Distributed energy resources and electricity balancing : visions for future organisation

This Report discusses how electricity balancing may best be organised in a future with greater penetration of distributed energy resources (DERs). Increased DER penetration can pose challenges to electricity balancing, while, at the same time, DERs can also help to balance the system more cost-effectively. Currently, participation by DERs in electricity balancing markets, whether individually or aggregated, is still somewhat limited. In the debate among practitioners and academics, most attention has been devoted to reducing market entry barriers for DERs. In this Report, we go one step further: we analyse whether the current organisation of the balancing mechanism is future-proof. This Report comprises an introduction, four sections and conclusions. After the introduction, Section 2 explains the working of the balancing mechanism and introduces the relevant EU legislation. Section 3 shows that the current organisation of balancing mechanisms in the EU is a legacy rather than a well-thought-through design choice. We explain that alternative setups are possible in theory and that their performance in practice depends on the context. To assess different balancing setups, we introduce a multidimensional framework and illustrate it by comparing the current setups in the EU and the US. In Section 4, we highlight the challenges that the balancing mechanism in the EU is currently facing with increasing shares of DERs. We argue that, in the medium to long term, it will become increasingly challenging to operate the balancing mechanism cost-effectively without adjusting its organisation. In Section 5, we introduce two alternative ways of organising it in the future: the ‘Super SO model’ and the ‘Local SO model’. The key question is whether it would be easier to manage seams within a balancing area or seams between balancing areas. The main challenge with the Super SO model would be that a global optimum, considering all voltage levels and local issues, is difficult to achieve. Even though the Local SO model might be more pragmatic, the main challenge with this model would be implementing it in a way that limits fragmentation of balancing markets, which would have severe implications for efficiency and competition

Flexibility markets : Q&A with project pioneers

Flexibility markets are recognised as a promising tool to make better use of existing distribution grids and thereby also reduce the need for grid investments. In this paper, we analyse four pioneering projects implementing flexibility markets: Piclo Flex, Enera, GOPACS and NODES. Based on a literature review, we develop a six-question framework and we then analyse the projects with that framework. The questions are: (1) Is the flexibility market integrated in the existing sequence of EU electricity markets; (2) Is the flexibility market operator a third party; (3) Are there reservation payments; (4) Are the products standardised; (5) Is there TSO-DSO cooperation for the organisation of the flexibility market; (6) Is there DSO-DSO cooperation for the organisation of the flexibility market. We find that all the considered flexibility markets are operated by a third party. All projects also engage with multiple DSOs in order to become the standardised platform provider. Important differences between the projects are the extent to which the flexibility markets are integrated into other markets, the use of reservation payments, the use of standardised products and the way TSO-DSO cooperation has been implemented

Least-cost distribution network tariff design in theory and practice

First published online: 31 December 2020In this paper a game-theoretical model with self-interest pursuing consumers is introduced in order to assess how to design a least-cost distribution tariff under two constraints that regulators typically face. The first constraint is related to difficulties regarding the implementation of cost-reflective tariffs. In practice, so-called cost-reflective tariffs are only a proxy for the actual cost driver(s) in distribution grids. The second constraint has to do with fairness. There is a fear that active consumers investing in distributed energy resources (DER) might benefit at the expense of passive consumers. We find that both constraints have a significant impact on the least-cost network tariff design, and the results depend on the state of the grid. If most of the grid investments still have to be made, passive and active consumers can both benefit from cost-reflective tariffs, while this is not the case for passive consumers if the costs are mostly sunk.Published version of EUI WP RSCAS, 2018/1

Limits of traditional distribution network tariff design and options to move beyond

This policy brief is based on RSCAS Research Paper No. 2018/19, titled 'Least-cost distribution network tariff design in theory and practice' by SCHITTEKATTE, Tim; MEEUS, Leonardo. Details about the assumptions, data, and formulation of the mathematical model can be found in the research paper.With more consumers installing solar PV panels, it makes sense to depart from the historical practice of volumetric distribution network tariffs with net-metering. However, regulators face many practical difficulties when redesigning the distribution network tariff design. Typically, there is a trade-off between cost-reflectiveness and fairness. We illustrate the cost-reflectiveness versus fairness trade-off and we find that some cost-reflectiveness can be sacrificed to limit the distributional impact resulting from tariff redesign. However, this works only up to a certain point without compromising grid cost recovery. If grid costs are mainly sunk, and cost-reflective charges are hard to implement, then smaller passive consumers are always worse off – tools other than ‘standard tariff options’ are needed to keep distributional impacts under control while limiting distortions

D7.4 economic framework for a meshed offshore grid

Work Package 7 (WP7) of the Progress on Meshed HVDC Offshore Transmission Networks (PROMOTioN) Horizon 2020 project focuses on various legal, financial and economic aspects of developing an integrated offshore infrastructure. Task 7.2 focuses on the development of an economic framework for the offshore grid in terms of three building blocks, namely: planning, investment, and operation. 1. Offshore grid planning comprises three topics, namely: Cost-Benefit Analysis (CBA) methods, onshoreoffshore coordination, and public participation. 2. Offshore grid investment comprises four topics: cooperation mechanisms for renewable support, transmission tariffs, investment incentives, and Cross-Border Cost Allocation (CBCA) methods. 3. Offshore grid operation focuses on the balancing mechanism in the offshore wind context. This final report extends our intermediate report with the addition of three new topics: incentives, CBCA and the balancing mechanism. The remaining chapters are identical to the intermediate report. In this section, we provide a summary of the research that has been undertaken so far and the main conclusions from our analysis.This result is part of a project that has received funding from the European Union’s Horizon 2020 research and innovation programme under grant agreement No 691714

The 5th EU electricity market reform : a renewable jackpot for all Europeans package?

