Over the past few years, the European Union (EU) has been making concerted efforts to shift towards cleaner energy by setting ambitious targets and formulating supporting policies. To achieve its goals of becoming carbon neutral by 2050 (under the European Green Deal) and reducing its greenhouse gas emissions by at least 55 per cent by 2030 (with support of the Fit-for-55 package), it is looking to integrate large-scale variable renewable energy (VRE) into the grid. Under the Fit-for-55 package, the share of renewable energy is proposed to be increased to at least 40 per cent by 2030 (from 32 per cent previously), along with the introduction of sector-specific measures for increasing the EU’s contribution to the final energy demand. For this, the EU will need 451 GW of wind capacity by 2030 (up from about 180 GW in 2021) and will have to double its planned annual capacity addition in the coming years.
This shift towards greater renewables integration comes with its own set of challenges for grid operators as it impacts grid resilience. Balancing supply and demand at all times is critical given that even a small variation can disturb the frequency of the power system, and also affect system operations and reliability. The large-scale renewable energy penetration means large swings in power supply and demand, thus making a case for flexible power systems.
In this backdrop, the European Network of Transmission System Operators for Electricity (ENTSO-E) recently released a position paper on the “Assessment of Future Flexibility Needs” in Europe. The paper provides insights on identifying the flexibility needs in generation, demand and storage.
Need for flexibility
Fundamentally, power system flexibility needs arise from variations in the power system due to uncertain and fast changing generation, demand and grid capacity. In terms of demand, the electrification of heating, transport and industries has led to greater uncertainty and variation. For instance, lack of smart charging in electric vehicles (EVs) as well as larger electric loads, subject to temperature variations, difficult-to-forecast customer preferences and uncertain price responsiveness, can lead to huge fluctuations in demand.
On the generation front, the increased use of VRE and less despatchable generation (which can be despatched on grid operators’ demand as per market needs) causes imbalances in supply.
In grids, variation and uncertainty are caused by VRE, distributed energy resources and inverters (devices that convert DC electricity into AC). With the large-scale deployment of inverter-based generators, system inertia is expected to decrease and lead to increasing rates of change of frequency (RoCoFs), which can present a challenge in terms of frequency stability of the system.
Existing assessment approaches
The EU’s extant power system planning methods already assess flexibility needs, and the availability of solutions and products to cover flexibility gaps in many cases. These needs are addressed in the European Resource Adequacy Assessment, the system operation, capacity allocation, congestion management and electricity balancing guidelines, as well as the Electricity Regulation. For instance, in recent years, ENTSO-E’s Ten-Year Network Develop Plan has forecast decreasing inertia levels due to converter-interfaced renewables such as solar photovoltaic (PV), wind and battery resources becoming dominant. Coupled with increasing RoCoF due to the rise in sudden disturbances, this may create demand for fast frequency response capacities. Indicators such as inertia, RoCoF, area control error and frequency restoration control error quality need to be investigated.
Ireland’s transmission system operator (TSO), EirGrid, has illustrated the speed at which frequency response challenges can be met. Meanwhile, the adequacy and flexibility assessment study by Belgium’s TSO Elia provides examples of flexibility metrics that address unexpected generation and demand variations after the day-ahead time frame. Moreover, there are research and innovation (R&I) projects such as MIGRATE (Massive InteGRATion of power Electronic devices), which have successfully investigated systems with high penetration of power electronics. Another ongoing R&I project is the European OneNet flexibility market project, which started in October 2020. It is funded by the European Commission’s Horizon 2020 programme. Under this, various flexibility market solutions and complementary tools for electricity network development and operations will be tested over a three-year period. In addition, the project will carry out regional studies on flexibility needs and studies on methodological development needs.
With all these developments, TSOs now need to identify which additional flexibilities may be needed at what time in the future and in which European regions, and also understand the possible negative effects of a flexibility gap in the power system.
