GREENHOUSE GAS 

LIFE-CYCLE EMISSIONS STUDY: 

Fuel Life-Cycle of 

U.S. Natural Gas Supplies and International LNG 

Prepared for: 

Sempra LNG

Prepared by: 

Advanced Resources International, Inc. 

and 

ICF International 

November 10, 2008 
 

 November 10, 2008 i

TABLE OF CONTENTS 

EXECUTIVE SUMMARY ................................................................................................ 1

Conclusions............................................................................................................................................... 4

OVERVIEW OF INPUT DATA, METHODOLOGY AND ASSUMPTIONS...................... 5

Background and Introduction .................................................................................................................... 5

Methodology Description – U.S. Natural Gas............................................................................................ 7

Exploration and Development ................................................................................................................................................ 8

Natural Gas Production .......................................................................................................................................................... 9

Natural Gas Processing ....................................................................................................................................................... 10

Natural Gas Transmission.................................................................................................................................................... 15

Natural Gas Distribution ....................................................................................................................................................... 17

End Use Consumption ......................................................................................................................................................... 17

Methodology Description – Liquefied Natural Gas .................................................................................. 19

Exploration and Development .............................................................................................................................................. 23

Natural Gas Production ........................................................................................................................................................ 24

Natural Gas Processing ....................................................................................................................................................... 28

Natural Gas Liquefaction and Loading................................................................................................................................. 29

LNG Shipping....................................................................................................................................................................... 30

LNG Storage and Regasification.......................................................................................................................................... 31

Natural Gas Transmission.................................................................................................................................................... 32

OVERVIEW OF SECTOR-SPECIFIC RESULTS.......................................................... 33

Exploration and Development ................................................................................................................. 33

Natural Gas Production ........................................................................................................................... 38

Natural Gas Processing .......................................................................................................................... 42

Natural Gas Liquefaction and Loading .................................................................................................... 52

LNG Shipping.......................................................................................................................................... 52

LNG Storage and Regasification............................................................................................................. 53

Natural Gas Transmission....................................................................................................................... 54

Natural Gas Distribution .......................................................................................................................... 56

End Use Consumption ............................................................................................................................ 56

EMISSIONS INTENSITY OF NATURAL GAS SUPPLIES FROM CANADA ............... 58

APPENDIX A - Environmental Impact Statements and Supporting Documentation 

used in this Analysis 
 

 November 10, 2008 ii

LIST OF EXHIBITS 

Exhibit 1: 2006 GHG Emissions Intensity from U.S. Natural Gas Supply ..................................................... 2 

Exhibit 2: 2006 GHG Emissions Intensity from LNG Supply Serving U.S. Market......................................... 2 

Exhibit 3: 2020 GHG Emissions Intensity from U.S. Natural Gas Supply ...................................................... 3 

Exhibit 4: 2020 GHG Emissions Intensity from LNG Supply Serving U.S. Market......................................... 3 

Exhibit 5: Process for Estimating GHG Emissions......................................................................................... 7 

Exhibit 6: EIA AEO Supply Regions............................................................................................................... 8 

Exhibit 7: Estimated Number of Production Wells, by Region and Resource Type, in 2006 and 2020........ 11 

Exhibit 8: Average CO2 Content (weighted by production), by Region and Resource Type, 

in 2006 and 2020......................................................................................................................................... 12 

Exhibit 9: Ranges of CO2 Content for Selected Regions by Basin and Resource Type.............................. 13 

Exhibit 10: EIA AEO Demand Regions........................................................................................................ 16 

Exhibit 11: Estimates of Key Activity Factors for Natural Gas Transmission, by Region, 

in 2006 and 2020......................................................................................................................................... 17 

Exhibit 12: Estimates of Key Activity Factors for Natural Gas Distribution, by Region, 

in 2006 and 2020......................................................................................................................................... 18 

Exhibit 13: Estimates of Key Activity Factors for Natural Gas Consumption, by Region, 

in 2006 and 2020......................................................................................................................................... 18 

Exhibit 14: Sources and Volumes of LNG Supplying U.S. LNG terminals in 2004, 2005, and 2006........... 20 

Exhibit 15: Existing and Proposed North American LNG Import Terminals ................................................. 21 

Exhibit 16: Assumed Capacity Expansions for Existing LNG Import Facilities, Sizes for New Facilities, and 

Assumed Capacity Utilization in 2020.......................................................................................................... 22 

Exhibit 17: LNG Imports and Estimated Transport Distance by Country of Origin in 2020 ......................... 23 