We think that the electricity markets that were developed over the last two decades did what they were supposed to do during this crisis: through higher prices, they convey the message that energy is scarce. “Shooting the messenger” is not going to remove the problem. However, we also learned a lot during this crisis on how electricity markets can be completed and complemented with regulatory instruments, which is why we have three recommendations: First recommendation: Enable and incentivize consumers and suppliers to hedge via well-functioning forward markets (which would complete the sequence of electricity markets). Second recommendation: Give consumers access to cheap renewables with Contracts for Difference (CfDs) and Power Purchase Agreements (PPAs) that are compatible with short-term markets. Third recommendation: De-risk the investments in energy resources AND mitigate affordability concerns for consumers by redesigning Capacity Remuneration Mechanisms (CRMs) or by complementing these mechanisms with other regulatory tools. We finally observe that a broader reform could also aim at accelerating the innovations on the consumers’ side envisioned by the Clean Energy Package. These innovations can bring the much-needed flexibility in decarbonized energy systems

Review of different national approaches to supporting renewable energy development

To increase the share of RES-E, governments have designed and implemented promotional policies which provide direct and indirect financial aid to RES-E adapters and developers. These promotional policies include several instruments and support schemes. Different countries, and in some cases different governments in a country, use different combinations of these support schemes to promote different renewable technologies. In this work, we study support schemes that have been implemented since the late 1990s or early 2000s in five countries: the UK, Germany, Italy, Spain and Australia. We provide an overview of these schemes and their timelines for the following RES-E technologies: onshore wind, offshore wind, utility-scale solar PV, rooftop solar PV and solar thermal. In addition, it is important to evaluate the effectiveness and efficiency of support schemes in promoting these RES-E technologies. We tackle these two values and provide specific discussions on each country, support scheme and technology

The EU electricity network codes

The EU network codes and guidelines are a detailed set of rules pushing for the harmonisation of national electricity markets and regulations. A total of eight network codes and guidelines entered into force by the end of 2017: three grid connection codes, three market codes and two (system) operation codes. This text focuses on the market codes (FCA, CACM and EBGL) and their interaction with the system operation guideline (SOGL). More precisely, this text is intended to guide the reader through the sequence of electricity markets in place in the EU: forward markets, the day-ahead market, the intraday market and finally the balancing markets. First, the establishment of these different markets in a national context is discussed, then their integration. In each section basic market design concepts are explained, we highlight what is in the codes, and we also refer to some of the relevant academic literature

Least-cost distribution network tariff design in theory and practice

In this paper a game-theoretical model with self-interest pursuing consumers is introduced to assess how to design a least-cost distribution tariff under two constraints that regulators typically face. The first constraint is related to difficulties regarding the implementation of cost-reflective tariffs. In practice, so-called cost-reflective tariffs are only a proxy for the actual cost driver(s) in distribution grids. The second constraint has to do with fairness. There is a fear that active consumers investing in distributed energy resources (DER) might benefit at the expense of passive consumers. We find that both constraints have a significant impact on the least-cost network tariff design, and the results depend on the state of the grid. If most of the grid investments still have to be made, passive and active consumers can both benefit from cost-reflective tariffs, while this is not the case for passive consumers if the costs are mostly sunk

How future-proof is your distribution grid tariff design?

The assumption that people cannot react to the way distribution grid tariffs are designed does not hold anymore. This is mainly true due to breakthroughs in two game-changing technologies: photovoltaics (PV) and batteries. • By investing in PV and batteries, active consumers push the sunk costs towards passive consumers (equity issue). Ironically, the active consumers can even end up paying more (efficiency issue). To avoid being screwed by the others, active consumers could overinvest. They are in a non-cooperative equilibrium. • We find that the outcome of this game between the DSO (and the regulator) trying to recover sunk costs, and active consumers reacting to the distribution grid tariff, depends heavily on the way the tariff is designed. • It is clear that current distribution grid tariffs are not future-proof. The historical conventional practice in the EU is net-metering, which creates significant equity issues and is an implicit subsidy for the adoption of PV. The solution that is advocated in the current debate, capacity charges, creates significant efficiency issues and is an implicit subsidy for the adoption of batteries. • ‘Bi-directional’ volumetric charges can outperform capacity based charges to recover sunk costs, so they should at least be considered as an option