The following sub-systems are provided and the integration of these is described below:

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2 The following sub-systems are provided and the integration of these is described below: Pretreatment Plant The Pretreatment Plant typically comprises an amine system for gas sweetening and a molecular sieve system for gas dehydration. These systems require heat and power (provided by the CHP plant) and cooling (provided by the Auxiliary Refrigeration plant) as well as providing fuel gas (for the Single Mixed Refrigerant gas turbine compressor drives). Heat is required for the amine reboiler (and reclaimer if provided) and for molecular sieve regeneration gas. Cooling is required to condense the bulk of water from the wet gas stream exiting the amine contactor before it enters the dehydration plant. This minimises the size of the molecular sieve vessels, reduces the regeneration gas flow required and allows regeneration at full system pressure. This allows regeneration gas to be used to fuel the gas turbine drives without the need for a recycle compressor or a fuel gas compressor. Water (and amine) condensed during cooling can be recycled and used as make-up in the amine plant. Fuel gas heating is provided by the CHP plant. Combined Heat and Power (CHP) Plant The CHP Plant comprises a waste heat recovery system (typically once through steam generator), a steam turbine generator, an auxiliary boiler, a process steam heating system and auxiliary plant. The CHP plant supplies the all the heat and power demands of the LNG plant as well as consuming off-gas from the process. Heat (steam) is used for the Pretreatment Plant and to heat fuel gas. Energy for the CHP plant is provided by waste heat from the SMR gas turbine drives with additional fuel from the re-liquefied BOG flash gas (low BTU) for either duct firing the gas turbine exhaust or for the auxiliary boiler. Flash gas from the amine system can also be used to fuel the boiler or for duct firing. Excess power over and above normal plant power demand, is used to power the Auxiliary Refrigeration plant. Power can also be exported from the LNG Plant. 2

3 Auxiliary Refrigeration Plant The Auxiliary Refrigeration Plant comprises an ammonia refrigeration system using multiple screw compressors driven by electric motors powered from the CHP Plant. The Auxiliary Refrigeration plant provides cooling for the Pretreatment Plant as described above. The inlet air to the gas turbine is also cooled by auxiliary refrigeration to substantially improve its performance. The balance and bulk of auxiliary refrigeration is used in the Single Mixed Refrigerant plant. This substantially improves the output and efficiency of the SMR process. Single Mixed Refrigerant (SMR) Plant The SMR Plant comprises a simple vapour compression cycle using a mix of refrigerants that provide a close fit of cooling curves in the main heat exchanger. The refrigerant compressor is driven by high efficiency low emissions aero-derivative gas turbines. Fuel for the gas turbines is provided by regeneration gas and by a small quantity of makeup feedgas. The main exchanger can be a multi-core brazed aluminium plate fin exchanger using a minimal number of streams. The performance of the main exchanger is substantially enhanced by the auxiliary refrigeration system. Boil-off Gas System The BOG System comprises low pressure compressors to recover flash and BOG from the LNG tank and a simple re-liquefaction and nitrogen rejection system to ensure the required LNG composition is met. The reliquefied BOG is flashed to allow the nitrogen to be removed along with some methane. This low BTU stream is used to fuel the CHP plant. Liquids Removal (optional) The feedgas may include heavy hydrocarbon components that need to be removed in order to meet the LNG specification. The CHP plant and Auxiliary Refrigeration plant can be used to assist in this process by supplying the necessary heating, cooling and power requirements. 3

4 Process Advantages The process described above has the following benefits over traditional LNG plants: Simplicity in design, construction and operation. Uses far less equipment and packaged items than conventional propane-mixed refrigerant or cascade processes. Uses the simplest of all liquefaction processes being single mixed refrigerant (SMR) and the simplest of all of the various versions of the SMR process. For instance, the main compressor comprises a single stage unit (no inter-stage cooler or scrubber, no gearbox, no helper motor) and the single mixed refrigerant stream comprises only 4 components. The cold box has only 3 main stream passes and 2 minor passes plus a 2 phase internal MR separator. High fuel efficiency and low emissions. Uses the most efficient proven gas turbine mechanical drive available which is 20% more fuel efficient than much larger industrial turbines used in traditional modern large-scale LNG plants. This alone results in a process which is more fuel efficient than conventional large-scale propane-mixed refrigerant processes. Integrated systems. Combined heat and power (CHP) technology uses waste heat from the gas turbines plus an auxiliary boiler fired with low Btu BOG to provide all electrical power (via steam turbine generator) and heating requirements for the plant. Part of this free energy is used to drive standard packaged ammonia refrigeration compressors which provides additional free refrigeration for: o gas turbine inlet air cooling (improves plant capacity by ~15%) o o process cooling (reduces size of dehydration plant and balances regeneration gas with GT fuel gas) cooling the CSG and MR in the cold box (improves plant capacity by 20% and efficiency by another 20%). Low cost and efficient liquefaction system. The mixed refrigerant system is designed to provide a close match on the cooling curves thereby maximising refrigeration efficiency. The additional ammonia refrigeration improves the heat transfer at the warm end of the main heat exchanger by increasing the LMTD which reduces the cold box size. 4

