The estimation of reservoir properties from seismic amplitude is, generally, an underdetermined problem, which can result in ambiguous estimation of the sought-for properties. Although seismic reflectivity is dependent upon formation P- and S-wave velocities and density, it is common practice to estimate only two attributes from prestack P-wave data because of data limitations at far offsets and instabilities of inversion. On the other hand, the number of petrophysical properties that determine reservoir storability and production are four, in the simplest of cases: porosity, lithology, pore fluids (type and amount), and permeability. Ambiguity and risk reduction require the inclusion of additional, robust information into the estimation of reservoir properties. This is particularly true in formations where reservoir storability and production depend on additional petrophysical properties, as would be the case of unconventional plays where brittleness and vertical fracture density and orientation are factors that determine reservoir performance. In this study, rock properties are estimated through PP-PS joint inversion and estimation of S-wave anisotropy. Data from the Marcellus Shale in Pennsylvania are used to illustrate risk reduction in qualitative estimation of total organic content (TOC) and fractures characterization.