Background report providing guidance on tools and methods for the preparation of public heat maps

This methodology is intended to provide guidance to MS on the structure and methods of preparation of a map of the national territory, identifying heating and cooling demand points, district heating and cooling infrastructure and potential heating and cooling supply points. Since there are many diverse methods and tools that can be used for processing of the data, making of the map and eventual publishing, this methodology is not intended to cover them all but instead should be viewed as a supporting document and a source of ideas.JRC.F.6-Energy Technology Policy Outloo

Background report on best practices and informal guidance on installation level CBA for installations falling under Article 14(5) of the Energy Efficiency Directive

The Energy Efficiency Directive (EED), adopted on 4 December 2012, establishes a set of binding measures to help the EU reach its 20% energy efficiency target by 2020. Under the Directive, all EU countries are required to use energy more efficiently at all stages of the energy chain from its production to its final consumption. Member States were required to translate the EED into national law by 5 June 2014. The EED will repeal the existing Cogeneration Directive (2004/8/EC) and the Energy End-Use Efficiency and Energy Services Directive (2006/32/EC) as of 5 June 2014. Article 14(5) of the EED requires Member States to ensure that thermal electricity generation installations and industrial installations exceeding 20 MWth, carry out a cost-benefit analysis when they are planned or substantially refurbished to assess whether the use of high-efficiency cogeneration, the connection to a district heating or cooling network or other means of waste heat recovery would be cost-effective. The obligation to carry-out a cost-benefit analysis also applies to new district heating and cooling networks, when those are planned or when an energy production installation with a capacity exceeding 20 MWth is planned or substantially refurbished within those networks, in order to assess whether the utilisation of waste heat from a nearby industrial installation is cost-effective. If the benefits exceed the costs, the options analysed in the cost-benefit analysis must be included in the authorisation or permit criteria. The cost-benefit analysis has to be in accordance with the general methodological principles set out in Part 2 of Annex IX. A possible methodology for conducting a Cost Benefit-Analysis (CBA) in accordance with Article 14(5) and Part 2 of Annex IX of the Energy Efficiency Directive is presented here. The methodology takes into account the Guidance note prepared by the Commission for the implementation of Article 14, including the carrying out of the cost-benefit analysis by individual installations and district heating and cooling networks.JRC.F.6-Energy Technology Policy Outloo

Background report on evaluation of thresholds for exemptions under Article 14(6) of the Energy Efficiency Directive

Article 14 (6) of the Energy Efficiency Directive allows Member States to exempt certain installations from the requirements of conducting a cost-benefit analysis of individual installations as stated by Article 14 (5). This report compares MS notifications on exemptions concerning laying down thresholds with general benchmark thresholds and with thresholds estimated through a general techno-economic model. Finally, this report provides recommendations how the exemptions thresholds ought to be defined, in order not to a priori exclude feasible heat linking options.JRC.C.7-Knowledge for the Energy Unio

Integrated modelling of future EU power and heat systems: The Dispa-SET v2.2 open-source model

This report describes the implementation of the Dispa-SET model version 2.2. It extensively describes the model equations, the model inputs, and the resolution process. This version of Dispa-SET focuses more specifically on the inclusion of the heating sector, with a new dedicated module. It allows simulating the potential interactions between heat and power and the exploitation of thermal storage as a flexible resource. The model is an open-source tool and comes with an open dataset for testing purposes. It can therefore be freely re-used or modified to fit the needs of a particular case study.JRC.C.7-Knowledge for the Energy Unio

Case study on the impact of cogeneration and thermal storage on the flexibility of the power system

This work investigates the optimal operation of cogeneration plants combined with thermal storage. To do so, a combined heat and power (CHP) plant model is formulated and incorporated into Dispa-SET, a JRC in-house unit commitment and dispatch model. The cogeneration model sets technical feasible operational regions for different heat uses defined by temperature requirements.JRC.C.7-Knowledge for the Energy Unio

Power system flexibility in a variable climate

Our report “Power system flexibility in a variable climate” assesses the impact of the annual variation of meteorological factors – the climate variability – on the operations of the power systems in 34 European countries that jointly constitute the interconnected European electricity systems. It covers important aspects such as CO2 emissions and use of freshwater for cooling of power plants, and estimates their sensitivity to the changing climatic conditions. Changing weather conditions affect the operation of the European power systems. The output of renewable energy sources fluctuates depending on the availability of wind, cloud cover, or water levels in reservoirs, while the output of dispatchable generators, such as gas turbines, must be adapted accordingly to ensure that supply and demand are balanced at all times. The link between meteorology and power systems also manifests itself through other aspects such as the demand for electricity, affecting the operation of power markets, and thus power prices, emissions, and use of resources (fuels, fresh water etc). Today more than 40% of the European electricity generation capacity is heavily dependent on climatic factors. This dependence is expected to increase in the future as Europe is transitioning to a carbon-neutral economy by mid-century.JRC.C.7-Knowledge for the Energy Unio

Water-related modelling in electric power systems: WATERFLEX Exploratory Research Project: version 1