Exhibit 18: Key Activity Factors Affecting Emissions from Exploration and Development Activities to Serve 

U.S. LNG Requirements for 2006 and 2020 ................................................................................................ 24 

Exhibit 19: Representative Emission Factors for Exploration and Development for Trinidad and Tobago for 

2006 and 2020............................................................................................................................................. 25 

Exhibit 20: Representative Activity Factors for Fugitive Emissions for Trinidad and Tobago in the 

Production Sector for 2006 and 2020 .......................................................................................................... 26 

Exhibit 21: Selected Key Emission Factors for Fugitive Emissions for Trinidad and Tobago in the 

Production Sector ........................................................................................................................................ 27 

Exhibit 22: Key Activity Factors for Gas Liquefaction by Source Country for 2006 and 2020 ..................... 29 

Exhibit 23: Key Activity Factors for LNG Shipping, by Source Country and Delivery Point, for 2006.......... 30 

Exhibit 24: Key Activity Factors for LNG Shipping, by Source Country and Delivery Point, for 2020.......... 31 
 

 November 10, 2008 iii

Exhibit 25: Comparison of GHG Emissions for Exploration and Development for U.S. Natural Gas for 2006 

and 2020...................................................................................................................................................... 34 

Exhibit 26: Comparison of GHG Emissions for Exploration and Development for LNG Supplies Serving U.S. 

Markets for 2006 and 2020.......................................................................................................................... 35 

Exhibit 27: Exploration and Development Emissions Intensity by AEO Supply Region 

for 2006 and 2020 ....................................................................................................................................... 36 

Exhibit 28: Exploration and Development ................................................................................................... 37 

Exhibit 29: Emissions from Production Operations by AEO Supply Region - 2006 .................................... 39 

Exhibit 30: Emissions from Production Operations by AEO Supply Region - 2020 .................................... 39 

Exhibit 31: Natural Gas Production Emissions Intensity by AEO Supply Region for 2006 and 2020.......... 40 

Exhibit 32: Natural Gas Production Emissions Intensity for LNG, by Source Country, 

for 2006 and 2020 ....................................................................................................................................... 41 

Exhibit 33: Emissions from Natural Gas Processing of U.S. Supplies, by Region for 2006 ........................ 44 

Exhibit 34: Emissions from Natural Gas Processing of U.S. Supplies, by Region for 2020 ........................ 45 

Exhibit 35: Emissions Intensity for U.S. Natural Gas Processing by NEMS Supply Region, for 2006 (Mg). 46 

Exhibit 36: Emissions Intensity for U.S. Natural Gas Processing by NEMS Supply Region, for 2020 (Mg). 47 

Exhibit 37: Emissions from Natural Gas Processing for U.S. LNG Markets, by Country of Origin, 2006 .... 48 

Exhibit 38: Emissions from Natural Gas Processing for U.S. LNG Markets, by Country of Origin, 2020 .... 49 

Exhibit 39: Emissions Intensity for U.S. Natural Gas Processing by LNG Source Country, for 2006 (Mg) .. 50 

Exhibit 40: Emissions Intensity for U.S. Natural Gas Processing by LNG Source Country, for 2020 (Mg) .. 51 

Exhibit 41: Natural Gas Liquefaction Emissions Intensity for LNG, by Source Country, 

for 2006 and 2020 ....................................................................................................................................... 52 

Exhibit 42: Emissions from LNG Shipping in 2006...................................................................................... 53 

Exhibit 43: Emissions from LNG Shipping in 2020...................................................................................... 53 

Exhibit 44: Emissions from LNG Storage and Regasification in 2006......................................................... 53 

Exhibit 45: Emissions from LNG Storage and Regasification in 2020......................................................... 54 

Exhibit 46: Transmission Sector Emissions by AEO Demand Region for 2006 and 2020 .......................... 55 

Exhibit 47: Distribution Sector Emissions by AEO Demand Region for 2006 and 2020 (Mg) ..................... 56 

Exhibit 48: Consumption Emissions by AEO Demand Region for 2006 (tonnes CO2e) ............................. 57 

Exhibit 49: Consumption Emissions by AEO Demand Region for 2020 (tonnes CO2e) ............................. 57 

Exhibit 50: Life Cycle Emissions Analysis of the Canadian Natural Gas System (1995) ............................ 59 

Exhibit 51: Canadian Natural Gas Production, Export, and GHG Emission Trends in the Canadian National 

