The Nappamerri Trough in the Cooper Basin has long been recognised as a potential unconventional resource play with both deep-basin (Hillis et al. 2001) or basin-centred gas, and, more recently, as a potential shale gas target. However, initial attempts to fracture stimulate sandstones on conventional structural highs in and around the trough proved difficult. High treating pressures reached the limits of the well designs, and unsuccessful stimulation treatments resulted. A review of geomechanical information suggested that fracture complexity might have resulted from fractures initiating vertically and then twisting off to horizontal further into the reservoir (Nelson et al. 2007). From 2010 to 2012, Beach Energy undertook a two-well exploration drilling program aimed at assessing the shale gas potential of the Nappamerri Trough and proving the presence of gas outside of structural closure. The wells were initially planned to gather base geological information from the core, but it was recognised that key fracture stimulation uncertainties could be addressed by these wells that would have significant benefit for future well design. With the knowledge gained from previous stimulation treatments, the wells were designed to incorporate Acid-soluble cement to improve the connection to the reservoir A fracture completion string—wellhead and pumping equipment suitable for higher treating pressures A surface tiltmeter monitoring array to ascertain whether treatments were twisting into the horizontal plane The two wells, Holdfast-1 and Encounter-1, were successfully stimulated with 13 different treatments. This paper summarises the interpretation of the treating pressure data and the tiltmeter responses. Through diligent pre-project planning, the observed treating pressures were manageable, although higher than pressure gradients in other published shales and tight-gas areas. Large near-wellbore (NWB) pressure losses in most intervals were successfully reduced to allow treatments to be placed using moderately low viscosity fluids. The interpretation of the tiltmeter array data indicated predominately vertical fracture development, which is a positive outcome for maximising stimulated reservoir volume (SRV) in future horizontal wells. However, the fracture orientation determined from the tiltmeters was not consistent with the anticipated maximum stress orientation from borehole logs and regional studies, and further investigation is required to resolve this difference.