Search

2021 has been a landmark year for UK energy and climate policy. Plans and strategies were announced across many sectors, from offshore wind to how we heat our homes. The UK also hosted COP26 and pressed hard for greater ambition. Now that the spotlight has moved, in this Review, we consider whether plans will be adequate to deliver results.With a focus on gas and the UK continental shelf, industrial decarbonisation, heat, mobility and the environment, we look at developments both at home and internationally and ask whether the UK is a leader in decarbonisation, and if the transition is being managed as well as it could be.

The heating of homes is a major contributor to the UK’s greenhouse gas emissions accounting for 13% of total emissions. 1 This is comparable to the carbon emissions of all petrol and diesel cars in the UK. 2 Meeting the UK government’s net zero emissions goal for 2050 will only be possible by complete decarbonisation of the building stock (both existing and new). While emissions from heating have fallen by 11% since 1990 1, much of which was driven by efficiency programmes and regulation in the period 2002-2012 3, continuing decarbonisation at this pace would get us to zero emissions from buildings in 235 years and fall far short of meeting the 2050 target. Home heating energy consumption is also at risk of increasing further. Home working has developed substantially during the COVID-19 lockdown and is widely expected to remain at higher levels than pre-crisis 4 meaning that people may require houses which are on average warmer during the heating seasons. Data shows that domestic heating energy use was up by 15% during March when the lockdown started compared to March 2019 5,6., The potential for more time spent at home will make heat decarbonisation and the thermal comfort and health associated with homes even more important. There is uncertainty over the extent to which heating might practically be decarbonised in the future and what the optimal technologies may be. The aim of this paper is, to provide some clarity about the pathways forward, focusing on the next 5-10 years. We also draw on lessons learned from international examples for smart electrification of heating which we identify as one of the key strategies for decarbonisation of residential heat – at least in the short term.

The present report is a public deliverable (D1.2) of the MAGNITUDE H2020 funded European project. The MAGNITUDE project aims at developing business and market mechanisms, as well as supporting coordination tools to provide flexibility to the European electricity system, by enhancing the synergies between electricity, heating/cooling and gas systems. Seven real-life case studies of multi-energy systems of different sizes and technological features located in seven European countries are used to provide the data foundation for the assessment and analysis carried out in the frame of the project.

Traditionally, power system operation has relied on supply side flexibility from large fossil-based generation plants to managed swings in supply and/or demand. An increase in variable renewable generation has increased curtailment of renewable electricity and variations in electricity prices. Consumers can take advantage of volatile electricity prices and reduce their bills using electricity storage. With reduced fossil-based power generation, traditional methods for balancing supply and demand must change. Electricity storage offers an alternative to fossil-based flexibility, with an increase expected to support high levels of renewable generation. Electrochemical storage is a promising technology for local energy systems. In particular, lithium-ion batteries due to their high energy density and high efficiency. However, despite their 89% decrease in capital cost over the last 10 years, lithium-ion batteries are still relatively expensive. Local energy systems with battery storage can use their battery for different purposes such as maximising their self-consumption, minimising their operating cost through energy arbitrage which is storing energy when the electricity price is low and releasing the energy when the price increases, and increasing their revenue by providing flexibility services to the utility grid. Power rating and energy capacity are vitally important in the design of an electricity storage system. A case study is given for the purpose of providing a repeatable methodology for optimally sizing of a battery storage system for a local energy system. The methodology can be adapted to include any local energy system generation or demand profile.

Accurate information regarding the uncertainty of short-term forecast for aggregate wind power is a key to efficient and cost effective integration of wind farms into power systems. This paper presents a methodology for producing wind power forecast scenarios. Using historical wind power time series data and the Kernel Density Estimator (KDE), probabilistic wind power forecast scenarios were generated according to a rolling process. The improvement achieved in the accuracy of forecasts through frequent updating of the forecasts taking into account the latest realized wind power was quantified. The forecast scenarios produced by the proposed method were used as inputs to a unit commitment and optimal dispatch model in order to investigate how the uncertainty in wind forecast affect the operation of power system and in particular gas-fired generators.

The large scale integration of wind generation capacity into an electricity\ud network poses technical as well as economic challenges. In this research,\ud three major challenges introduced by wind including non-correlated power\ud output from geographically dispersed wind farms, wind variability and wind\ud uncertainty were studied. In order to address each of the aforementioned\ud challenges an appropriate modelling approach and case studies were used.\ud The impacts of power output from dispersed wind farms on the Great Britain\ud transmission reinforcement were studied using an optimal DC load flow combined\ud with a power generation model. It was shown that Western and\ud Eastern HVDC links play a crucial role to bypass the Scotland to England\ud transmission bottleneck.\ud The impacts of wind variability on the GB gas and electricity network were\ud investigated through application of the Combined gas and Electricity Network\ud (CGEN) Model. Additional gas storage capacity was shown to be an\ud efficient option to compensate for wind variability.\ud Two-stage and multi-stage stochastic programming models were developed\ud to examine the impact of wind forecast uncertainty on the GB electricity and\ud gas networks. Stochastic modelling approaches were shown to be efficient\ud methods for scheduling and operating the system under wind uncertainty.\ud The key contributions of this thesis are the investigation of the impacts of\ud wind generation variability on the gas network, and development of twostage\ud and multi-stage stochastic programming models of integrated gas and\ud electricity network.

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

The aim of this project is to describe the expected evolution of the Spanish electricity sector in the coming decades, as well as to study the economic feasibility of solar PV and CCGT power generation plants in this context. First of all, an analysis of the Spanish electricity market has been carried out. The current energy situation has been also studied, both globally and nationally. Given the growing importance of renewable energies in the sector, the legislative development on renewables has been studied, as well as the impact they have generated in the sector and their different financing mechanisms. Based on the environmental objectives established by the European Union, the general lines of the expected energy transition in the Spanish electricity sector have been defined, estimating the installed capacity of the main generation technologies for the period 2020-2050, as well as their contribution in the generation mix. Likewise, an analysis of the price of electricity in the daily market has been carried out, from which a price prediction model has been developed. According to the results, the weight of renewables will increase progressively during the next decades, reaching in 2050 an approximate share of 90% in the generation mix. The expected load factor for CCGTs, on the other hand, will increase in the mid-term, whereas in the long-term will be reduced below the current values. The price of electricity, on the other hand, will increase significantly between 2020 and 2030, whereas as of this year will undergo a gradual but steady reduction. Given the expected relevance of solar PV and CCGT technologies in the future Spanish generation park, the economic feasibility of both technologies has been studied. In the case of the solar PV plant, an analytical model has been developed in MATLAB by which forecasts of the generation of the plant have been made. These results have been validated by the software SOLAR PV, making a comparison between both results. For the analysis of CCGT plant, the price in the adjustment markets has been studied, analysing its relationship with the price in the daily market. According to the results, both projects would be profitable. However, given the uncertainty inherent to forecasts of the price, alternative forecasts have been considered. Due to substantial differences in the mid-term, the main financial parameters of solar PV and CCGT power generation plants have been calculated again, considering in this case the alternative forecasts of the price. From this second analysis it has been concluded that, whereas the solar PV would not require any additional financing mechanism in order to be profitable, capacity payments would be indispensable in the case of the CCGT plant. It has been also concluded that, in the analysis of the economic feasibility of marginal technologies, such as CCGTs, the average price of the electricity in the markets is not a representative parameter. Outgoing