TECHNOLOGY FOCUS - ORGANIC CHEMISTRY - Preferred Process: The step (B) utilizes Selexol (RTM: acid gas remover comprising dimethyl ether of polyethylene glycol) or Rectisol (RTM: acid gas remover comprising methanol) absorber to capture the carbon dioxide. The step (E) utilizes an amine absorber or potassium carbonate absorber to capture the carbon dioxide. The steps (B) and (F) utilize a pressure swing adsorber (PSA) unit to purify the hydrogen. The step (F) utilizes a hydrogen membrane optionally in combination with the PSA unit, where high purity hydrogen (greater than 99% pure) is recovered from PSA unit and lower purity hydrogen is recovered from the hydrogen membrane. The hydrogen stream from step (F) is greater than 99% pure. The portion of the recycled purge gas stream from step (G) is (less than 10, preferably less than 5)% of the overall recycled purge gas stream. The process (P1) involves a step of feeding hydrogen, distillate stream from step (A) and a naphtha stream separated from light ends of step (A) to a hydrotreating/hydrocracking facility and naphtha, diesel and vacuum gasoil are obtained. At least part of hydrogen produced in step (B) and hydrogen produced in step (F) which are greater than 99% pure are utilized in the coal liquefaction facility. EXAMPLE - Illinois No. 6 coal (8000 standard conditions for temperature and pressure (STPD) on dry basis) was processed in H-Coal-TS direct coal liquefaction process (DCL) facility to produce finished products including LPG, butanes, gasoline, ultra low sulfur diesel (ULSD) and low-sulfur fuel oil product. The raw liquids from DCL Plant were further upgraded in standard refinery operations. A prior art treatment method was compared with test process. In the comparative process, unconverted coal, heavy liquefaction residue and supplemental coal were fed to gasification plant to provide plant hydrogen. Fuel gas was produced from H-Coal-TS unit, secondary hydroprocessing units, and gasification pressure swing absorber (PSA) tail gas. CO2 capture was utilized in gasification plant to attain 87% capture of total CO2 produced in gasification plant and 75% of total liquefaction facility. The plant fired heaters were fueled by blend of gasifier tail gas and process generated fuel gases. There was no steam methane reformer (SMR) unit and all hydrogen was generated via gasification of H-Coal bottoms and supplemental coal. It was observed that the process required 1972 STPD of supplemental coal feed to gasification to provide total plant hydrogen requirements (224 mM standard cubic feet/day (SCFD)). The total CO2 emitted to the atmospheric was 2847 STPD. In test process, SMR unit was added to process fuel gas from plant, tail gas purge from PSA unit in gasification complex, and tail gas from PSA unit that was part of this SMR unit to produce hydrogen and capture the CO2 produced. The SMR furnace was fed by SMR produced hydrogen and small quantity of SMR PSA tail gas. It was observed that 137.5 mM SCFD of hydrogen (99.9 vol.% purity) was produced in the SMR Unit. This hydrogen was used as follows: 55 mM SCFD to the SMR furnace, 55.6 mM SCFD to liquefaction complex fired heaters (in place of fuel gas), and 26.9 mM SCFD to process plants including liquefaction reactors. The latter hydrogen reduced that required from gasifier and resulted in lower supplemental coal required. The supplemental coal to gasifier was reduced from 1972 (prior art process) to 1437 STPD with significant investment and operating cost savings. The SMR unit also produced a large quantity of steam and could replace coal or natural gas fired boiler as prior art comparative process. The net plant power consumption for test process was significantly higher than prior art comparative process as result of higher hydrogen compression duty and less high pressure steam which was letdown via steam turbines. With power provided via combined cycle gasification with CO2 capture, affect on total CO2 emitted (included imported power) was minimal. The addition of the SMR unit and use of produced hydrogen for fired heaters resulted in a 27% reduction in quantity of supplemental coal to gasifier and increased CO2 recovered from 75 to 97.6%. This was accomplished with small effect on overall plant investment.