ENTSO-E’s position paper makes an assessment of future flexibility needs in the day-ahead time frame, that is, the flexibility needs arising from increasing variability in the balance of generation, demand and storage. It states that the increasing variability in the forecasted demand and generation in the day-ahead time frame can possibly lead to two new flexibility challenges.
First, the periods when load is increasing and VRE generation is decreasing could require weather-independent generation to ramp up or down at a faster rate and wider overall MW ranges to compensate for the decrease in renewable energy supply. For instance, the increase in load could become steeper due to the increasing penetration of heat pumps and EVs, while the VRE fluctuations (for example, during sunset) would grow with higher VRE penetration. Second, the decreasing amount of weather-independent generation may become insufficient to cover the demand during extended scarcity periods with very low VRE generation, such as during windless winter weeks.
ENTSO-E conducted a survey of assessment approaches being used by 22 TSOs for future flexibility needs and on international examples of flexibility needs assessments, metrics and products. Based on the responses, ENTSO-E zeroed in on two flexibility needs – ramping and scarcity periods.
To illustrate how flexibility needs for ramping and scarcity periods could evolve by 2025 and 2030, ENTSO-E considered the example of Germany, which is both one of Europe’s largest countries and has one of the highest VRE penetration rates, based on ENTSO-E’s Mid-term Adequacy Forecast (MAF) 2020 data. Though the German system displays sufficient system adequacy in both the 2025 and 2030 MAF analyses, its high amount of installed wind and solar capacities relative to both peak loads and installed despatchable capacities have started posing challenges that are quite visible on ramping and scarcity periods.
Notably, the paper acknowledges that a simple analysis of residual loads cannot replace the complete and realistic chronological simulation of system adequacy, which includes forced outages, different climate years, as well as imports and exports. Therefore, ENTSO-E has proposed metrics that combine the strengths of detailed hourly results from chronological probabilistic simulations, with insights gained from the simple residual load analysis focused on the two relevant and prevalent variability challenges:
Ramping flexibility needs: The ramping flexibility needs approach is partly based on experiences from California Independent System Operator and EirGrid. These metrics measure large daily residual load gradients, for example, at sunset in regions with large PV generation capacities. Residual load is the load left after subtracting VRE generation (such as wind, PV and run-of-the-river hydro) from the total demand, and is a useful indicator to show the flexibility and ramping needs for adequate power system operation. Explicit and implicit demand flexibility was considered a part of the despatchable capacity, and not in the residual load calculation. As per ENTSO-E, the treatment of these capacities in the methodology could be further improved.
Consider the 2025 and 2030 maximum ramps in the residual load over one, three and eight-hour time steps, which reach a substantial fraction of the total despatchable capacity and even exceed it at times. Study that relates the residual load to despatchable capacities indicates a serious ramping-flexibility challenge, especially for the 2030 data, as despatchable capacity or other flexibilities would need to be imported from neighbouring countries, or renewable energy generation would need to be curtailed in a well-coordinated and anticipated manner to cover such ramps.
However, a key point to be noted is that residual loads do not account for imports and exports, which strongly contribute to overall system adequacy, especially for strongly interconnected countries such as Germany. Further, despatchable capacities, which in any case only provide a very rough reference for the interpretation of residual loads, are adjusted or derated to account for forced outage rates of coal, gas, pumped storage hydropower generation and other capacities, and include the MAF data for demand-side response (DSR).
Broadly, the highest annual residual load MW ramps (calculated as the difference between residual loads one, three and eight hours apart) can be easily compared with market zones and years after they are normalised to the zone’s despatchable capacity, accounting for demand response and forced outage derations.
