There are substantial economic and operational incentives to reduce the volumes of thermodynamic inhibitors (THIs) injected in deepwater oil and gas pipelines to a minimum threshold necessary to achieve a flowable hydrate slurry and prevent hydrate deposition; however, there is uncertainty about whether this underinhibited condition may worsen hydrate transportability and increase plugging potential. In this study, hydrate formation rate and hydrodynamic pressure drop were measured over a range of temperatures and subcoolings using a one-inch single-pass flowloop containing aqueous monoethylene glycol (MEG) solutions (040 wt %) at a liquid loading of 5 vol % and a synthetic natural gas at an initial pipeline pressure of 10.3 MPa (1500 psia). Measured average formation rates in this gas dominant flow were within a factor of 2 of the kinetic rate and about 250 times faster than that expected for oil dominant flows. When the system was underinhibited with MEG, the pressure drop behavior over time was consistent with a proposed conceptual description for hydrate plugging in gas-condensate pipelines based on the mechanisms of stenosis (narrowing of the pipeline due to the deposition of a hydrate coat at the pipe wall) and sloughing (shear breaking of the hydrate deposits). The results from experiments performed at constant temperature showed that increasing the MEG dosage reduced hydrate formation rates and improved hydrate transportability. However, at decreasing temperatures, increasing the concentration of MEG to maintain a constant subcooling (and formation rate) appeared to promote hydrate sloughing. In certain experiments, it was possible to estimate the average deposition rate over the entire flowloop in addition to the average formation rate. Although formation rates were correlated with subcooling (rather than MEG concentration), the deposition rates were constant over the subcooling range (3.1 to 5.5 degrees C) achieved with MEG concentrations of 0 to 20%.