Detailed California-Modified GREET 

Pathway for Liquefied Natural Gas (LNG) 

from North American 

and Remote Natural Gas Sources 

Stationary Source Division 

Release Date: July 20, 2009 

Version 1.0 
The Staff of the Air Resources Board developed this preliminary draft 

version as part of the Low Carbon Fuel Standard regulatory process 

The ARB acknowledges contributions from Life Cycle Associates (under 

contract with the California Energy Commission) during the development of 

this document 

When reviewing this document, please submit comments directly to: 

Anil Prabhu: aprabhu@arb.ca.gov

Chan Pham: cpham@arb.ca.gov

Alan Glabe: aglabe@arb.ca.gov

Gregory McMahan: gmcmahan@arb.ca.gov

Joe Fischer: jofische@arb.ca.gov

These comments will be compiled, reviewed, and posted to the LCFS 

website in a timely manner.
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TABLE OF CONTENTS 

Table of Contents........................................................................................................... i

List of Figures ............................................................................................................... ii

List of Tables ................................................................................................................. ii

Summary........................................................................................................................ 1

CA-GREET Model Pathway for LNG from North American Natural Gas and Remote 

Natural Gas.............................................................................................................. 2

APPENDIX A1 (SCENARIO 1)....................................................................................... 6

LNG FROM NORTH AMERICAN NG ............................................................................. 6

SECTION 1. NATURAL GAS RECOVERY .................................................................... 7

1.1 Energy Use for Natural Gas Recovery ............................................................... 7

1.2 GHG Emissions from NA Natural Gas Recovery .............................................. 7

SECTION 2. NATURAL GAS PROCESSING ................................................................ 9

2.1 Energy use for Natural Gas Processing............................................................. 9

2.2 GHG Emissions from Natural Gas Processing................................................... 9

SECTION 3. NATURAL GAS TRANSPORTATION AND DISTRIBUTION.................. 10

3.1 Energy Use for NG Transport to LNG Plants in California ............................... 10

3.2 GHG Emissions from Natural Gas Transport to LNG Plants in California........ 10

SECTION 4. NATURAL GAS LIQUEFACTION TO LNG............................................. 11

4.1 LNG Liquefaction Energy Use.......................................................................... 11

4.2 GHG Emissions from Natural Gas Liquefaction to LNG in California............... 12

SECTION 5. LNG TRANSPORT, DISTRIBUTION, AND STORAGE........................... 13

5.1 LNG Truck Transport Summary ....................................................................... 13

5.2 LNG Truck Transport Energy Consumption ..................................................... 13

5.3 GHG Emissions from Truck Transport of LNG................................................. 14

5.4 GHG Emissions from Storage of LNG.............................................................. 16

SECTION 6. GHG EMISSIONS FROM VEHICLES...................................................... 17

6.1 LNG Composition............................................................................................. 17

6.2 GHG Emissions from Vehicles......................................................................... 17

APPENDIX A2 (SCENARIO 2)..................................................................................... 18

LNG FROM REMOTE SOURCES, SHIPPED TO BAJA, RE-GASIFIED, 

PIPELINED TO CA, LIQUEFIED IN CA................................................................. 18

SECTION 1. REMOTE NATURAL GAS RECOVERY, PROCESSING AND 

TRANSPORT TO LNG PLANT .................................................................................... 21

1.1 Remote NG Recovery and Processing ............................................................ 21

SECTION 2. REMOTE NATURAL GAS LIQUEFACTION TO LNG............................. 22

2.1 Liquefaction Energy Use .................................................................................. 22

2.2 GHG Emissions from Natural Gas Liquefaction to LNG................................... 23

SECTION 3. LNG TRANSPORT TO CALIFORNIA, DISTRIBUTION, REGASIFICATION, TRANSPORT, AND STORAGE WITHIN CALIFORNIA ................... 24

3.1 LNG Transport via Ocean Tanker .................................................................... 24
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3.2 Re-gasification ................................................................................................. 26

3.3 Pipeline Transport to CA under Scenario 2...................................................... 28

3.4 Liquefaction in California.................................................................................. 29

3.5 LNG Transport and Storage in California ......................................................... 29

SECTION 4. GHG EMISSIONS FROM VEHICLES...................................................... 30

4.1 Tank To Wheel (TTW) GHG Emissions ........................................................... 30

APPENDIX A3 (SCENARIO 3)..................................................................................... 31

LNG FROM REMOTE SOURCES, SHIPPED TO BAJA, TRUCKED TO CA ........ 31

SECTION 1. REMOTE NATURAL GAS RECOVERY, PROCESSING AND 

TRANSPORT TO LNG PLANT .................................................................................... 35

1.1 Remote NG Recovery and Processing ............................................................ 35

SECTION 2. REMOTE NATURAL GAS LIQUEFACTION TO LNG............................. 36

2.1 Liquefaction Energy Use .................................................................................. 36

2.2 GHG Emissions from Natural Gas Liquefaction to LNG................................... 36

SECTION 3. LNG TRANSPORT TO BAJA, THEN TRUCKED AND STORAGE 

WITHIN CALIFORNIA .................................................................................................. 37

3.1 LNG Transport via Ocean Tanker .................................................................... 37

3.2 LNG Transport and Storage to California from Baja, Mexico to California ....... 37

SECTION 4. GHG EMISSIONS FROM VEHICLES...................................................... 38

4.1 Tank To Wheel (TTW) GHG Emissions ........................................................... 38

APPENDIX B ................................................................................................................ 39

LIQUEFIED NATURAL GAS (LNG) FROM NORTH AMERICAN AND REMOTE 

NATURAL GAS SOURCES PATHWAY INPUT VALUES...................................... 39

LIST OF FIGURES 

Figure 1. Discrete Components of the Three Natural Gas to LNG Pathways Detailed in 

this Document ................................................................................................................. 3

LIST OF TABLES 

Table A. Summary of GHG Emissions for the Three Scenarios Detailed Here............... 5

Table 1.01. Total Energy Consumption for NA NG Recovery ......................................... 7

Table 1.02. Total GHG Emissions from Natural Gas Recovery....................................... 8

Table 2.01. Total Energy Consumption for NG Processing............................................. 9

Table 2.02. Total GHG Emissions from NG Processing.................................................. 9

Table 3.01. Energy Use for NG Transport to LNG Plants in CA.................................... 10

Table 3.02. Total GHG Emissions Associated with NG Transport to California LNG 

Plants ............................................................................................................................ 10

Table 4.01. Energy Efficiency for Natural Gas Liquefaction .......................................... 11

Table 4.02. Direct Energy Use by Process Fuel for Liquefaction in California .............. 12

Table 4.03. Total Energy Use by Process Fuel for Liquefaction in California................ 12
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Table 4.04. Total Emissions (Direct + Upstream) Emissions for Liquefaction ............... 12

Table 5.01. Direct, Upstream and Total Energy Use for Heavy-Duty Diesel Truck 

Delivering LNG from LNG Plants to Refueling Stations in California............................. 14

Table 5.02. Upstream and Direct Emissions for Heavy-Duty Diesel Truck Transport of 

LNG from LNG Plants to Refueling Stations in California.............................................. 14

Table 5.03. Total GHG Emissions for LNG Transport in CA ......................................... 16

Table 5.04. LNG Storage Emissions ............................................................................. 16

Table 6.01. LNG Tailpipe Emissions. ............................................................................ 17

Table A2.1. Summary of GHG Emissions for Scenario 2.............................................. 20

Table A2.2. Basis Assumptions for Remote Sourced LNG for Scenario 2 .................... 20

Table 2.01. Total Energy Inputs for Overseas LNG Liquefaction Systems.................... 22

Table 2.02. Total Emissions (Direct + Upstream) Emissions for Remote Liquefaction.. 23

Table 3.01. Transport Distance for LNG Shipment via Ocean Tanker from Remote 

Source to Baja............................................................................................................... 25

Table 3.02. Direct, Upstream and Total Energy Use for Transport via Ocean Tanker to 

Baja............................................................................................................................... 25

