No full-text available
To read the full-text of this research,
you can request a copy directly from the authors.
Day-ahead and real-time operational signals for the European electricity market
Abstract
This paper gives a comparison between zonal and nodal designs on the topic of Real-time and Day-ahead operational signals within and between different control areas. These designs are analyzed comparing public data and actual practices in use among different TSOs in comparable interconnected zones in Europe end the US, concluding that the zonal design is better suited for the European context. Concerning the Day-ahead signal, in a zonal design, market coupling (eventually with flow-based) allows an optimized use of interconnection capacity between control areas and the use of specific operating practices inside each control area. In nodal designs, control areas match market zones, but very poor results are observed at their interconnection, with inconsistency between price differentials and flows. Furthermore, the nodal design has some drawbacks concerning the optimization of maintenance periods and the leveling of operating procedures. A comparison of Day-ahead congestion revenues in the chosen areas shows that revenues were much greater in the US (1 798 M$ vs. 255 M€ in 2010). These values may reveal the different degree of development of the grid and may justify the choice of a nodal approach in the US. Inside a control area the Real-time signal is always nodal when needed, even in zonal designs; among different control areas the nature of the signal depends on the coordination level among TSOs. Topological remedial actions at almost no-cost seem easier to perform in a zonal design.
... Another important issue related to the modern electricity markets is the adoption of real-time pricing. It has been employed and improved in several power systems, as reported by [64][65][66]. ...
... The financial impacts of these systems may be improved, becoming the customers well informed participants of the electricity market. A comparative analysis between zonal and nodal designs concerning to real-time and day-ahead operational signals is performed in [66]. It compares the data and practices of several TSOs, placed in interconnected zones in Europe and in the USA. ...
Power sector is undergoing an expressive energy transition process, which increases the uncertainties across the whole sector. Transmission cost allocation (TCA) methods must be improved to contemplate this new paradigm. In order to obtain an efficient pricing and to encourage the more optimized use of system global resources, modern TCA methods must capture the observed integration trend of devices and systems. The current TCA methods need to be improved and new approaches developed based on the right insights identified in this chapter. We may affirm that the better TCA methods are straight, elegant, and without arbitrary and subjective decisions.
The achievement of the internal market for energy is going ahead in the EU 15 since a model is emerging for “coupling the national markets for electricity”. For about 15 years the EU 15 was made up of national markets open to each other through rules of access to the grids while organized market pricing was kept national. The main exception was in the Nordic countries (Sweden, Finland and Denmark plus Norway –not a member of the EU). In this region the coupling of national markets is obtained through a single Power Exchange being a common subsidiary of the Nordic transmission system operators (TSOs). This single PX runs a single Day Ahead market pricing zone when the grid is not constrained and splits itself into different pricing areas when structural constraints arise. This model is known as “market splitting”. The Netherlands, Belgium and France did later create a less centralized single pricing mechanism by “coupling” their three national PXs with a common pricing algorithm coordinating the price formation among the three national exchanges. The empirical success of this new model has validated it as an EU model for other regional markets. A counter-model has been experimented between Germany and Denmark. It consisted of a coupling of “volumes” linking the quantities offered and demanded in the two exchanges while keeping the price formation in these two markets separated. That experiment failed and started to work again only when elements of price coupling have been introduced. Having now three workable models of market coupling, the European Union (at least EU 15) should be able to successfully achieve one layer of its internal market soon. However, several further questions are kept open such as how to successfully bridge several regional markets all over the EU 15 or how to integrate more and more PXs having different regulatory frames. A centralized approach (known as CMU) is advocating creating a single pan-European trading entity by a mandatory restructuring of all existing PXs plus a clubbing of all TSOs and the extensive harmonization of all existing national regulatory frames. An alternative approach is the one known as PCR (“Price Coupling of Regions”). It allows building a less demanding common pricing mechanism to coordinate existing PXs in a decentralized network. It is permitting grid access and trading to keep a national flavour when requested by particular local preferences.
This contribution analyses the European electricity markets with respect to their aptitude to absorb large amounts of wind energy. Thereby in a first step the market designs of the major European power markets in France, Germany, Scandinavia, Spain and UK are reviewed, with a particular focus on liquidity in the spot and intraday markets. Then some key features of the short-term adjustments required by wind energy are discussed and the necessity of sufficient liquidity in intraday markets is highlighted. For the example of the German market subsequently the discrepancy between the physical short-term adjustment needs and the traded volumes on the intraday market is analyzed. This leads to an evaluation of proposals for improving the liquidity on the short-term market, including the use of continuous spot trading like in UK or the use of intraday auctions like in Spain.
Cross-border trade remains a contentious issue in the restructuring of the European electricity market. Difficulties stem from the lack of a common market design, the separation between energy and transmission markets and the insufficient coordination between Transmission System Operators (TSOs). This paper analyzes the cross-border trade problem through a set of models that represent different degrees of coordination both between the energy and transmission markets and among national TSOs.We first present the optimal organisation, not implemented in Europe, where energy and transmission are integrated according to the nodal price paradigm and Power Exchanges (PXs) and TSOs are integrated. This is our reference case. We then move to a more realistic representation of the European electricity market based on the so-called market-coupling design where energy and transmission are operated separately by PXs and TSOs. When considering different degrees of coordination of the national TSOs’ activities, we unexpectedly find that some arrangements are more efficient than the lack of coordination might suggest. Specifically we find that even without a formal coordination of the TSOs’ counter-trading operations, non discriminatory access to common counter-trading resources for all TSOs may lead to a partial implicit coordination of these TSOs. In other words, an internal market of counter-trading resources partially substitutes the lack of integration of the TSOs. While a full access to counter-trading resources is a weaker requirement than the horizontal integration of the TSO, it is still quite demanding. We show that quantitative limitations to the access of these resources decrease the efficiency of counter-trading. The paper supposes price taking agents and hence leaves aside the incentive to game the system induced by zonal systems.
Economists know how to calculate optimal prices for electricity transmission. These are rarely applied in practice. This paper develops a 13-node model of the transmission system in England and Wales, incorporating losses and transmission constraints. It is solved with optimal prices, and with uniform prices for demand and for generation, re-dispatching when needed to take account of transmission constraints. Moving from uniform prices to optimal nodal prices could raise welfare by 1.3% of the generators’ revenues, and would be less vulnerable to market power. It would also send better investment signals, but create politically sensitive regional gains and losses. Copyright Springer Science+Business Media, LLC 2007
Market Operations - M-401 Day-Ahead Market
- Iso California
- Operating Procedures