Analysis of reserve relaxations in electric energy markets

Electric power grids are some of the most complex engineering systems today. System operators must manage generation fleets with complex operating requirements and transmission assets spanning thousands of miles, while maintaining synchronism and meeting strict reliability criteria. Given the limited computational capabilities of modern computers, the Independent System Operators (ISOs) and Regional Transmission Organizations (RTOs) cannot fully integrate all of these complexities in their market model. Thus to ensure scalability, ISOs and RTOs employ a number of approximations within their market models, including proxy reserve requirements that attempt to achieve, but does not guarantee, N − 1 reliability. Since the market model is an approximate model itself, and the solution needs to be corrected nevertheless, market management tools allow select constraints to be relaxed for a set penalty price. This paper examines the impacts of different penalty price schemes, for relaxation of reserve requirements, on system N − 1 reliability and market outcomes. In particular, the post contingency network violations for the relaxed and non-relaxed market solutions are compared. Moreover, the final cost after making necessary corrections to arrive at the N − 1 secure solutions are presented and compared for the relaxed and non-relaxed cases. The paper demonstrates that reserve relaxation does not significantly increase post contingency violations for the market solution or the total system cost after the adjustment phase. Thus, if performed for appropriate reasons such as controlling price or achieving feasibility, reserve relaxation is a justifiable practice in power system operations.