This paper presents a new framework to study the generation capacity expansion in a multi-stage horizon in the presence of strategic generation companies (GENCOs). The proposed three-level model is a pool-based network-constrained electricity market that is presented under uncertainty in the predicted load demand modeled by the discrete Markov model. The first level includes decisions related to investment aimed to maximize the total profit of all GENCOs in the planning horizon, while the second level entails decisions related to investment aimed at maximizing the total profit of each GENCO. The third level consists of maximizing social welfare where the power market is cleared. The three-level optimization problem is converted to a one-level problem through an auxiliary mixed integer linear programming (MILP) using primal-dual transformation and Karush-Kuhn-Tucker (KKT) conditions. The efficiency of the proposed framework is examined on MAZANDARAN regional electric company (MREC) transmission network-a part of the Iranian interconnected power system. Simulation results confirm that the proposed framework could be a useful tool for analyzing the behaviour of investment in electricity markets in the presence of strategic GENCOs.Keywords: Generation expansion planning, mathematical programming of equilibrium constraints problem, dynamic planning, strategic GENCO, uncertainty, three-level model. Nomenclature

Wind energy integration into microgrids, has introduced new challenges to energy management systems because of its intermittent behaviour. Owing to continuous changes in generation and consumption, the energy price is volatile. This study proposes a new two-stage stochastic framework for day-ahead scheduling of microgrids. Uncertainties associated to wind power generation, real-time electricity price and load demand are considered. Different scenarios are generated using autoregressive moving-average method and then are reduced using fast-forward technique. On the first stage, the microgrid master controller determines the procured energy from the day-ahead market and commitment states of distributed energy resources (DERs). In the second stage, the purchased energy from the real-time market and schedules of committed DERs are obtained. The problem is modelled using mixed-integer linear programming approach and is solved via CPLEX ® optimizer. Both grid-connected and stand-alone modes of operation are investigated. Despite of high operation cost in island mode, coordination of energy storage systems, incentive-based and price-based demand response (DR) programmes affect economy of microgrids. The framework is examined on a test microgrid. Results show that both of the releasing the microgrid master controller authority and DR resources result in significant saving in operating; especially in emergency conditions such as islanded mode.

This paper presents the analysis of a novel framework of study and the impact of different market design criterion for the generation expansion planning (GEP) in competitive electricity market incentives, under variable uncertainties in a single year horizon. As investment incentives conventionally consist of firm contracts and capacity payments, in this study, the electricity generation investment problem is considered from a strategic generation company (GENCO) ′ s perspective, modelled as a bi-level optimization method. The first-level includes decision steps related to investment incentives to maximize the total profit in the planning horizon. The second-level includes optimization steps focusing on maximizing social welfare when the electricity market is regulated for the current horizon. In addition, variable uncertainties, on offering and investment, are modelled using set of different scenarios. The bi-level optimization problem is then converted to a single-level problem and then represented as a mixed integer linear program (MILP) after linearization. The efficiency of the proposed framework is assessed on the MAZANDARAN regional electric company (MREC) transmission network, integral to IRAN interconnected power system for both elastic and inelastic demands. Simulations show the significance of optimizing the firm contract and the capacity payment that encourages the generation investment for peak technology and improves long-term stability of electricity markets.

Summary This paper proposes a new concept for limiting fault current in distribution systems with interline bridge‐type fault current limiter (IBFCL). It includes two or more BFCLs connected to only a common limiting resistor in DC link, which result in considerable cost saving. This configuration is inserted in series with feeders connected to a point common coupling (PCC). At first, the principle and characteristics of IBFCL are described. Then, a theoretical analysis of limiting performance and parameter design of the IBFCL is explained. Finally, the performance of the IBFCL for limiting fault current is validated on the distribution system comprising of parallel feeders connected to PCC through electromagnetic simulations by PSCAD/EMTDC under symmetrical and asymmetrical faults as well as different load current conditions. Simulation results show that the IBFCL provides a cost‐effective approach for limiting fault current in distribution system.

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