The proposed metrics for ramping flexibility needs are percentage of loss of load expectation (LOLE), expected energy not served (EENS), and curtailed surplus energy during the 5 per cent highest ramp periods. These indicate how the ramping issue can pose an adequacy and economic problem. They will be assessed separately for positive and negative residual load ramps and for one-, three- and eight-hour ramps as well as the corresponding prior hours for potential pre-emptive curtailment. Currently, hourly values for LOLE, EENS and curtailed energy are among the outputs of chronological probabilistic market simulations used by adequacy and Ten-Year Network Development Plans (TYNDP) studies. With the necessary fine-tuning of this indicator, the 5 per cent threshold can be addressed and the ramping capabilities of all resources can be modelled in market simulations, especially for demand response and VRE curtailment.
Scarcity period flexibility needs: These are metrics focused on contiguous-day EENS issues during scarcity periods, when VRE resources are not available for extended and continuous periods such as windless winter weeks in northern Europe. This metric can indicate small sets of hours in a given year when flexibility is particularly challenging. Meanwhile, market simulations can show quantified reliability risks from detailed simulations of despatchable capacity, demand response, battery use, and mutual support between countries, as well as weather and outage probabilities.
As in the case of ramping, LOLE and EENS percentages over the maximum 120-hour average residual load periods indicate the fraction of overall adequacy concerns that arise due to seasonal scarcities involving extended periods of high residual load and low VRE generation. For further interpretation of scarcity periods, it may be useful to examine the climate years with high LOLE and EENS contributions during the identified 120-hour scarcity periods in market simulations, as well as the average generation as a percentage of the installed capacities of all VRE resources during these periods. This will help understand which climatic conditions can lead to scarcity periods.
The necessary fine-tuning of this indicator will not only address the focus on the single worst five-day period, but also involve examining how the availabilities of flexibility resources during scarcity periods are modelled in market simulations, especially implicit demand response and sector coupling resources such as vehicle-to-grid (V2G), or seasonal thermal or hydrogen storage.
Sector coupling and flexibility: Sector coupling can be an important source of flexibility in the energy system, ranging from energy storage technologies to demand response solutions. Sector coupling refers to the integration of energy consuming sectors – buildings (heating and cooling), transport and industry – with the power generation sector. It provides options to absorb excess electricity supply from renewable energy sources, to store energy and provide backup supply in times of high demand and prices.
Sector coupling solutions such as power-to-heat with thermal storage and electrolysers using clean electricity combined with gas storage seem relevant for mitigating scarcity period flexibilities, especially for countries with high VRE shares. Meanwhile, power-to-gas, smart electrolysers, V2G and smart EV charging are solutions that offer fast response flexibility and ramping flexibility – both before and during the steep evening ramp of the residual load.
Hydrogen-based sector coupling is also gaining traction and there is a growing interest in using hydrogen as a long-duration energy storage resource in a future electric grid dominated by renewable energy generation. Recently, Denmark’s TSO Energinet and pump producer Danfoss entered into an innovation collaboration to examine whether a plant that converts electricity into hydrogen can be used to help balance the power grid. The collaboration is part of Energinet’s Open Door Lab, which examines how to enable more flexibility in the power grid.
Sector coupling as well as other flexibilities such as batteries and DSR involve load that is connected at the distribution level, implying that their usage for the overall system requires close cooperation between TSOs and distribution system operators (DSOs). ENTSO-E suggests that to promote this cooperation between TSOs and DSOs, a joint assessment of flexibility needs should be developed for different use cases at the transmission and distribution level.
Challenges and the way forward
The introduction of flexibility in the power system on a wide scale is undoubtedly a complex and significant challenge and hence the position paper is a step in the right direction. ENTSO-E is further planning to develop several additional flexibility need assessment methods related to stable frequency, congestion management, voltage stability and uncertain variations or forecast errors after the day-ahead frames along with associated metrics in the coming years. Once developed, ENTSO-E may directly apply or recommend to its member TSOs a fine-tuning and application of these methods, metrics and indicators on a national, regional and/or pan-European level.
With proper planning and execution, Europe’s power system can certainly provide safe and quality power even in the face of an unprecedented energy transition.