Most of the market models have some means of pricing out spinning reserves or nearline capacity and other ancillary services that aren't necessarily spinning a meter. Unfortunately trying to determine the correct price incentives is complicated and it often only becomes apparent a serious mistake was made after an event. One element of this is that overall US power grid and associated infrastructure was hugely over-engineered from like 1940-1980 and some areas are only recently pushing the limits of 1960s era transmission and generation planning, in many cases because old nasty coal plants are closing and non-dispatchable renewables are cropping up at locations power plants wouldn't have made sense historically.
Other market operators in north America have different means of doing it. PJM's capacity market strategy ( https://pjm.com/markets-and-operations/rpm.aspx ) has been a reasonably successful, at least so far. CAISO has their resource adequacy planning but the changes in the western interconnect have been seriously straining both the market model and the reliability coordination in parts of California. Can't dig up a good link right now but there has been some discussion that one problem with ERCOT's forecasting was that it assumed demand stopped increasing once it reached a cold-weather ceiling, which may or may not have contributed to lack of early action in the 2021 storm. But they also have no good means of early opportunistic demand reduction, which might have trimmed several GW off peak demand during the storm as many empty buildings and industrial users were still up and running with no one able to safely go to the facilities and safely shut down unimportant loads.
I remain personally of the opinion that if it takes increasingly complicated rules and financial structures to get the desired results, that maybe the modern US concept of a deregulated power market isn't such a great idea to begin with, but it's not going away any time soon.