Table 3.03. Total Emissions (Direct + Upstream) for Ocean Tanker Transport of LNG 

from Remote Source to Baja......................................................................................... 26

Table 3.04. Total GHG Emissions for Ocean Tanker Transport of LNG from Remote 

Source to Baja............................................................................................................... 26

Table 3.05. Total Energy (Direct + Upstream) for LNG Re-gasification......................... 27

Table 3.06. Emission Factors for Large (> 100 mmBtu/hr) NG Boiler ........................... 27

Table 3.07. Total GHG Emissions from LNG Re-gasification........................................ 28

Table 3.08. Total Energy Use for Transport of Re-gasified NG from Baja, Mexico ....... 29

Table 3.09. Total GHG Emissions for Pipeline Transmission from Baja, Mexico .......... 29

Table A3.1. Summary of GHG Emissions for Scenario 3.............................................. 33

Table A3.2. Basis Assumptions for Remote Sourced LNG ........................................... 34
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SUMMARY 
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CA-GREET Model Pathway for LNG from North American Natural Gas and Remote 

Natural Gas

Well-To-Tank (WTT) Life Cycle Analysis of a fuel pathway includes all steps from 

feedstock recovery to final finished fuel. Tank-To-Wheel (TTW) analysis includes actual 

combustion of fuel in a motor vehicle for motive power. Together, WTT and TTW 

analysis are combined to provide a total Well-To-Wheel (WTW) analysis. 

A Life Cycle Analysis Model called the Greenhouse gases, Regulated Emissions, and 

Energy use in Transportation (GREET)1

 developed by Argonne National Laboratory 

forms the core basis of the methodology used in this document. This model was 

modified by staff with assistance from Life Cycle Associates to create a CA-GREET 

model. This modified model incorporated California specific factors for emission factors, 

fuel properties, etc. into the original Argonne model. This pathway document details the 

energy use and associated Greenhouse Gas (GHG) emissions for the entire Liquefied 

Natural Gas (LNG) from Natural Gas (NG) pathway. The document includes LNG 

derived from: natural gas produced in North America and natural gas from remote NG 

sources (overseas from South East Asia for this document). Figure 1 details the steps 

for the three scenarios modeled in this document for LNG availability and use in 

California. 

Appendix A1: The left most scenario (Scenario 1) is for NG recovered and processed in 

North America, transported via pipeline to California, liquefied in California, transported 

to LNG filling stations in California and used as LNG in a heavy-duty vehicle in 

California. Complete details for this scenario is provided in Appendix A1. 

Appendix A2: The scenario in the middle of Figure 1 (Scenario 2) is for NG recovered, 

processed, and liquefied from remote sources (assumed from South East Asia), 

transported via tanker to Baja, re-gasified to NG and pipelined to California where it is 

liquefied to LNG, transported to LNG filling stations and used as LNG in a heavy-duty 

vehicle in California. Complete details for this scenario is provided in Appendix A2. 

Appendix A3: The rightmost scenario in Figure 1 (Scenario 3) is for NG recovered, 

processed, and liquefied from remote sources, transported via tanker to Baja, trucked 

from Baja to California as LNG and used as LNG in a heavy-duty vehicle in California. 

Complete details for this scenario is provided in Appendix A3. 

The summary section details the GHG emissions for the three scenarios with complete 

details for the scenarios provided in Appendices A1, A2, and A3. Details of all the input 

values are provided in Appendix B. 

Note: Staff is working on surveys for NG production, transmission and distribution in 

California. Based on the results, staff may update the analysis presented in this 

document. 

 

1 GREET Model: Argonne National Laboratory: 

http://www.transportation.anl.gov/modeling_simulation/GREET/index.html
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 APPENDIX A1 APPENDIX A2 APPENDIX A3 

Figure 1. Discrete Components of the Three Natural Gas to LNG Pathways Detailed in 

this Document 

Several general descriptions and clarification of terminology used throughout this 

document are: 

• CA-GREET employs a recursive methodology to calculate energy consumption and 

emissions. To calculate WTT energy and emissions, the values being calculated are 

often utilized in the calculation. For example, crude oil is used as a process fuel to 

recover crude oil. The total crude oil recovery energy consumption includes the 

direct crude oil consumption and the energy associated with crude recovery (which 

is the value being calculated). 

• Btu/mmBtu is the energy input necessary in Btu to produce or transport one million 

Btu of a finished (or intermediate) product. This description is used consistently in 

CA-GREET for all energy calculations. There are 1,055 MJ in one mmBtu of energy, 

so in order to convert one million Btu into MJ, divide the million Btu by 1,055. 

Scenario 1 

NG Extraction 

NG Processing 

NG Reliquefaction

NG Pipelined to 

California

LNG Vehicle 

Combustion

NG Regasification

LNG Tanker 

Ship Transport

NG Liquefaction 

NG Processing 

LNG T&D to 

California

LNG Tanker 

Ship Transport

NG Liquefaction 

NG Processing 

NG Extraction NG Extraction 

Scenario 2 Scenario 3

LNG T&D 

LNG Vehicle 

Combustion

NG Transport to

California

NG Liquefaction 

in California

LNG T&D 

LNG Vehicle 

Combustion
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• gCO2e/MJ provides the total greenhouse gas emissions on a CO2 equivalent basis 

per unit of energy (MJ) for a given fuel. Methane (CH4) and nitrous oxide (N2O) are 

converted to a CO2 equivalent basis using IPCC global warming potential values and 

included in the total. 

• CA-GREET assumes that VOC and CO are converted to CO2 in the atmosphere and 

includes these pollutants in the total CO2 value using ratios of the appropriate 

molecular weights. 

• Process Efficiency for any step in CA-GREET is defined as: 

Efficiency = energy output / (energy output + energy consumed) 

Table A below provides a summary of the GHG emissions for all the three scenarios. 
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Table A. Summary of GHG Emissions for the Three Scenarios Detailed Here 

Appendix A1 

Scenario 1 

Appendix A2 

Scenario 2 

Appendix A3 

Scenario 3 

North American 

NG, Liquefied in 

CA and used in 

CA 

Overseas LNG 

shipped to Baja, regasified, pipelined 

to CA, re-liquefied 

to LNG for use in 

CA 

Overseas LNG, 

shipped to Baja, 

then trucked to 

CA for use in CA 

Pathway Components gCO2e/MJ 

Well-to-Tank 

Natural Gas Recovery 3.49 3.43 3.43 

Natural Gas Processing 3.74 4.00 4.00 

NG Transport to LNG Plant 0.97 0.45 0.45 

Overseas Liquefaction n/a 7.40 7.40 

Transport via Ocean Tanker 

to CA n/a 1.65 1.65 

Transmission via pipeline n/a 0.76 n/a 

Re-gasification n/a 0.75 n/a 

Liquefaction at LNG Plants 15.79 15.79 n/a 

LNG Truck Transport, 

Distribution and Storage 0.64 0.64 2.07 

Total Well-to-Tank GHG 

Emissions 24.63 34.87 19.00 

Tank-to-Wheel 

Carbon in Fuel 56.0 56.0 56.0 

Vehicle CH4 and N2O 2.50 2.50 2.50

Total Tank-to-Wheel GHG 

Emissions 58.50 58.50 58.50 

Total Well-to-Wheel GHG 

Emissions 

(gCO2e/MJ) 

83.13 93.37 77.50

Note: All numerical entries in Table above are in gCO2e/MJ. Rounding of values has not been performed 

in several Tables in this document. This is to allow stakeholders executing runs with the CA-GREET 

model to compare actual output values from the model with values in this document. 
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APPENDIX A1 (SCENARIO 1) 

LNG FROM NORTH AMERICAN NG 
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SECTION 1. NATURAL GAS RECOVERY 

This Appendix details the energy use and GHG emissions for LNG derived from North 

American Natural Gas. Most of the details provided here for NG is from the NA NG to 

CNG pathway document published on the Low Carbon Fuel Standard website in 

February 2009 (http://www.arb.ca.gov/fuels/lcfs/lcfs.htm). The values for NG recovery, 

processing, and transport to CA are the same as detailed in the NA NG to CNG 

pathway document published in February 2009 and available from the Low Carbon Fuel 

Standard website. 