Water is needed for energy. For instance, hydropower is the technology that generates more electricity worldwide after the fossil-fuelled power plants and its production depends on water availability and variability. Additionally, thermal power plants need water for cooling and thus generate electricity. On the other hand, energy is also needed for water. Given the increase of additional hydropower potential worldwide in the coming years, the high dependence of electricity generation with fossil-fuelled power plants, and the implications of the climate change, relevant international organisations have paid attention to the water-energy nexus (or more explicitly within a power system context, the water-power nexus). The Joint Research Centre of the European Commission, the United States Department of Energy, the Institute for Advanced Sustainability Studies, the Midwest Energy Research Consortium and the Water Council, or the Organisation for Economic Co-operation and Development, among others, have raised awareness about this nexus and its analysis as an integrated system. In order to properly analyse such linkages between the power and water sectors, there is a need for appropriate modelling frameworks and mathematical approaches. This report comprises the water-constrained models in electric power systems developed within the WATERFLEX Exploratory Research Project of the European Commission’s Joint Research Centre in order to analyse the water-power interactions. All these models are deemed modules of the Dispa-SET modelling tool. The version 1 of the medium-term hydrothermal coordination module is presented with some modelling extensions, namely the incorporation of transmission network constraints, water demands, and ecological flows. Another salient feature of this version of Dispa-SET is the modelling of the stochastic medium-term hydrothermal coordination problem. The stochastic problem is solved by using an efficient scenario-based decomposition technique, the so-called Progressive Hedging algorithm. This technique is an Augmented-Lagrangian-based decomposition method that decomposes the original problem into smaller subproblems per scenario. The Progressive Hedging algorithm has multiple advantages: — It is easy parallelizable due to its inherent structure. — It provides solution stability and better computational performance compared to Benders-like decomposition techniques (node-based decomposition). — It scales better for large-scale stochastic programming problems. — It has been widely used in the technical literature, thus demonstrating its efficiency. Its implementation has been carried out through the PySP software package which is part of the Coopr open-source Python repository for optimisation. This report also describes the cooling-related constraints included in the unit commitment and dispatch module of Dispa-SET. The cooling-related constraints encompass limitations on allowable maximum water withdrawals of thermal power plants and modelling of the power produced in terms of the river water temperature of the power plant inlet. Limitations on thermal releases or water withdrawals could be imposed due to physical or policy reasons. Finally, an offline and decoupled modelling framework is presented to link such modules with the rainfall-runoff hydrological LISFLOOD model. This modelling framework is able to accurately capture the water-power interactions. Some challenges and barriers to properly address the water-power nexus are also highlighted in the report.JRC.C.7-Knowledge for the Energy Unio

Wind and other CO2-free assets replacing coal in 2030: A scenario analysis based on the EUCO3232.5 scenario with the METIS model

An up-to-date partial coal phase out scenario based on the power system and prices defined in the EUCO3232.5 scenario for 2030 is analysed with the METIS power system model. Following the removal of coal and lignite fleets in excess of half the capacity present in the EUCO scenario, the power system experiences more often power scarcity, primarily in the Central-West region of Europe. The study explores the potential of new wind capacity to fill the vacuum created by the coal fleet retirements both in energy and capacity terms. The conclusion of the previous similar study of 2018, that new wind capacity predominantly placed in peripheral regions of Europe (South-east, South-west and the North), has the potential to balance the system was tested for multiple climatic years. The modelling analysis showed that new capacity consisting of 85 GW of additional wind power (compared to the EUCO3232.5) supported by additional infrastructure would be sufficient to restore adequacy. The additional infrastructure identified in this study consists of approximately 8.2 GW of batteries, very limited new peaking generation (up to 0.5 GW) and 53 GW of interconnection upgrades. The interconnector’s role as a definitive enabler, not only of market integration but also of a path towards a renewables-based power system is strongly supported by the results. The identified transmission upgrades alone have the potential to reduce the carbon footprint of the European power system by more than a quarter, compared to the EUCO3232.5, with minimal additions of peaking capacity. In a scenario variant where no additional wind is added to the system, the modelling results indicate that only an additional 4.2 GW of peaking capacity (OCGTs) and 14.8 GW of battery storage on top of the EUCO3232.5 capacities, would be sufficient to restore adequacy to the power system, following the assumed coal fleet decommissioning. In a second scenario used to benchmark the results, with no interconnection upgrades we find that the flexible resource requirements rise sharply to 21 GW of battery storage and 22.3 GW of thermal peaking capacity. The cost of the additional infrastructure was estimated for all scenarios and benchmarked against the potential CO2 savings. Under the EUCO3232.5 fuel price assumptions replacing coal with wind power would lead to an annual additional cost ranging between 1.9 and 4.5 € Billion which would correspond to an incremental abatement cost between 7.4 and 18.2 €/tonne CO2 in 2030.JRC.C.7-Knowledge for the Energy Unio

Case study on the impact of cogeneration and thermal storage on the flexibility of the power system

This work investigates the optimal operation of cogeneration plants combined with thermal storage. To do so, a combined heat and power (CHP) plant model is formulated and incorporated into Dispa-SET, a JRC in-house unit commitment and dispatch model. The cogeneration model sets technical feasible operational regions for different heat uses defined by temperature requirements