Frequently, production from gas and gas condensate wells is negatively impacted by the wellbore accumulation of liquid – a mixture of water and condensate. As reservoir pressure and tubing gas velocity decline and produced water cut increases, heavier liquids can no longer be effectively removed from the wellbore, resulting in the liquid column build-up at the bottomhole. This creates additional backpressure on the producing formation and leads to gradual production decline, until the well completely stops producing – the condition widely known as "liquid loading". Use of smaller size tubing (velocity string) is often the simplest and most straightforward solution, but depending on reservoir properties (water cut, productivity and pressure) and well completion (vertical, slanted or horizontal) this approach may not be efficient. This paper describes the technical approach to resume continuous production from liquid-loading gas condensate wells at North Urengoy field. It is shown that Electric Submersible Pumps (ESPs) can be successfully applied to unload horizontal wells producing large amounts of water. In this application, water and condensate is lifted by the pump through the tubing string, while gas and condensate mixture is simultaneously produced through the annular space between the tubing and the casing. Reviewed in detail are the technical challenges of modeling the well and pump performance using dynamic multiphase flow simulators, and the ESP design for the pilot application in deep, horizontal gas condensate well in Russia.