1.1 Energy Use for Natural Gas Recovery 

Details of the energy use for North American Natural Gas (NA NG) has been provided 

in the NA NG to CNG pathway document published in February 2009. Table 1.01 

provides a summary of the results for energy consumption from recovery of NA NG. 

Table 1.01. Total Energy Consumption for NA NG Recovery 

Fuel Type Energy Use 

Residual Oil (Btu/mmBtu) 288 

Diesel Fuel (Btu/mmBtu) 3,313 

Gasoline (Btu/mmBtu) 311 

Natural gas (Btu/mmBtu) 23,328 

Electricity (Btu/mmBtu) 676 

NG Leaks (Btu/mmBtu) 3,290 

Total Energy Use for NA 

NG Recovery

(Btu/mmBtu) 

31,207 

Note: See detailed calculations in the NA NG to CNG document published in February 2009 at 

http://www.arb.ca.gov/fuels/lcfs/lcfs.htm 

1.2 GHG Emissions from NA Natural Gas Recovery 

The pathway detailed here for NA NG uses the same information for calculating GHG 

emissions from natural gas recovery. This is available from the NA NG pathway 

document indicated earlier and the results are summarized in Table 1.02. 
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Table 1.02. Total GHG Emissions from Natural Gas Recovery 

GHG Species 

Fuel Type CO2 CH4 N2O Total GHG 

Emissions 

Residual Oil 

(gCO2e/mmBtu) 24 0.025 0.000 25 

Diesel 

(gCO2e/mmBtu) 260 0.292 0.005 269 

Gasoline 

(gCO2e/mmBtu) 19 0.051 0.001 20 

Natural Gas 

(gCO2e/mmBtu) 1,366 4.171 0.021 1,477 

Electricity 

(gCO2e/mmBtu) 56 0.069 0.001 58 

NG Leakage 

(gCO2e/mmBtu) 72.166 1,804 

Total GHG Emissions 

(gCO2e/mmBtu) 1,726 4.608 0.027 1,849 

Total GHG Emissions (gCO2e/MJ) 3.49 
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SECTION 2. NATURAL GAS PROCESSING 

2.1 Energy use for Natural Gas Processing 

The energy use is the same as published in the NA NG to CNG pathway document and 

Table 2.01 provides a summary of the energy use for NG processing. 

Table 2.01. Total Energy Consumption for NG Processing 

Fuel Type Energy Use 

Diesel Fuel 323 

Natural gas 27,889 

Electricity 2,172 

NG Leaks 1,479 

Total Energy Consumption for NG 

Processing (Btu/mmBtu) 31,862 

2.2 GHG Emissions from Natural Gas Processing

The GHG emissions for NG processing are the same as detailed in the NA NG to CNG 

pathway document and Table 2.02 provides a summary of the GHG emissions from 

natural gas processing. 

Table 2.02. Total GHG Emissions from NG Processing 

GHG Species 

Fuel Type CO2 CH4 N2O Total GHG 

Emissions 

Diesel 

(gCO2e/mmBtu) 25 0.028 0.000 26 

Natural Gas 

(gCO2e/mmBtu) 1,654 0.203 0.025 1,666 

Electricity 

(gCO2e/mmBtu) 181 0.222 0.002 187 

NG Leakage 

(gCO2e/mmBtu) 1,253 32.450 811 

Non-combustion 

Processing Emissions 

(gCO2e/mmBtu) 

 1,253 

Total GHG Emissions 

(gCO2e/mmBtu) 3,112 32.903 0.027 3,943 

Total GHG Emissions (gCO2e/MJ) 3.74 
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SECTION 3. NATURAL GAS TRANSPORTATION AND 

DISTRIBUTION 

3.1 Energy Use for NG Transport to LNG Plants in California 

The third step in the LNG from NA NG pathway is transport and distribution of the 

natural gas by pipeline from the processing plant to the LNG refueling station. The 

energy use is the same as detailed in the NA NG to CNG pathway document. Table 

3.01 provides a summary of the energy use for transport of NG to LNG plants in 

California. 

Table 3.01. Energy Use for NG Transport to LNG Plants in CA 

 Total Energy Use = 9,348 Btu/mmBtu

3.2 GHG Emissions from Natural Gas Transport to LNG Plants in California 

GHG emissions from transporting NG to California is the same as detailed in the NA NG 

to CNG pathway document and is summarized in Table 3.02. 

Table 3.02. Total GHG Emissions Associated with NG Transport to California LNG 

Plants 

GHG Species 

CO2 CH4 N2O GHG 

Emissions 

GHG Emissions

(g/mmBtu) 532 19.640 0.015 

Total GHG Emissions (gCO2e/mmBtu) 1,028 

Total GHG Emissions (gCO2e/MJ) 0.97 
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SECTION 4. NATURAL GAS LIQUEFACTION TO LNG

4.1 LNG Liquefaction Energy Use 

The next step is liquefaction of NG at LNG plants in California. LNG is produced by the 

compression and cooling of natural gas and expansion through several stages in an 

LNG plant. LNG is stored near atmospheric pressure at -162°C (-260°F). 

LNG plants are generally supplied by pipeline gas with supply pressures ranging from 

800 to 1000 psi. The feed gas for LNG is free of components that freeze at cryogenic 

temperatures including CO2 and high molecular weight hydrocarbons (C6 and greater). 

If LNG is produced from pipeline gas in the U.S., it is assumed that the gas meets 

pipeline specifications. 

Medium and small scale LNG facilities operate with typical efficiencies between 76 and 

92% using a simple cascade cycle (Kunert 2008)2. For the analysis conducted here, 

only small scale systems (about 5,000 metric ton/year) have been considered based on 

the systems likely to be used in California. For such systems, the liquefaction 

efficiencies are likely to be in the lower range of values indicated above. Therefore, for 

this analysis a liquefaction efficiency of 80% was assumed. Details of the assumptions 

for efficiency and fuel shares is provided in Table 4.01. 

Table 4.01. Energy Efficiency for Natural Gas Liquefaction.

Liquefier Type Efficiency Fuel Shares 

Small Scale CA 

80%, excluding gas 

processing, which is 

calculated separately 

100% Natural Gas 

(CA-GREET Default) 

 

North American NG is liquefied at a central facility and distributed by heavy duty LNG 

trucks. NG liquefaction in California is done by pressure let down or electromagnetic 

liquefaction and is all electric. Liquefaction in California is assumed to be 100% natural 

gas- at central facilities, with an average efficiency of 80%. The main parameters for 

NA liquefaction modeling are: 

• Region: California (average crude) 

• Liquefaction efficiency (80%) 

• Process fuel shares (100% NG, CA-GREET default) 

• LNG storage leakage rate (0.05% day, IPCC value) 

• LNG storage duration (5 days, CA-GREET default) 

• Recovery rate of LNG boil-off (100%) 

 

2

 Kunert (2008). "Small is Beautiful - MiniLNG Concept: A Very Small LNG Production Plant for the 

Potential Use of Bio-Energy for Future Energy Supply". "The Potential of Bioenergy for Future Energy 

Supply" Conference, Leipzig, Germany. 
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The liquefaction efficiency assumed here (80%) implies that 250,000 Btu of direct NG is 

required to liquefy 1 mmBtu of NG fuel. A natural gas turbine is used for liquefaction 

energy. Unlike NG extraction and processing, CA-GREET models feed loss 

(Btu/mmBtu) based directly on the methane boil-off rather than using a fuel share for 

feed loss. However, zero percent feed loss is assumed because typically LNG facilities 

recapture boil off and re-liquefy the NG or use it as fuel. Table 4.02 provides the direct 

energy use for liquefaction. 

Table 4.02. Direct Energy Use by Process Fuel for Liquefaction in California 

Process Fuel Fuel 

Share Formula Direct Energy Use 

Natural Gas 

(Btu/mmBtu) 100% 106

*(1/0.80 – 1) 250,000 

Total Direct Energy Use (Btu/mmBtu) 250,000 

Total energy for liquefaction is based on the direct energy input plus the upstream 

energy for that fuel and is calculated in the same way as total energy for extraction and 

processing. Total energy use is shown in Table 4.03. 

