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The onshore Georgina Basin in northern Australia is prospective for unconventional hydrocarbons; however, like many frontier basins, it is underexplored. A well-connected hydraulic fracture network has been shown to be essential for the extraction of resources from the tight reservoirs that categorise unconventional plays, as they allow for economic flows of fluid from the reservoir to the well. One of the fundamental scientific questions regarding hydraulic stimulation within the sub-surface of sedimentary basins is the degree to which local and regional tectonic stresses act as a primary control on fracture propagation. As such, an understanding of present-day stresses has become increasingly important to modern petroleum exploration and production, particularly when considering unconventional hydrocarbon reservoirs. This study characterises the regional stress regime in the Georgina Basin using existing well data. Wellbore geophysical logs, including electrical resistivity image logs, and well tests from 31 petroleum and stratigraphic wells have been used to derive stress magnitudes and constrain horizontal stress orientations. Borehole failure features interpreted from wellbore image and caliper logs yield a maximum horizontal stress orientation of 044°N. Integration of density log data results in a vertical stress gradient of 24.6 MPa km–1. Leak-off and mini-fracture tests suggest that this is the minimum principal stress, as leak-off values are generally shown to be at or above the magnitude of vertical stress. The maximum horizontal stress gradient is calculated to be in the range of 31.3–53.9 MPa km–1. As such, a compressional stress regime favouring reverse/reverse–strike-slip faulting is interpreted for the Georgina Basin. [ABSTRACT FROM AUTHOR]