Electricity system models are widely used to study future designs for power markets. They are commonly used to represent electricity dispatch decisions but struggle to reproduce realistic variation in prices. We show that current assumptions of generators bidding short-run marginal cost underestimates the spread and volatility of hourly wholesale prices. Imperfect competition makes market prices differ from the theoretical optimum. Therefore, a simple modification to the short-run marginal cost approach is considered in a way that allows generators to make a spread of bids. Additionally, we add volatility into the model by making a post-optimizer transformation in the cost function. The objective is to propose a model to simulate prices on day-ahead markets that accounts for generators’ ability to bid below marginal costs for their first megawatts of capacity and above for their last, as well as to consider other variables that have an impact on power prices and that cannot be captured by the typical approaches. Using this method, we show the impacts of price volatility and price spreads in the power market.