Table 4.03. Total Energy Use by Process Fuel for Liquefaction in California 

Fuel Direct Energy Upstream Energy Total Energy Use 

Natural Gas 

(Btu/mmBtu) 

106*(1/80%)*100% 

= 250,000 

250,000*(31,144 + 

31,321)/106 = 

15,616 

265,616 

Total Energy Use (Btu/mmBtu) 265,616 

Note: The values used in this table are from the NA NG to CNG pathway document. 

4.2 GHG Emissions from Natural Gas Liquefaction to LNG in California

The analysis in this document considers all liquefaction energy to come from 100% NG 

with a liquefaction efficiency of 80%. Results for GHG emissions are similar to the 

energy calculations in the previous section. The pathway assumes zero methane 

emissions from leaks because typically all NG is either recaptured and re-liquefied or 

used as a fuel in the process. Table 4.04 summarizes the results where CO and VOC 

emissions are converted to CO2eq. 

Table 4.04. Total Emissions (Direct + Upstream) Emissions for Liquefaction in California 

GHG Species GHG Emissions (g/mmBtu)

VOC 1.707 

CO 8.590 

CH4 32.906 

N2O 0.389 

CO2 15,717 

GHG Emissions (gCO2e/mmBtu) 16,655 

Total GHG Emissions (gCO2e/MJ) 15.79 
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SECTION 5. LNG TRANSPORT, DISTRIBUTION, AND 

STORAGE 

5.1 LNG Truck Transport Summary 

LNG is distributed by heavy duty truck (HDT) from the bulk terminal in California to end 

user. The 80,000 lb GVW limit for tanker trucks carrying liquid fuels sets the theoretical 

upper weight limit for LNG (or any liquid fuel) cargo. The cargo capacity for gasoline 

tanker trucks is 54,000 lbs, or 9,000 gallons of gasoline. Since the density of LNG is 

slightly more than half of the density of gasoline, the practical LNG cargo capacity is 

limited by volume rather than weight. The 9,000 gallon capacity of a tanker truck 

translates into approximately 32,000 lbs (16 tons) LNG cargo capacity, or ~60% of the 

cargo weight limit. The Argonne GREET model default of 15 tons is close to this and 

used in this analysis. 

Heavy duty tanker trucks transfer LNG by passing a small amount of LNG into a heat 

exchanger to increase the pressure in the tanker truck and force the liquid into the 

receiver tank. After transferring the vapors, the LNG tank on the truck is purged. Life 

cycle energy includes the direct and upstream diesel energy used to operate the truck 

and the fuel lost to boil off methane emissions (which contributes to the loss factor). 

Emissions include direct and upstream emissions for diesel fuel in a HDT and the 

fugitive methane boil-off emissions. 

5.2 LNG Truck Transport Energy Consumption 

Heavy duty trucks distribute the LNG from the liquefaction facility to the LNG station. 

The energy results are calculated using a 50 mile transport distance from a LNG plant in 

California. The main transport inputs are shown below. All inputs except for distances 

are CA-GREET default values. 

• Region: CA (CA marginal electricity, CA average crude) 

• Capacity (15 tons) 

• Fuel economy (5 mi/gal) 

• Fuel used (diesel) 

• Fugitive emissions during storage (0.1% loss/day, CA-GREET default) 

• Fugitive emission recovery rate (80% industry practice) 

• Distance (50 mi, CA-GREET default) 

The calculations for heavy duty truck energy consumption are based on truck energy 

intensity in Btu/ton-mi. The energy intensity is calculated as follows: 

Btu/ton-mi = ((128,450 Btu/gal Diesel LHV)/(5 mi/gal))/capacity in tons. The calculation 

for energy intensity is shown below and direct, upstream and total energy results are 

presented in Table 5.01. 
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Energy Intensity for Trip to Destination and Return Trip: 

(128,450 Btu/gal)/(5 mi/gal)/15 tons = 1,713 Btu/ton-mi 

Direct Diesel Energy 

ton mile

Btu miles

Btu gal g lb lbs ton

g gal

−

 × × ×











× ×

×

50 ,1 713 2

80,968 / 454 / ,2 000 /

10 ,1 724 /

6

 = 

4,016 Btu/mmBtu

Upstream Diesel Energy 

× =

−

 × × ×











× ×

×

Btu Btu

ton mile

Btu miles

Btu gal g lb lbs ton

g gal 50 ,1 713 2 .0 165 /

80,968 / 454 / ,2 000 /

10 ,1 724 /

6

663 Btu/mmBtu

(where 0.165 Btu/Btu is Btu energy of diesel consumption per Btu of diesel transported - 

upstream) 

Table 5.01. Direct, Upstream and Total Energy Use for Heavy-Duty Diesel Truck 

Delivering LNG from LNG Plants to Refueling Stations in California 

Energy Source Energy Use 

(Btu/mmBtu)

Direct Energy 4,016 

Upstream Energy 663 

Total Energy 

(Btu/mmBtu) 4,679 

5.3 GHG Emissions from Truck Transport of LNG 

Upstream and direct emissions from LNG transport by truck from the LNG plants are 

shown in Table 5.02 below. Table 5.03 below summarizes the total GHG emissions for 

LNG transport inclusive of methane losses. 

Table 5.02. Upstream and Direct Emissions for Heavy-Duty Diesel Truck Transport of 

LNG from LNG Plants to Refueling Stations in California 

 GHG Species (g/mmBtu)

Fuels CO2 CH4 N2O 

Upstream Diesel Emissions 64 0.4524 0.001 

Direct Diesel Emissions 313 0.006 0.008 

Total Emissions 

(g/mmBtu) 378 0.453 0.009 
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Example of calculation CO2 shown above: 

Upstream Diesel CO2: 

ton mile

Btu miles g mmBtu

Btu gal g lb lbs ton

g gal

−

× × × × 











× ×

50 15,813 / ,1 713 2

80,968 / 454 / ,2 000 /

,1 724 /

 = 

64 g/mmBtu 

where 15,813 g/mmBtu is the upstream CO2 emissions associated with diesel 

production (calculated in the “Petroleum” sheet of the CA-GREET model) 
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Direct Diesel CO2

ton mile

Btu miles g mmBtu

Btu gal g lb lbs ton

g gal

−

× × + × 











× ×

50 77( ,809 77,912) / ,1 713

80,968 / 454 / ,2 000 /

,1 724 /

 = 313 g/mmBtu CO2 

Total: 378 g/mmBtu CO2 where 77,809 g/mmBtu and 77,912 g/mmBtu are the emission 

factors from the EF sheet of CA-GREET. 

Fugitive emissions from truck transport are modeled based on 0.1% boil-off/day and 

80% recovery. These are CA-GREET default parameters. 

Table 5.03. Total GHG Emissions for LNG Transport in CA 

GHG Species 

CO2 CH4 N2O GHG Emissions

Fuel 

Diesel (g/mmBtu) 378 0.453 0.009 392 

Methane Losses (g/mmBtu) 0.426 11 

Total Emissions (gCO2e/mmBtu) 378 0.879 0.009 403 

Total GHG Emissions (gCO2e/MJ) 0.38 

5.4 GHG Emissions from Storage of LNG 

Fugitive methane emissions occur during LNG storage. The net emissions are a 

function of the methane boil-off and recovery rates. There are 6 key inputs determining 

the fugitive methane emissions, shown below in Table 5.04. 

