Search

This paper provides a new methodology to compute a reduced but efficient set of candidate lines in a transmission expansion planning (TEP) context. Considering this reduced set of candidate lines should lead to similar investment decisions as if all the possible ac and dc candidate lines that could be installed in the network were considered. A first “hybrid” relaxed TEP problem is solved. Based on this initial solution, a new relaxed TEP problem is iteratively solved in which the dc load flow (DCLF) model is enforced to a certain extent in the partially expanded ac corridors. Once a convergence threshold has been reached, an upper bound of the number of candidate ac and dc lines to install in each corridor can be defined. This process results in a compact search space. Our algorithm has been implemented in General Algebraic Modeling Software (GAMS) and has been tested on a case study based on the European power system. The method produces very promising results and in the considered case study, leads to a very efficient investment. [ABSTRACT FROM AUTHOR]

This paper provides a new methodology to compute a reduced but accurate network representation in a transmission expansion planning (TEP) context. Considering this reduced network should lead to the same investment decisions as if the whole original network were considered. A set of relevant lines to be preserved is defined based on a proxy of the TEP solution. An optimal network partition, resulting from solving the multicut problem, is computed in such a way that the two ends of each of these relevant lines are allocated to two different areas. An iterative Kron reduction is then applied to each area to eliminate most of the buses that are not connected to any interarea line. This two-step process results in a compact but representative reduced network. Our algorithm has been implemented in General Algebraic Modelling Software and Matrix Laboratory and has been tested on the standard IEEE 118 bus system and a case study based on the European power system. The method produces very promising results and, in the considered case studies, leads to the same, or equally efficient, investment decisions and essentially the same total costs as when considering the whole original network. [ABSTRACT FROM AUTHOR]

This paper provides a novel technique to represent in a reduced, or compact, way temporal variability in transmission expansion planning (TEP). This reduction is handled by means of “snapshot selection.” Instead of taking into account all the possible operational states and their associated optimal power flow, a reduced group of them is selected that is representative of all the states that should have an influence on investment decisions. Considering this reduced group of operational states should lead to the same investment decisions as if all the snapshots in the target year were considered. Original operational states are compared in the space of the benefits produced by potential reinforcements considered, which are relevant drivers for investment decisions. The benefits produced by these potential reinforcements are computed based on the incremental change in operation costs resulting from their installation. A clustering algorithm is used to group together those operational states where similar line benefits are realized. Our algorithm has been tested on a modified version of the standard IEEE 24 bus system. The method produces promising results and proves to be more efficient than other snapshot selection methods used until now in computing an accurate enough selection of snapshots representing system operation variability in TEP. [ABSTRACT FROM AUTHOR]

Transmission charges aim to recover the cost of transmission network investments and provide efficient locational signals to new generators. In this paper, we investigate the effect of these charges on the development of new generation capacities in the system. Generation expansion planning is decided by strategic generation planners (SGPs) trying to maximize their profits, while transmission line investments are planned by a central planner and regulatory body aimed at minimizing the overall operation and network investment costs of the system. Regulatory transmission charges (RTCs) are calculated according to the marginal responsibility of generation investment on transmission network investment costs. An iterative algorithm is proposed to model the interaction taking place between the central planner and SGPs. The developed methodology is applied to a 2-node illustrative example and the IEEE-RTS96, and effects of RTCs on investment decisions of SGPs are analyzed. [ABSTRACT FROM AUTHOR]

The marginal value of transmission lines in the dispatch is widely used in the literature and has relevant practical applications related to planning the expansion of the transmission grid and computing the remuneration of merchant lines. This paper presents a general formulation of the marginal value of a line in the dispatch that highlights the dependence of this value on the link between line admittance and capacity. We discuss the value of a line according to marginal principles following a general approach and prove that only if the admittance of a line can be expressed as a linear function of its capacity, or when admittance and capacity can be deemed independent, is this value equal to the product of the difference between marginal electricity prices at both ends of the line and the flow through this line. Afterwards, we show that under a set of stylized conditions the remuneration of efficient network investments according to their marginal value in the dispatch should result in an exact recovery of their cost. Finally, we compute the marginal value of lines in a stylized, though representative, system for several relationships between line capacities and admittances to illustrate the theoretical results obtained. [ABSTRACT FROM PUBLISHER]

Parties to the Internal Electricity Market of the European Union (IEM) decided in 2001 to abolish the method of pan-caking of transmission tariffs for cross-border transactions that was originally in place. Instead, they have agreed to implement a system whereby national transmission tariffs provide access to the entire IEM. This system is supplemented by a scheme of inter-TSO payments. However, conflict may arise if the compensation that a country must pay another one is not in accordance with the electrical usage that the former is making of the grid of the latter. For instance, Inter TSO Compensation methods (ITC methods) implicitly allocate the cost of any existing or new transmission line. Therefore, the adoption of an inefficient method may be an obstacle for building some needed regional grid investments. Consequently, one should give careful consideration to the selection of the ITC method. This paper analyzes, both qualitatively and quantitatively, the implementation of the most relevant ITC methods that have been considered so far in the European debate. When assessing each method from a conceptual point of view, considerable attention is devoted to the critical examination of its main underlying assumptions. [ABSTRACT FROM AUTHOR]

Electricity transmission contracts allocate scarce resources, allow hedging against locational price differences, and provide information to guide investment. However, ownership of transmission contracts might enhance market power of strategic generators. If the allocation mechanism for transmission contracts does not prevent generators from obtaining market power-enhancing contracts, explicit restrictions on owning transmission contracts might be required. To ensure that these restrictions do not interfere with the need to hedge for transmission price risk, one proposal is to define all transmission contracts to a balancing point at which energy is traded. Generators are only allowed to own transmission contracts toward this balancing point. Traders or load hedge the price risk from this balancing point to the location of load with transmission contracts. We propose an algorithm and apply it to the European electricity network to identify a balancing point that reduces market power of generation companies and is well connected. Market-level data or detailed information about demand are not required. The only critical input is assumptions on future transmission constraint patterns. [ABSTRACT FROM AUTHOR]

This paper investigates the application of adaptive control to the Spanish load-frequency regulation scheme, Automatic Generation Control (AGC). The Spanish AGC system regulates the frequency and the power exchange between France and Spain. The system is hierarchically structured with one master regulator that coordinates four control areas. Each control area is composed of several generating units providing AGC service. Co-ordinating signals are sent to the control areas so that the global system response achieves the objective established by the System Operator. The participation of each control area in the service is set according to the rated share that it has obtained in the secondary-reserve market and its relative response speed compared to that of the rest of the control areas. Some problems, such as the lack of sensitivity to the quality of the reserve provided by the control areas, have been detected in the operation of the current AGC scheme. A new design, which is presented in this paper, has been developed in order to overcome these problems. This paper attempts to outline how this new design improves the global AGC system response and the distribution of the regulation effort among the control areas. The proposed strategy is compared with the present design by means of simulation. [ABSTRACT FROM AUTHOR]

Growing load factors in winter and summer peaks are a serious problem faced by the Spanish electric energy system. This has led to the extensive use of peak load plants and thus to higher costs for the whole system. Wind energy represents a strongly increasing percentage of overall electricity production, but wind normally does not follow the typical demand profile. As generation flexibility is limited due to technical restrictions, and in absence of large energy storages, the other side of the equilibrium generation-demand has to react. Demand side management measures intend to adapt the demand profile to the situation in the system. [ABSTRACT FROM PUBLISHER]