The ever-increasing demand for oil and gas has driven its exploration in rather extreme conditions. In Lamu offshore, which is hitherto underexplored, most of the wells already drilled turned out dry save for a few wells with hydrocarbon shows despite the promising reservoir properties and related geological structures. This, therefore, necessitated a source rock evaluation study in the area to ascertain the presence and potential of the source rock by integrating the geochemical data analysis and petroleum system modeling. The shallow Lamu offshore source rock quantity, quality, and maturity have been estimated through the determination of the total organic carbon (TOC) average values, Kerogen typing, and Rock-Eval pyrolysis measurements respectively. Geochemical data for Kubwa-1, Mbawa-1, Pomboo-1, and Simba-1 were evaluated for determining the source rock potential for hydrocarbon generation. Petroleum system modeling was applied in evaluating geological conditions necessary for a successful charge within a software that integrated geochemical and petrophysical characterization of the sedimentary formations in conjunction with boundary conditions that include basal heat flow, sediment-water interface temperature, and Paleo-water depth. The average TOC of 0.89 wt % in the study area suggests a fair organic richness which seems higher in the late cretaceous (0.98 wt %) than in the Paleocene (0.81 wt %). Vitrinite reflectance and Tmax values in the study area indicate the possible presence of both mature and immature source rocks. Type III Kerogen was the most dominant Kerogen type, and gas shows are the most frequent hydrocarbon encountered in the Lamu Basin with a few cases registering type II/III and type II. The charge properties (i.e. Temperature, transformation ratio, and Vitrinite reflectance) over geologic time at each of the wells have been estimated and their spatial variation mapped as seen from the burial history and depth curves overlaid with temperature, transformation ratio, and Vitrinite reflectance respectively. From the upper cretaceous maturity maps, the results seem to favor near coastal regions where average TOC is about 1.4 wt %, Vitrinite reflectance is more than 0.5%, transformation ratio is more than 10%, and temperatures range from 80°C to 160°C. The results postulate the absence of a definitive effective source rock with a likelihood of having cases of potential and possible source rocks. Moreover, greater uncertainty rests on the source rock’s presence and viability tending toward the deep offshore. Geochemical analysis and petroleum system modeling for hydrocarbon source rock evaluation improved the understanding of the occurrence of the possible and potential source rocks and processes necessary for hydrocarbon generation.