Table 5.04. LNG Storage Emissions 

Description Bulk Terminal Distribution 

Daily Boil-Off Rate (%) 0.05% 0.1% 

Duration (Days) 5 0.1 

Boil-Off Recovery Rate (%) 80% 80% 

Net Methane Emissions (g/mmBtu) 10.7 0.4 

Net Methane Emissions (gCO2e/mmBtu) 267 10.6 

Net Methane Emissions (gCO2e/MJ) 0.25 0.01 

Total GHG Emissions (gCO2e/MJ) 0.26 

Calculation of the net fugitive emissions based on the inputs is shown below: 

Net Boil-Off Emissions: 

[(0.05% bulk terminal boil-off/day)*(5 days)/(1-(0.05% bulk terminal boil-off/day)*(5 

days))*(1-80% recovery) + [(0.1% distribution boil-off/day)*(0.1 days)/(1-(0.1% 

distribution boil-off/day)*(5 days))*(1-80% recovery)]*106/(80,968 Btu/gal)*(1,724 g/gal) 

= 11.1 g CH4/mmBtu 

Converting to gCO2e/MJ: (11.1 g CH4/mmBtu)*25/(1055 MJ/mmBtu) = 0.26 g CO2e/MJ 
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SECTION 6. GHG EMISSIONS FROM VEHICLES

6.1 LNG Composition 

LNG composition affects the inputs to its life cycle analysis in two ways. First, the 

composition determines the product fuel’s carbon content which can range from 74.7 to 

76.1% corresponding to a range of 55.4 to 56.8 g/MJ (as CO2) when calculated from the 

individual LNG composition. The range in carbon content for LNG is relatively small as 

it contains low levels of nitrogen and no CO2. A carbon content of 75.7% was selected 

as the CA-GREET input based on the average of a range of LNG compositions. The 

CA-GREET inputs for heating value and density were also changed to reflect LNG 

compositional data that was consistent with data and the carbon content in g/MJ. 

6.2 GHG Emissions from Vehicles 

Vehicle GHG emissions consist of: 

• Tailpipe CO2 (combusted CH4) 

• Tailpipe N2O (combustion product) 

• Tailpipe CH4 (product of incomplete combustion, evaporative losses) 

In this analysis, heavy duty trucks use LNG. The CO2 is calculated from the carbon 

content of the fuel, minus the tailpipe methane emissions. CO2 emissions therefore 

depend on the fuel heating value (LHV), density (g/gal) and carbon content (% C by 

weight). 

(1,724 g-LNG/gal)*(0.757 g-C/g-NG)*(1/80,968 Btu/gal)*(44 g-CO2/12 g-C)*(Btu/1.055 

kJ)*(1,000 kJ/MJ) = 56.0 g CO2/MJ 

In the above equations 1,724 is the density of LNG (CA-GREET default), 0.757 is the 

Carbon in LNG (Ca-GREET default) and the LHV of LNG is 80,968 Btu/gal. 

The same vehicle CH4 and N2O emissions are assumed for LNG vehicles as CNG 

vehicles which is 2.5 g CO2e/MJ, (see NA NG to CNG fuel pathway document on the 

LCFS website at http://www.arb.ca.gov/fuels/lcfs/lcfs.htm for complete details). 

 

Table 6.01. LNG Tailpipe Emissions. 

Tailpipe Emissions CO2

CH4 and 

N2O Total 

Total GHG Emissions 

(gCO2e/MJ) 56.0 2.5 58.5 
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APPENDIX A2 (SCENARIO 2) 

LNG FROM REMOTE SOURCES, SHIPPED TO BAJA, 

RE-GASIFIED, PIPELINED TO CA, LIQUEFIED IN CA
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This Appendix details the energy use and GHG emissions for LNG produced from 

remote NG (overseas modeled here as being South East Asia), shipped to Baja, 

Mexico, re-gasified, pipelined to CA, liquefied in CA and transported for use in CA. 

Some of the details provided here for NG are from the NA NG to CNG pathway 

document published on the Low Carbon Fuel Standard website in February 2009 

(http://www.arb.ca.gov/fuels/lcfs/lcfs.htm). Other details are from Appendix A1 of this 

document. This scenario differs from scenario 1 presented in Appendix A1 in the 

following areas: 

a) NG recovery and processing uses South East Asia Electricity mix compared to U. 

S. Average mix for scenario 1. 

b) Liquefaction efficiency is 90% for this compared to 80% for scenario 1. 

c) LNG is transported via ocean tanker which does not exist in scenario 1. 

d) LNG is re-gasified for this scenario but not for scenario 1. 

e) NG is pipelined from Baja, Mexico, to CA for this scenario but NG is transported 

from average U. S. sources of NG for scenario 1. 

f) There is liquefaction in California for scenario 2 which is the same for scenario 1. 

Table A2.1 below provides a summary of the GHG emissions calculated for 

scenario 2. Details of the calculations are presented in the following sections. 
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Table A2.1. Summary of GHG Emissions for Scenario 2 

Pathway Component GHG Emissions 

NG Recovery (gCO2e/MJ) 3.43 

NG Processing (gCO2e/MJ) 4.00 

NG Transp. to LNG Plant 

(gCO2e/MJ) 0.45 

NG Liquefaction (Overseas) 

(gCO2e/MJ) 7.40 

LNG Transport via Ocean 

Tanker (gCO2e/MJ) 1.65 

NG Pipeline Transmission 

(gCO2e/MJ) 0.76 

Re-gasification (gCO2e/MJ) 0.75 

NG Liquefaction (CA) 

(gCO2e/MJ) 15.79 

LNG/Diesel Truck Transport 

and Storage (gCO2e/MJ) 0.64 

WTT GHG Emissions 

(gCO2e/MJ) 34.87 

Carbon in Fuel (gCO2e/MJ) 56.00 

Tailpipe Emissions 

(non-CO2 ,gCO2e/MJ) 2.50 

TTW GHG Emissions 

(gCO2e/MJ) 58.50 

Total WTW GHG Emissions 

(gCO2e/MJ) 93.37 

The basic assumptions for the calculations above are summarized in Table A2.2. 

Table A2.2. Basis Assumptions for Remote Sourced LNG for Scenario 2 

Description Value/Assumption

NG Transport from field to 

Remote LNG plants (mi) 50 

Liquefaction Efficiency 

90% for remote 

liquefaction and 

80% for California 

liquefaction 

LNG Transport from 

remote source via Ocean 

Tanker (mi) 

8,769 

LNG Truck Transport (mi) 50 

Electricity Mix for remote 

source 

S. E. Asia Average 

Electricity Mix for CA 

process 

CA Marginal 
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SECTION 1. REMOTE NATURAL GAS RECOVERY, 

PROCESSING AND TRANSPORT TO LNG PLANT 

1.1 Remote NG Recovery and Processing 

For NG recovery and processing, the same assumptions and inputs are assumed for 

NG produced at a remote site as that for NA NG. Hence the results are similar to those 

provided in Sections 1 and 2 in Appendix A1. The small differences are related to the 

average electricity mix used for South East Asia (Residual oil 19.3%, NG 33.5%, Coal 

36.3%, Biomass 2.2% and other renewables 8.6%) being different compared to the 

U.S. Average electricity mix used in the calculations for the recovery and processing of 

NA NG. The values for GHG emissions for recovery and processing are shown in 

Table A in the summary section and the total emissions are 3.43 (recovery) and 4.0 

(processing) for a total of 7.43 gCO2e/MJ for the recovery and processing of remote 

natural gas. 
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SECTION 2. REMOTE NATURAL GAS LIQUEFACTION TO 

LNG 

2.1 Liquefaction Energy Use 

Liquefaction at the remote site is modeled as being produced in a large scale (over 4 

million tonne/year) liquefier. A detailed description of the processing requirements for 

LNG is provided in a report by the International Gas Union (Rahal 20063

). The 

conversion efficiency for LNG ranges from 89% to 93% for large scale facilities. The 

inputs for the analysis used here are based on the Argonne GREET inputs with data 

from a 1999 article (Kikkawa 19994). 

The energy for liquefaction is generated with turbines at the LNG plant. 2% of the 

energy input is purchased power to operate facility controls based on the CA-GREET 

default with the balance from NG. The inputs and breakdown of the energy used are 

shown in Table 2.01. The calculation methodology is similar to the one presented for 

liquefaction in California in Appendix A1. 

