Gas hydrate blockages pose an outstanding flow assurance challenge for hydrocarbon production with high watercuts because hydrate inhibition with thermodynamic inhibitors, such as methanol, often becomes economically and logistically unpractical. Some production wells can be prematurely terminated as a result of risks of hydrate blockages because subcooling in deepwater production is generally too high for kinetic hydrate inhibitors (KHIs) to be effective and it is commonly believed that anti-agglomerant hydrate inhibitors (AAs) are not designed to work at watercuts higher than 50%. To demonstrate the feasibility and principles for managing gas hydrate risks at high watercuts with AAs, systematic hydrate laboratory testing at various watercuts was conducted on a rocking cell apparatus. Results showed that the ability of an AA to prevent hydrate blockages at high watercuts strongly depends upon the brine salinity. Even though a small increase in the salinity does not shift the hydrate phase diagram by much, it can cause a step change in the performance of an AA at high watercuts. Hydrate problems in higher salinity systems are generally drastically easier to manage than in lower salinity systems even if they have the same subcoolings. It was also revealed that, when a thermodynamic hydrate inhibitor, such as methanol, is mandatory, a small dosage of AA in combination with methanol can significantly reduce the amount of methanol required.