Gas hydrate formation can result in the blockage of deepwater flowlines, leading to severe economic and safety risks. As oil and gas production moves to greater water depths, the operating conditions of high pressure and low temperature can lead to greater risks of hydrate formation in the flowlines. In addition, as the fields mature, the continuous increase of water cut further enhances the potential problems associated with hydrate formation. With these more challenging production conditions, antiagglomerants could offer an economical and environmentally attractive alternative for preventing hydrate plug formation. However, reported work on hydrate antiagglomerant behavior for moderate to high water content systems is quite limited. The work reported in this paper investigates the effects of Arquad 2HT-75 (used as a model antiagglomerant) and salt (NaCl) on water-in-oil emulsions, and explores the gas hydrate formation characteristics for moderate to high water content (50 and 75 vol %) crude oil using high-pressure differential scanning calorimetry (DSC). The results indicate that the formation and dissociation of both ice and hydrate could lead to destabilization of the water-in-oil emulsion under certain conditions. At a high water cut (75 vol %), hydrate conversion is much lower, because of mass-transfer limitations for hydrate formation. Furthermore, the DSC and bottle tests also suggest that, at the concentrations and conditions used in this work, the addition of salt to Arquad 2HT-75 can help to form stable water-in-oil emulsions.