Table 2.01. Total Energy Inputs for Overseas LNG Liquefaction Systems 

Parameter Energy or Other 

Value 

Liquefaction Inputs 

Natural Gas (Btu/mmBtu) 108,889 

Electric Power (Btu/mmBtu) 2,222 

Total (Btu/mmBtu) 111,111 

Liquefaction Efficiency 90% 

Fuel Shares 

Natural Gas 98% 

Electric Power 2% 

 

3

Rahal, C. (2006). "Liquefied Natural Gas". Report of Programme Committee D, Triennium 2003-2006, 

23rd World Gas Conference, International Gas Union.

4

 Kikkawa, Y. and I Aoki, 199, “Gas to Liquid of 21st Century,” AIChE meeting, Houston, TX, March 1999 
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2.2 GHG Emissions from Natural Gas Liquefaction to LNG

For this document, liquefaction energy comes from the resource mix described in the 

previous section. The GHG emissions correspond to the natural gas and electricity use. 

The pathway assumes zero methane emissions from leaks because typically all NG is 

either recaptured and re-liquefied or used as a fuel in the process. Table 2.02 

summarizes the results where CO and VOC emissions are converted to CO2 eq. The 

calculations are similar to the ones presented for liquefaction in California in 

Appendix A1. 

Table 2.02. Total Emissions (Direct + Upstream) Emissions for Remote Liquefaction of 

NG 

GHG Species 

GHG Emissions 

(g/mmBtu)

VOC 0.796 

CO 4.135 

CH4 15.003 

N2O 0.175 

CO2 7,381 

Total GHG Emissions 

(gCO2e/mmBtu) 7,808 

Total GHG Emissions 

(gCO2e/MJ) 7.4 
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SECTION 3. LNG TRANSPORT TO CALIFORNIA, 

DISTRIBUTION, RE-GASIFICATION, TRANSPORT, AND 

STORAGE WITHIN CALIFORNIA 

3.1 LNG Transport via Ocean Tanker 

LNG is transported in large cryogenic tanks aboard LNG tanker ships. Standard LNG 

carriers range in size from 120,000 to 155 000 m3. A few small purpose built ships and 

large LNG carriers 210,000 m3 have also been built (Rahal 20065). Most LNG tankers 

operate on a combination of LNG and bunker fuel. Some very large LNG tankers 

operate on only bunker fuel and use an on-board re-liquefaction system to capture boil 

off. The analysis here is based on 53% NG ship fuel share, including the LNG from boil 

off (0.15%/day) and 47% residual oil as fuel. 

LNG Tanker Ship Energy Consumption 

The parameters for modeling LNG tanker ship transport energy are shown below. All 

inputs except for distances are CA-GREET default values. 

• Region: Southeast Asia (U.S. Average Crude, South East Asia electricity) 

• Capacity (65,000 tons) 

• Average speed (19 mph) 

• Energy consumption for transport and return trip (4,620 and 4,691 Btu/hphr) 

• Fuel shares (47% residual oil, 53% natural gas) 

• Load factor for transport and return trip (80% and 70%) 

• Distance (8,769 miles) 

The calculations for energy tanker ship energy consumption are based on the ship 

energy intensity (in Btu/ton-mile). The calculations for energy intensity are below: 

Trip to Destination: 

(4,620 Btu/hphr)*(15,635 hp required)*(80% load factor)/(65,000 tons)(19 mph average 

speed) = 48 Btu/ton-mi

Return Trip: 

(4,691 Btu/hphr)*(15,635 hp required)*(70% load factor)/(65,000 tons)(19 mph average 

speed) = 43 Btu/ton-mi

The ships boil off approximately 0.15%/day of the LNG, which is used as ship fuel. 

100% recovery is assumed in GREET, since there are no fugitive emissions and the 

boil-off determines the loss factor. 

 

5

 Rahal, C. (2006). "Liquefied Natural Gas". Report of Programme Committee D, Triennium 2003-2006, 

23rd World Gas Conference, International Gas Union.
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The ship distance shown in Table 3.01 was estimated using an online shipping 

calculator tool (Eship 20086

). 

Table 3.01. Transport Distance for LNG Shipment via Ocean Tanker from Remote 

Source to Baja 

Pathway 

Scenario 

LNG 

Source Destination Port Distance (mi) 

2 South 

East Asia 

Baja (Mexico) 8,769 

Ocean tanker transport energy is calculated the same way as energy for all transport 

modes. The calculations for ocean tanker transport from South East Asia to Baja, 

Mexico are shown below in Table 3.02. 

Table 3.02. Direct, Upstream and Total Energy Use for Transport via Ocean Tanker to 

Baja 

Fuel 

(Btu/mmBtu)

Direct Energy 

Use 

Upstream 

Energy Use 

Total Energy 

Use 

Residual Oil 8,769 1,008 9,777 

NG 9,871 3,490 13,360 

Total Energy Use (Btu/mmBtu) 23,137 

Direct Residual Oil Energy (South East Asia to Baja) 

Direct energy = 106 Btu/(80,968 Btu/gal)*(1,724 g/gal)/(454 g/lb)/(2,000 lbs/ton)*(8,769 

mi)*(48 Btu/ton-mi + 43 Btu/ton-mi)*(47%) = 8,769 Btu/mmBtu

Upstream Residual Oil Energy 

106 Btu/(80,968 Btu/gal)*(1,724 g/gal)/(454 g/lb)/(2,000 lbs/ton)*(8,769 mi)*(48 Btu/tonmi + 43 Btu/ton-mi)*(0.115 Btu/Btu)(47%) = 1,008 Btu/mmBtu

The direct and upstream energy for the natural gas component is calculated in the same 

manner as detailed for residual oil. The total energy for both residual oil and NG is 

shown in Table 3.02 and is 23,137 Btu/mmBtu. 

GHG Emissions from Transport via Ocean Tanker 

Ocean tanker transport emissions is calculated the same way as emissions for all 

transport modes. The total GHG emissions, including ship combustion and upstream 

emissions for scenario 2 is shown in Tables 3.03 and Table 3.04. 

 

6

 Eship. (2008). "Sea Distances - Voyage Calculator." Retrieved September 1, 2008, from http://www.eships.net/dist.htm. 
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Table 3.03. Total Emissions (Direct + Upstream) for Ocean Tanker Transport of LNG 

from Remote Source to Baja 

GHG Species 

CO2 VOC CO CH4 N2O Fuel(g/mmBtu)

Residual Oil 825 0.777 1.810 0.876 0.019 

Natural Gas 799 0.905 1.192 2.723 0.025 

Total GHG Emissions 

(g/mmBtu) 1,625 1.682 3.002 3.599 0.043 

Table 3.04. Total GHG Emissions for Ocean Tanker Transport of LNG from Remote 

Source to Baja 

 GHG Species 

CO2 CH4 N2O Emissions

Fuel (g/mmBtu)

Residual Oil 830 0.876 0.019 

Natural gas 804 2.723 0.025 

Total GHG Emissions (gCO2e/mmBtu) 1,737 

Total GHG Emissions (gCO2e/MJ) 1.65 

3.2 Re-gasification 

Scenario 2 requires that LNG gas be re-gasified to natural gas for pipeline transmission. 

This includes heating the gas to ambient temperature and raising the pressure to 

pipeline pressures of 800 psi. Several methods are used for the re-gasification or 

vaporization process. LNG is pumped into a heat exchanger and the source of heat 

could be sea water, combustion of the vaporized gas, or ambient air. Some systems 

also aim to make use of the latent heat energy from LNG to produce useful work. The 

energy required for re-gasification ranges from 0.5% to 3% (Heede 20067

, Rahal 

20068

). An average re-gasification energy requirement of 1.0% was assumed for this 

document. 

Energy Consumption from LNG Re-gasification 

The equipment used for re-gasification is similar to a NG boiler or steam generator. 

Direct energy for LNG re-gasification is based on the share of the feedstock stream 

(LNG) used for re-gasification: 

(1.0%)*(1,000,000 Btu LNG) = 10,000 Btu NG/mmBtu LNG throughput 

 

7Heede, R. (2006). "LNG Supply Chain Greenhouse Gas Emissions from the Cabrillo Deepwater Port: 

Natural Gas from Australia to California", Climate Mitigation Services. 

