This paper proposes an improved version of EUPowerDispatch - a minimum cost dispatch model, was originally developed to investigate the need for cross-border transmission investment in Europe - that aims at analysing the generation adequacy of the European electricity system in a probabilistic manner. Over the last decades, the actions aimed to realize an integrated pan-European electricity market brought about profound modifications on the physical, information and communication systems upon which the electricity delivery process occurs. In order to assess some of the techno-economic challenges relating to the single electricity market functioning, including the future needs of electricity, several dispatch models have been developed in recent years in Europe and the rest of the world. The case study is composed of 33 European countries/regions which are linked through interconnectors. Indexes for the reliability assessment of electric power systems are calculated in order to study the generation adequacy of the European electricity system in 2025.

This report summarises the findings of a project, awarded to Tractebel-Engie, to analyse the possibility and the effects of implementing nodal pricing in the European Internal electricity market based on the current and proposed legal framework.

In the past there have been studies and discussions regarding the use of nodal pricing in Europe. Indeed, the move to a nodal pricing scheme was considered as one of four possibilities for improving local price signals in the EC Impact Assessment of the Clean Energy package.

The report presents the origins and organisation of nodal pricing and the documented costs and benefits and describes the implementation challenges of applying nodal pricing in the EU.

This paper investigates how price caps, capacity targets and merchant investments affect the critical investment thresholds and characterize the government's optimal incentive. We consider firms facing uncertain demand, and study their problem of investing in an electricity line between two neighbouring countries, under capacity constraints, and incentive schemes.

We consider three ownership structures: a state-owned transmission company, a merchant transmission investor, and a regulated firm. The firm's problem is to choose the optimal time and size of the interconnector. The government is concerned with the incentive design.

We find that price caps speed-up projects' development, while capacity targets reduce under-investments in capacity markets. Finally, we study the effect of investment decisions on the social welfare value.

This paper proposes a Deterministic Unit Commitment (DUC) model with a set of state-of-the-art probabilistic reserve constraints (DUC-PR). An electricity generation system adequacy assessment aims to generate statistically significant adequacy indicators given projected developments in, i.a., renewable and conventional generation, demand, demand response and energy storage availability. DUC models with exogenous reserve requirements, as often used in today's adequacy studies to represent day-to-day power system operations, do not account for the contribution of operating reserves to the adequacy of the system. Hence, the adequacy metrics obtained from such an analysis represent a worst-case estimate and should be interpreted with care. The performance of the DUC-PR model in the context of adequacy assessments is studied in a numerical case study. The Expected Energy Not Served (EENS) volume obtained with the DUC model is shown to be a poor estimate of the true EENS volume. In contrast, the DUC-PR methodology yields an accurate estimate of the EENS volume without significantly increasing the computational burden. Policy makers should encourage adopting novel operational power system models, such as the DUC-PR model, to accurately estimate the contribution of operating reserves to system adequacy.

This paper provides an econometric analysis to understand the individual effect of regulation and ownership structure on the decision to adopt more stringent unbundling regimes by using a dataset of the 35 major electricity transmission utilities in Europe.

One of the fundamental provisions of the European electricity directives is the so-called unbundling of structures and functions. Vertical disintegration with Full Unbundling (ownership unbundling or independent system operation) is considered an important step toward electricity market restructuring. While Full Unbundling (FU) models appear to be the most prevalent, several European countries adhered solely to less stringent forms of unbundling.

The overall results show that incentive-based or hybrid regulatory schemes and private ownership, are associated with a higher probability that a country will opt for FU.

This report presents recommendations for the Greek power system adequacy assessment. Approaches to generation adequacy assessment vary between countries, not only with regard to the implemented methodology, but also with regard to the generation and demand models used to estimate these elements. Furthermore, the results are very sensitive to the assumptions used to project future resources and demand(s). In this context, there is a need for harmonisation of models, data assumptions, and inputs between national and European adequacy and flexibility studies. Best European and international practices based on the current and future evolution of the power system, should be adopted and implemented to provide a common assessment methodology for the pan-European and national adequacy studies.

Following the assessment of the studies, the main recommendations for potential improvements are summarised below. It should be mentioned that to achieve full alignment with the ENTSO-E standards on generation adequacy studies or the state-ofthe-art on flexibility assessment, the implementation of (at least) these methodological suggestions is needed.

This paper focuses on market and regulatory factors, based on a review of the European regulatory status and using a dataset of 459 innovative smart grid projects. It performs a series of statistical tests to investigate how the different factor levels affecting smart grid investments in Europe.

Electricity distribution system operators (DSOs) are expected to invest heavily in system innovation in the form of smart grids (SG) in order to help achieve energy policy goals. In this context, regulatory reforms to spur DSOs investments are considered a policy priority.

The results show that lower market concentration in the electricity distribution sector the use of incentive-based regulatory schemes; and the adoption of innovation-stimulus mechanisms are key enablers of smart grid investments.

This report presents a review of some European Member States, regions and ENTSO-E’s pan-European methodologies to highlight the latest developments and current trends.

Generation adequacy is a key tool to assess security of supply in an electrical system. Complementing national adequacy assessments with regional and pan-European studies is required for scrutinising the integrated interplay and functioning of the European electricity system and market. What is needed, besides a minimum harmonisation of models and data inputs, is to clearly determine what the scope of each assessment is. Indeed, increasing the model geographical size can be hardly attained at the same time as increasing the time resolution, as well as representing into detail several other system features; additionally, keeping things as simple as possible will avoid constant revisions of the fundamentals and the basic assumptions of the assessment methodologies used by a vast number of stakeholders.

In Europe, the integration of high amount of variable generation, demand response, storage, distributed generation, the increase of interconnection capacities and the electricity markets coupling, motivate a need for a revision of how adequacy is assessed.

This paper examines the market integration of a centrally dispatched multi-terminalHVDC Grid based on droop control.

The development of a multi-terminal high voltage DC (HVDC) grid based on voltage source converter (VSC) technology has been envisaged as a key development for harnessing the vast offshore wind production potential of the North Seas. 

Particular emphasis is given on the management of onshore imbalance volumes due to offshore wind power forecast errors. The economic importance of the control choices of the operator of such an active transmission grid is highlighted, and regulatory implications are briefly discussed.

The main contribution of the paper is the coherent development of a droop-controlled MT HVDC grid scheme that integrates optimal power flow (OPF) dispatch, and imbalance volume management.