Inventory Report (1990-2005)...................................................................................................................... 60 

Exhibit 52: Canadian Natural Gas Production and Export Forecasts of the Canadian National Energy 

Board.............................................................................................................................................. 61
 

 November 10, 2008 1

EXECUTIVE SUMMARY 

The purpose of this study was to compare the greenhouse gas (GHG) emissions intensity 

(defined in terms of fuel life-cycle carbon dioxide-equivalent (CO2e) emissions per million British 

thermal units (MMBtu) of natural gas) for the two major natural gas supply chains in the United 

States -- natural gas produced in the United States and liquefied natural gas (LNG) imported 

into the United States. This is intended to include the entire supply chain analysis of CO2e 

emissions associated with natural gas delivered to California and other regions of the U.S. 

The comparison considered the GHG emissions associated with carbon dioxide (CO2), methane 

(CH4), and nitrous oxide (N2O). GHG emissions were estimated under current (defined for 

purposes of this study as 2006) and forecast (defined for purposes of this study as 2020) 

conditions, based on existing and expected future supplies and infrastructure. 

In all cases, for the national level comparison, the primary specification parameter is pounds of 

CO2e per MMBtu of natural gas consumed . 

In interpreting the results of this analysis, two important caveats must be kept in mind: 

• The analyses assume that there are no major changes to policies affecting GHG 

emissions controls, at either the state or federal level. In particular, it assumes that no 

emission trading systems or carbon taxes are established in the U.S. or in specific 

countries supplying natural gas for LNG to the U.S. market. 

• The analyses assume that new facilities/supplies for the 2020 case utilize state-of-the-art 

technology to minimize GHG emissions. 

The overall approach for estimating GHG emissions from the supply chain for the U.S. was 

derived in part from publicly available domestic greenhouse gas estimates, models, and 

analytical procedures developed in part by ICF International to support EPA in their GHG 

emission inventory work for the U.S. petroleum and natural gas sectors and for the American 

Petroleum Institute. 

All GHG emissions associated with the natural gas supply chain, from the wellhead to the 

burner tip, were estimated so that intensity of each supply chain component could be compared 

directly. The overall U.S. comparison was determined using total natural gas delivered to end 

users as a common denominator across all sectors, for both U.S. natural gas supply and 

imported LNG. 

The total GHG emissions intensity for U.S. natural gas supply was estimated to be 145.78 lb 

CO2e/MMBtu of natural gas in 2006, while imported LNG was estimated to have an intensity of 

145.92 lb CO2e/MMBtu. Consequently, on average for the U.S., the overall emissions intensity 

for the U.S. gas supply chain and imported LNG serving U.S. markets are quite comparable. 

Exhibit 1 displays the supply chain emissions intensity for the 2006 U.S. supply scenario, and 

Exhibit 2 displays the comparable graph for LNG supplies serving U.S. markets in 2006. 

Natural gas consumed by end-users has an emissions intensity of 117.06 lb CO2e/MMBtu, or 

over three-fourths of the total supply chain emissions. The other supply chain emissions are due 

to natural gas fugitives, venting, and combustion for energy to move the gas through the chain. 

Similarly, the GHG emissions intensity for U.S. natural gas supply was estimated to be 140.61 

lb CO2e/MMBtu in 2020, compared to an estimated emissions intensity for imported LNG of 

147.25 lb CO2e/MMBtu. Exhibit 3 displays the supply chain emissions intensity for the 2020 U.S. 

scenario, and Exhibit 4 displays the comparable graph for LNG supplies in 2020. 
 

 November 10, 2008 2

Exhibit 1: 2006 GHG Emissions Intensity from U.S. Natural Gas Supply 

13.10 0.50 145.78

6.64

5.49 117.06 2.98

0

20

40

60

80

100

120

140

160

Burner Tip Distribution Transmission Processing Production E&D Total

lb CO2e/MMBtu

Exhibit 2: 2006 GHG Emissions Intensity from LNG Supply Serving U.S. Market 

1.57 0.37 145.92 6.46

9.52

6.07

0.13 1.75 117.06 2.98

0

20

40

60

80

100

120

140

160

Burner Tip Distribution Transmission Regasification Shipping Liquefaction Processing Production E&D Total

