 0.004722$/kWh, and LCOH = 0.03328 $/kWh. For System 2, these values are 0.03653$/kWh, 0.003743 $/kWh, and 0.03328$/kWh. In the case of System 3, they are 0.03736 $/kWh, 0.004726$/kWh, and 0.03335 $/kWh, and LCOR = 0.03309$/kWh. The results show that the systems modeled here have competitive performance with existing multi-energy systems, powered by other renewables. Integrating these systems will further the sustainable and net zero energy system transition, especially in rural communities.</p

Electric Insights - Quarterly : January to June 2022

After a 12 month hiatus Electric Insights is back, relaunching into one of the most turbulent times in Britain’s electricity system’s history. Our first article focuses on the cost-of-living crisis that is engulfing the nation, and the central role played by energy prices. The wholesale cost of coal and gas have risen to 5-10 times their usual levels over the past two years, and as gas is the largest source of electricity production, the cost of power has shot up too. These price rises have made their way into consumer bills, bringing extreme hardship for households, businesses and industrial consumers alike. The price of fossil fuels over the last three years, relative to their averages from 2010-19 These huge price rises have sparked intense debate about whether energy markets are fundamentally broken, who is profiting from the crisis, and should they be allowed to? Our second article explores whether renewables are being paid more than they should, and the government’s Review of Electricity Market Arrangements which is exploring these topics. These problems are not just limited to the UK: energy prices have been spiralling upwards across the whole of Europe. Several factors are colliding on the continent, including gas shortages in Germany and prolonged nuclear outages in France, meaning Europe’s power systems are facing additional pressures. So, despite British electricity being more expensive than ever, it is cheap in comparison to our European neighbours. Our third article details how Britain has become a net exporter of electricity for the first time in 10 years, with 5% of the electricity generated here sent abroad over the last three months. This comes at a time when Britain’s energy security is becoming a cause for concern. This situation has been complicated further by the extreme weather affecting the UK and much of the world. This summer saw a series of unrelenting heat waves, with temperatures soaring past 40°C for the first time ever, coupled with the driest start to the year ever recorded. We examine how the extreme heat has impacted electricity demand and supply, and the longer-term implications for the power system

The role of natural gas in setting electricity prices in Europe

The EU energy and climate policy revolves around enhancing energy security and affordability, while reducing the environmental impacts of energy use. The European energy transition has been at the centre of debate following the post-pandemic surge in power prices in 2021 and the energy crisis following the 2022 Russia-Ukraine war. Understanding the extent to which electricity prices depend on fossil fuel prices (specifically natural gas) is key to guiding the future of energy policy in Europe. To this end, we quantify the role of fossil-fuelled vs. low-carbon electricity generation in setting wholesale electricity prices in each EU-27 country plus Great Britain (GB) and Norway during 2015-2021. We apply econometric analysis and use sub/hourly power system data to estimate the marginal share of each electricity generation type. The results show that fossil fuel-based power plants set electricity prices in Europe at approximately 58% of the time (natural gas 39%) while generating only 34% of electricity (natural gas 18%) a year. The energy transition has made natural gas the main electricity price setter in Europe, with gas determining electricity prices for more than 80% of the hours in 2021 in several countries such as Belgium, GB, Greece, Italy, and the Netherlands. Hence, Europe’s electricity markets are highly exposed to the geopolitical risk of gas supply and natural gas price volatility, and the economic risk of currency exchange