Market power remains a persistent challenge in many liberalized electricity markets worldwide, driving the adoption of ex-ante and ex-post mitigation measures. Despite locational mitigation tools (e.g., cost-based reference levels or default energy bids), evidence of price manipulation has motivated system-level market power mitigation (MPM) policies. However, the full implications of these rules are not well understood, and limited insight into participant behavior can lead to unintended consequences, including increased market power and welfare losses. We study sequentially cleared electricity markets and analyze a two-stage settlement structure commonly used by system operators (e.g., day-ahead and real-time markets in North America). Our focus is on MPM policies that replace noncompetitive generator offers with operator-estimated default bids, and we model competition between generators and loads with inelastic energy requirements who act strategically in allocating demand across stages under real-time, day-ahead, and simultaneous applications of MPM policies. Motivated by the loss of Nash equilibrium under conventional supply-function bidding, we adopt an alternative mechanism in which generators bid the intercept of an affine supply function. Under real-time MPM, strategic interaction in the day-ahead market drives all demand to real time, producing an undesirable outcome. To test robustness, we incorporate demand uncertainty using a variance-penalized expectation framework. Low risk aversion still leads to substantial real-time clearing, while imbalances in risk preferences further amplify market power. Overall, intercept-function bidding combined with day-ahead and simultaneous MPM policies mitigates generator market power more effectively than real-time substitution alone, although these policies shift some market power toward loads.