8Rahal, C. (2006). "Liquefied Natural Gas". Report of Programme Committee D, Triennium 2003-2006, 

23rd World Gas Conference, International Gas Union.
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The upstream energy component consists of the total energy required to generate the 

LNG delivered by tanker ship (just prior to re-gasification). This includes energy for 

extraction, transport to LNG facility, processing, liquefaction, storage and LNG tanker 

ship transport. The total energy (direct + upstream) for Scenario 2 that includes regasification is shown below in Table 3.05. 

Table 3.05. Total Energy (Direct + Upstream) for LNG Re-gasification 

Description Energy (Btu/mmBtu)

Direct Energy 10,000 

Upstream Energy 2,959 

Total Energy Use 

(Btu/mmBtu) 12,959 

GHG Emissions from LNG Re-gasification 

The NG process fuel input (10,000 Btu/mmBtu) and the NG fuel properties (lower 

heating value, % carbon in fuel and density) determine the direct CO2 emissions from 

re-gasification and equipment-specific emission factors (in g/mmBtu fuel burned) dictate 

the other emission species. Since CA-GREET does not model LNG re-gasification and 

emission factor data for re-gasifiers is not readily available, this analysis uses CAGREET default emission factors for large (> 100 mmBtu/hr) NG utility boilers to 

calculate direct emissions (shown below in Table 3.06). 

Table 3.06. Emission Factors for Large (> 100 mmBtu/hr) NG Boiler 

Species Emissions 

CO2 (g/mmBtu fuel burned) 58,198 

VOC (g/mmBtu fuel burned) 1.557 

CO (g/mmBtu fuel burned) 16.419 

CH4 (g/mmBtu fuel burned) 1.100 

N2O (g/mmBtu fuel burned) 0.315 

The total greenhouse gas calculations are based on the direct energy input (10,000 

Btu/mmBtu) with emission factors shown in Table 3.06. Table 3.07 below presents the 

total (direct + upstream) emissions for re-gasification for Scenario 2 considered here. 

Since 1.0% of the LNG is consumed for re-gasification, this step contributes a 1.0% 

feed loss to the process steps upstream of re-gasification. This is equivalent to applying 

a 1.01 loss factor to the upstream process energy and emission results. 
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Table 3.07. Total GHG Emissions from LNG Re-gasification 

GHG Species 

CO2 CH4 N2O Emissions

Re-gasification Emissions 

(g/mmBtu) 777 0.511 0.007 

Total GHG Emissions (gCO2e/mmBtu) 792 

Total GHG Emissions (gCO2e/MJ) 0.75 

3.3 Pipeline Transport to CA under Scenario 2 

NG Pipeline Transmission Energy 

The main input parameters for modeling pipeline energy are the energy intensity and 

equipment shares for turbines, engines for pressurizing the gas, pipeline distance and 

% loss factor. Using details for transporting NG as shown in Appendix A1, for this 

scenario using 250 mile transport from Baja, Mexico to California, the direct and 

upstream . NG energy calculations for pipeline transport to California (scenario 2) are 

shown as an example: 

Direct Energy (NG) (Scenario 2) 

250 405 .0( 069 94%)

930 / 454 / ,2 000 /

10 20 4. /

3

6 3

× ×

−

× × 











× ×

×

Btu

Btu

ton mile

Btu miles

Btu ft g lb lbs ton

g ft

= 190 Btu/mmBtu 

Upstream Energy (NG and electricity) (Scenario 2) 

250 405 .0( 069 94% .1 997 6%)

930 / 454 / ,2 000 /

10 20 4. /

3

6 3

× × + ×

−

× × 











× ×

×

ton mile

Btu miles

Btu ft g lb lbs ton

g ft

= 542 Btu/mmBtu 

Where: 

 0.069 Btu/Btu: energy consumption from transportation of NG (CA-GREET calculated 

in cell D170, “T&D” tab) 

1.997 Btu/Btu: energy consumption from transmission of electricity (CA-GREET 

calculated in cell R170, “T&D” tab) 

Table 3.08 provides a summary of the total energy use for pipeline transport of NG from 

Baja, Mexico to CA for Scenario 2. 
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Table 3.08. Total Energy Use for Transport of Re-gasified NG from Baja, Mexico 

Energy Use 

(Btu/mmBtu)

Direct Energy Use 190 

Upstream Energy Use 542 

Total Energy Use 

(Btu/mmBtu) 732 

GHG Emissions from NG Pipeline Transmission 

Greenhouse gas emissions resulting from NG pipeline transmission are presented here. 

Direct and upstream emissions are calculated using the same equations shown in the 

NA NG to CNG document. The total process fuel emissions are shown below in Table 

3.09. 

Table 3.09. Total GHG Emissions for Pipeline Transmission from Baja, Mexico 

 GHG Species 

CO2 CH4 N2O 

GHG 

Emissions 

Fuels (g/mmBtu) (gCO2e/mmBtu)

Natural Gas 289 1.315 0.010 325 

Electricity 31 0.064 0.001 33 

Methane Losses 17.548 439 

Total GHG Emissions (gCO2e/mmBtu) 796 

Total GHG Emissions (gCO2e/MJ) 0.76 

3.4 Liquefaction in California 

For Scenario 2 where liquefaction occurs in California, the process has been described 

earlier in Appendix A1. The emissions for this step in the pathway is 15.79 gCO2e/MJ. 

3.5 LNG Transport and Storage in California 

This section is the same as presented in Appendix A1. The GHG emissions from LNG 

transport and storage in CA are 0.38 + 0.26 = 0.64 g CO2e/MJ. 
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SECTION 4. GHG EMISSIONS FROM VEHICLES 

4.1 Tank To Wheel (TTW) GHG Emissions 

GHG emissions are the same as detailed in Appendix A1 and the total GHG emissions 

are 58.5 gCO2e/MJ. 
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APPENDIX A3 (SCENARIO 3) 

LNG FROM REMOTE SOURCES, SHIPPED TO BAJA, 

TRUCKED TO CA
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This Appendix details the energy use and GHG emissions for LNG produced from 

remote NG (overseas modeled here as being South East Asia), shipped to Baja, 

Mexico, trucked to CA and use in CA. Some of the details provided here for NG are 

from the NA NG to CNG pathway document published on the Low Carbon Fuel 

Standard website (http://www.arb.ca.gov/fuels/lcfs/lcfs.htm) in February 2009. Other 

details are from Appendices A1 and A2 of this document. This scenario differs from 

scenarios 1 and 2 presented in Appendices A1 and A2 in the following areas: 

a) NG recovery and processing uses South East Asia Electricity mix which is the 

same for scenario 2 while for scenario 1, the mix is U. S. Average mix. 

b) Liquefaction efficiency is 90% for this and scenario 2 compared to 80% for 

scenario 1. 

c) LNG is transported via ocean tanker for this scenario and scenario 2 which does 

not exist in scenario 1. 

d) LNG is not re-gasified for this scenario and scenario 1 but is for scenario 2. 

e) NG is not pipelined from Baja, Mexico, to California for this scenario but is for 

scenario 2 and for scenario 1, NG is transported from average U. S. sources to 

California. 

f) There is liquefaction in California for scenario 2 which is the same for scenario 1 

but does not happen for scenario 3. 

g) LNG is transported from Baja, Mexico, for this scenario but does not happen for 

scenarios 1 and 2. 

Table A3.1 below provides a summary of GHG emissions calculated for scenario 3. 

Details of the calculations are presented in the following sections. 
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Table A3.1. Summary of GHG Emissions for Scenario 3

Pathway Component 

GHG Emissions 

(gCO2e/MJ) 

NG Recovery (gCO2e/MJ) 3.43 

NG Processing (gCO2e/MJ) 4.00 

NG Transp. to LNG Plant 

(gCO2e/MJ) 0.45 

NG Liquefaction (Overseas) 

(gCO2e/MJ) 7.40 

LNG Transport via Ocean 

Tanker (gCO2e/MJ) 1.65 

LNG/Diesel Truck Transport 

and Storage (gCO2e/MJ) 2.07 

WTT GHG Emissions 

(gCO2e/MJ) 19.00 

Carbon in Fuel (gCO2e/MJ) 56.00 

Tailpipe Emissions 

(non-CO2, gCO2e/MJ) 2.50 

TTW (gCO2e/MJ) 58.50 

Total WTW GHG Emissions 

(gCO2e/MJ) 77.50 
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The basic assumptions for the calculations above are summarized in Table A3.2. 