5 This also provides a cool MR suction temperature to the compressor which significantly improves the compressor capacity. The high refrigeration plant efficiency, use of CHP to meet all plant heat and electrical power requirements and the use of dry low emissions combustors in the gas turbines, results in very low overall plant emissions. In addition, the plant is designed to avoid flaring during normal operation and during ship loading. Efficient BOG recovery. The BOG system recovers flash gas and BOG gas generated from the LNG tank and from ships during loading. This gas is compressed in 2 stage centrifugal BOG compressors to only ~6 bara where is it re-liquefied in the cold box to recover methane as liquid. The methane returns to the LNG tank and the flash gas which is concentrated in nitrogen is used for boiler fuel. This is a cost effective and energy efficient way of dealing with BOG and rejecting nitrogen from the system, and at the same time minimise or eliminate flaring during ship loading. Lower plant capital and operating/maintenance costs. Less equipment items and modular packages results in reduced civil, mechanical, piping, electrical and instrumentation works and fast construction schedule; all of which contribute to reduced costs. This results in simple operations requiring less operating and maintenance staff. The majority of maintenance costs are dedicated to the gas turbine drives so the use of aero-derivative gas turbines substantially reduces maintenance costs. High reliability, availability and maintainability (RAM). The high plant RAM, compared to alternative processes, is principally due to the two separate, independent and parallel liquefaction circuits utilizing highly reliable aero-derivative gas turbine drives, combined with using minimal equipment items. Although the process is highly integrated, the failure of any item will not cause a plant shutdown. For instance, the plant will continue to operate if the complete ammonia plant (which has 6 compressors in parallel) shuts down or if the OTSG and steam turbine generator shuts down. Full plant power is provided by a reliable steam turbine system and is backed-up by the mains utility grid. The installation of spare rotating equipment (other than the main gas turbine/compressors and steam turbine generator), careful selection of key rotating equipment and holding of critical spare parts items in-stock also contribute to high RAM. For instance, the main gas turbine aero-derivative engines can be quickly changed over as is the case with all aero-derivative gas 5

6 turbines. Low maintenance reliable centrifugal equipment (for MR and BOG compressors; amine and boiler pumps) have been selected as opposed to less reliable reciprocating machines. Selection of membrane tank. A membrane tank consists of a thin stainless steel primary container (membrane) together with thermal insulation and a concrete tank which jointly form an integrated composite structure, to provide the liquid containment and transfer hydrostatic and other loadings to the outer concrete tank. The concrete tank is slip-formed resulting in a very fast and economical method of construction. The quantity of low temperature alloy steel and associated welding required for the inner tank is less than 10% of that required for a traditional nickel steel tank. The risks associated with membrane tanks are similar to that of full containment tanks. The overwhelming benefit of a membrane tank is the capital cost which is around half that of full containment tanks and a schedule saving of around 8 months. Fast construction schedule. The use of modular shop fabricated packages and selection of standard equipment items where possible, allows an accelerated schedule. Long lead equipment items such as the MR compressor, gas turbine, cold box and BOG compressor have deliveries of under 18 months, although this will need to be confirmed at the time of order. In summary, the above advantages result in the following project cost (Dec-08) and efficiency which surpass all other LNG processes including those of a much larger scale: EPC Capital cost of US$500m for 1.5mtpa which equates to USD330/tpa including the disproportionately large LNG storage capacity versus plant production rate. Plant energy consumption which consumes ~7.0% of feedgas in energy terms including all utility systems. 6