We have developed a new pore-scale method to quantify petrophysical properties of hydrocarbon (HC)-bearing shale. Recent studies indicate that slip flow, Knudsen diffusion, Langmuir desorption, and diffusion in kerogen contribute to the unconventional production properties of shale-gas formations. Conventional petrophysical interpretation methods do not account for the aforementioned phenomena and are often inconclusive when estimating petrophysical properties in shale formations. We constructed a pore-scale representation of the lower Eagle Ford Shale based on focused-ion-beam–scanning-electron-microscope (FIB-SEM) images. Permeability is calculated via previously developed finite-difference methods for the cases with and without slip flow and Knudsen diffusion. The method also calculates streamlines to describe sample pore connectivity. Weighted throat-size distributions are defined based on streamlines to represent the most resistive paths for fluid flow in the FIB-SEM image. Subsequently, permeability is estimated from the dominant throat size in the weighted throat-size distribution. We used a new fluid percolation model for HC-bearing shale that expands HC from kerogen surfaces and water from grain and clay surfaces into the pore space to vary fluid saturation. Isolated pores are randomly distributed within kerogen to increase kerogen maturity in the model. Electrical resistivity is calculated with a finite-difference solution of Kirchhoff’s voltage law applied at the pore scale. A parallel conductor model was used based on Archie’s equation for water conductivity in pores and a parallel conductive path for the Stern-diffuse layer. Calculations were compared with Waxman-Smits’ and Archie’s predictions of macroscopic electric conductivity. Using practical modeling parameters, the parallel conductor model yields the most accurate prediction of pore-scale sample conductivity for various cases of water saturation and conductivity.