Methodologies to predict the optimal end‐of‐tubing (EOT) location for wells with natural flow and artificial lift are proposed. The optimal EOT‐location methodology without artificial lift is validated with 2‐in.‐flow‐loop data and applied to synthetic field‐scale cases. This methodology postulates that the minimum Δptotal, defined as the difference between toe and wellhead pressure, should determine the optimal EOT location. The methodology is extended to incorporate reservoir coupling and liquid‐loading analysis to produce a more comprehensive EOT analysis. Liquid‐loading evaluation is necessary because the optimal EOT methodology might not indicate the liquid-loading potential in the well. In the case where reservoir potential is integrated into the methodology, maximizing the well's gas‐flow rates is used as the optimization criterion. The modification of the methodology to determine the optimal EOT location with installed gas lift or electrical‐submersible‐pump (ESP) system is demonstrated. Gas lift can be used to reduce the Δptotal and increase the in‐situ gas velocity to avoid liquid loading. In ESP systems, EOT location plays a role in preventing performance degradation, surging, or gas lock from occurring in the ESP by using the natural separation of liquid and gas at an appropriate EOT location.