In sedimentary basins geothermal resources may coexist alongside hydrocarbon resources. The latter can represent a risk to geothermal exploration as experienced during the drilling of the deep St. Gallen geothermal well in eastern Switzerland. In this case, the unexpected occurrence of substantial amounts of natural gas, along with other external factors, prevented the continuation of the geothermal project. Therefore, this work aims at resolving the origin of the gas alongside evaluating the processes activating the petroleum system in the study area. In order to characterize the petroleum system of St. Gallen, we performed a basin analysis study aimed at reconstructing the thermal history of the basin and quantifying the main variables controlling the temperature in the basin: the paleo-heat flow and the magnitude and timing of the most relevant erosion events. The findings from this study indicate that the thermal conditions attained in the area were mostly controlled by the deposition of the Molasse units during the Oligocene-Miocene time. Older thermal events could not be detected by organic paleothermometers. An erosion thickness of 1800−2000m was estimated for the Molasse deposits, related to the uplift of the Northern Alpine foreland, occurring in the area most likely at 8−5 Ma. Results of thermal modelling revealed favourable conditions for the activation of a petroleum system in the St. Gallen area. The source rocks, located most likely in the Permo-Carboniferous grabens, are in the gas window. The model suggests that most of the hydrocarbons generated in the study area migrated northward, because of the southward dipping of the basin. According to the model only a small percentage of hydrocarbons were trapped in reservoirs, mostly located in the uppermost Permo-Carboniferous and basal Mesozoic units. Accumulations were simulated a few hundred meters below the final depth reached by the geothermal St. Gallen GT-1 well. From here the gas likely migrated into the overlying Mesozoic units, the target area of the well, where effectively the model predicts high petroleum saturation levels. This work demonstrates that the basin-scale thermal modelling approach adopted in this study should be incorporated into the feasibility and planning phase of future geothermal exploration campaigns to de-risk the subsurface manifestation of hydrocarbons.