Table A3.2. Basis Assumptions for Remote Sourced LNG 

 Description Value/Assumption 

NG Transport from field to 

Remote LNG plants (mi) 50 

Liquefaction Efficiency 90% for remote 

liquefaction 

LNG Transport from 

remote source via Ocean 

Tanker (mi) 

8,769 

LNG Truck Transport (mi) 250 

Electricity Mix for remote 

source 

South East Asia 

Average 

Electricity Mix for CA 

process 

CA Marginal 
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SECTION 1. REMOTE NATURAL GAS RECOVERY, 

PROCESSING AND TRANSPORT TO LNG PLANT 

1.1 Remote NG Recovery and Processing 

As detailed in scenario 2 and shown in Appendix A2, the results are 3.43 g/CO2e/MJ for 

NG recovery and 4.0 g/CO2e/MJ for NG processing. 
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SECTION 2. REMOTE NATURAL GAS LIQUEFACTION TO 

LNG 

2.1 Liquefaction Energy Use 

As presented in scenario 2 and shown in Appendix A2, the energy use for overseas 

liquefaction is 111,111 Btu/mmBtu. 

2.2 GHG Emissions from Natural Gas Liquefaction to LNG

As presented in scenario 2 and shown in Appendix A2, the GHG emissions from 

overseas liquefaction are 7.4 g/CO2e/MJ. 
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SECTION 3. LNG TRANSPORT TO BAJA, THEN TRUCKED 

AND STORAGE WITHIN CALIFORNIA 

3.1 LNG Transport via Ocean Tanker 

As presented in scenario 2 and shown in Appendix A2, transport of LNG from remote 

sources (modeled here as being from South East Asia) via ocean tanker requires 

23,137 Btu/mmBtu of energy and 1.65 gCO2e/MJ of GHG emissions are generated 

during the transport process. 

3.2 LNG Transport and Storage to California from Baja, Mexico to California 

The calculations are the same as presented in section 5 of Appendix A1, but with a 

transport distance of 250 miles from Baja, Mexico to California. The total energy use is 

4,679 Btu/mmBtu (Table 5.01 of Appendix A1). The GHG emissions are calculated to 

be 1.81 gCO2e/MJ of truck transport which has to be combined with 0.26 gCO2e/MJ of 

emissions from LNG storage (see Appendix A2 for LNG storage emission details) for a 

total of 2.07 gCO2e/MJ GHG emissions and is shown in Table A in the summary 

section. 
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SECTION 4. GHG EMISSIONS FROM VEHICLES 

4.1 Tank To Wheel (TTW) GHG Emissions 

GHG emissions are the same as detailed in section 6 of Appendix A1 and the total 

emissions are 58.5 gCO2e/MJ. 
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APPENDIX B 

LIQUEFIED NATURAL GAS (LNG) FROM NORTH AMERICAN AND 

REMOTE NATURAL GAS SOURCES PATHWAY INPUT VALUES 
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Parameters Units Values Note 

GHG Equivalent

CO2 1 CA-GREET Default 

CH4 25 CA-GREET Default 

N2O 298 CA-GREET Default 

VOC 3.1 CA-GREET Default 

CO 1.6 CA-GREET Default 

Natural Gas Recovery

Process Efficiency 97.2% CA-GREET Default 

Natural Gas Leak Rate 0.35% CA-GREET Default 

Fuel Shares 

Residual Oil 0.9% CA-GREET Default 

 Conventional Diesel 9.8% CA-GREET Default 

 Conventional Gasoline 0.9% CA-GREET Default 

Natural Gas 76.2% CA-GREET Default 

Electricity 0.9% CA-GREET Default 

Feed Loss (Leak) 11.4% CA-GREET Default 

Equipment Shares 

Small Boiler - Residual Oil 100% CA-GREET Default 

CO2 Emission Factor gCO2/mmBtu 85,049 CA-GREET Default 

Commercial Boiler - Diesel 25% CA-GREET Default 

CO2 Emission Factor gCO2/mmBtu 78,167 CA-GREET Default 

Stationary Reciprocating Eng. - Diesel 50% CA-GREET Default 

CO2 Emission Factor gCO2/mmBtu 77,349 CA-GREET Default 

Turbine - Diesel 25% CA-GREET Default 

CO2 Emission Factor gCO2/mmBtu 78,179 CA-GREET Default 

Stationary Reciprocating Eng. - 

Gasoline 

CO2 Emission Factor gCO2/mmBtu 50,480 CA-GREET Default 

Small Boiler - NG 50% CA-GREET Default 

CO2 Emission Factor gCO2/mmBtu 58,215 CA-GREET Default 

Stationary Reciprocating Eng. - NG 50% CA-GREET Default 

CO2 Emission Factor gCO2/mmBtu 56,388 CA-GREET Default 

Natural Gas Processing

Process Efficiency 97.2% CA-GREET Default 

Natural Gas Leak Rate 0.15% CA-GREET Default 

Fuel Shares 

 Conventional Diesel 0.9% CA-GREET Default 

Natural Gas 91.1% CA-GREET Default 

Electricity 2.8% CA-GREET Default 

Feed Loss (Leak) 5.1% CA-GREET Default 

Equipment Shares 

Commercial Boiler - Diesel 33% CA-GREET Default 

CO2 Emission Factor gCO2/mmBtu 78,167 CA-GREET Default 

Stationary Reciprocating Eng. - Diesel 33% CA-GREET Default 

CO2 Emission Factor gCO2/mmBtu 77,349 CA-GREET Default 

Turbine - Diesel 34% CA-GREET Default 

CO2 Emission Factor gCO2/mmBtu 78,179 CA-GREET Default 

Large Boiler - NG 50% CA-GREET Default 

CO2 Emission Factor gCO2/mmBtu 58,215 CA-GREET Default 
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Parameters Units Values Note

Large Turbine - NG 50% CA-GREET Default 

CO2 Emission Factor gCO2/mmBtu 58,196 CA-GREET Default 

Feed Loss 1.001 CA-GREET Default 

NG Liquefaction

NG Liquefaction Efficiency in CA 80% CA-GREET Default 

Process Fuels Shares 

Natural Gas 98% CA-GREET Default 

Electricity 2% CA-GREET Default 

Remote NG Processing Efficiency 90% Excluding gas processing 

Process Fuels Shares Assumed the same as NA NG 

Natural Gas Pipeline Transmission

Natural Gas Use 94% CA-GREET Default 

Electricity Use 6% CA-GREET Default 

Distance travel Miles 1,400 For NA NG to California

LNG Truck Transport 

Tanker Truck Size ton 15 fueled by diesel or LNG 

Distance travel Miles 50 from LNG plants in CA to CA filling stations 

 250 from LNG plants in Baja to CA filling stations

Fuel Economy Mi/gal 5 

Fugitive Emissions During Storage %/day 0.1%/day CA-GREET default 

Fugitive Emissions Recovery Rate 80% Industry Practice 

Vehicle Emissions 

Carbon in NG grams C/gram 

NG 72.4 CA-GREET default 

 

Fuels Properties LHV (Btu/gal) Density 

(g/gal) 

 

Crude 129,670 3,205 CA-GREET Default 

Residual Oil 140,353 3,752 CA-GREET Default 

 Conventional Diesel 128,450 3,167 CA-GREET Default 

 Conventional Gasoline 116,090 2,819 CA-GREET Default 

CaRFG 111,289 2,828 CA-GREET Default 

CARBOB 113,300 2,767 CA-GREET Default 

Natural Gas 83,686 2,651 NG Liquids 

Natural Gas NG gaseous: 930 Btu/scf