lb CO2e/MMBtu
 November 10, 2008

3

Exhibit 3: 2020 GHG Emissions Intensity from U.S. Natural Gas Supply 

117.06 1.37 3.82

6.80

11.19 0.37 140.61

0

20

40

60

80

100

120

140

160

Burner Tip Distribution Transmission Processing Production E&D Total

lb CO2e/MMBtu

Exhibit 4: 2020 GHG Emissions Intensity from LNG Supply Serving U.S. Market 

147.25 0.60 2.08 8.14

10.60

5.59 0.02 1.80 117.06 1.37

0

20

40

60

80

100

120

140

160

Burner Tip Distribution Transmission Regasification Shipping Liquefaction Processing Production E&D Total

lb CO2e/MMBtu
 November 10, 2008

4

The conclusion to be drawn from comparisons between 2006 and 2020 for both supply sources 

is that improvements in efficiencies in limiting emissions in some sectors over time, on average, 

offset emissions from supplies from higher emission sources that will need to be tapped in the 

future. 

It is also important to note that while the emissions intensity of the U.S. sources of gas and LNG 

serving U.S. markets are comparable, substantial regional differences can exist for both sources. 

These differences are illustrated throughout this report for each step in the supply chain, for 

each of the regions considered in this assessment. Regional intensities, it should be noted, are 

based on regional and supply chain-specific throughput, and not always final consumption. 

Therefore, regional intensities cannot simply be added together to develop a regional supply 

chain intensity. 

Finally, it is important to note that this report does not reflect recent revised forecasts that 

project decreased U.S. and worldwide natural gas consumption compared to earlier forecasts, 

recent increases in U.S. gas production from unconventional sources, and the anticipated 

continued growth in production from these unconventional sources. 

Conclusions

Overall, the GHG emissions intensity of LNG imported to the U.S. relative to U.S. supplysourced gas is not significantly different. LNG has considerably lower emissions for 

development and production, due to the much higher productivity of the resources serving LNG 

export terminals. Far fewer wells are associated with producing the same volume of gas for 

LNG relative to U.S. natural gas supplies. Thus, other than the ultimate consumption of the gas 

itself, the largest sources of emissions are the production and gas processing stages. For LNG, 

the largest emissions are associated with the processing and liquefaction, shipping, and 

gasification. A major factor influencing the level of these emissions is the extent to which CO2

that would otherwise be vented during processing is/will be sequestered, and the distances over 

which the LNG would need to be shipped. 

The most significant factor, by far, contributing to GHG emissions from the natural gas 

sector, regardless of the source of the gas, is the volume of natural gas consumed. Even 

dramatic changes in other factors do not make a major contribution to the overall GHG 

“footprint” of the natural gas industry. Overall, GHG emissions overall are much larger for U.S. 

sources supply relative to LNG because the volume consumed it much larger. However, the 

emissions intensity is the same regardless of source. 

While the average emissions intensity of LNG or U.S.-sourced natural gas supplies is not 

materially different, there is considerable variability among the regional sources of gas 

supplies. This is true for different supply regions in the U.S. and for the different countries 

serving current and potential future demand for LNG in the United States. Since the global flow 

and regional consumption of natural gas are based on market conditions, and because 

greenhouse gas emissions are global in scope, this report focuses on average emissions for 

both domestically produced natural gas and international LNG likely to be consumed in the 

United States. When characterizing the emissions intensity of natural gas supply from a specific 

source -- either from domestic sources or foreign sources serving the international LNG market -

- the unique characteristics and variability of specific supply sources (domestic or international) 

are considered. 
 November 10, 2008

5

OVERVIEW OF INPUT DATA, METHODOLOGY AND 

ASSUMPTIONS 

Background and Introduction

The purpose of this study was to compare the greenhouse gas (GHG) emissions intensity 

(defined in terms of fuel life-cycle carbon dioxide-equivalent (CO2e) emissions per million British 

thermal units (MMBtu) of natural gas) for the two major natural gas supply chains in the United 

States -- natural gas produced domestically and liquefied natural gas (LNG) imported into the 

United States. This was intended to include the entire supply chain analysis of CO2e emissions 

associated with natural gas delivered to consumers. The analysis considers all GHG emissions 

associated with fuel consumption, flaring/venting, and fugitive methane emissions, and 

considers them through each step in the natural gas supply chain: 

• Exploration and development

• Production

• Gas processing

• Liquefaction (LNG only)∗

• Shipping (LNG only)

• Regasification (LNG only)

• Transmission

• Distribution

• Combustion/consumption.

The comparison excludes consideration of the emissions associated with both construction and 

decommissioning of the facilities associated with each supply source, for example: 

• For LNG, this excludes emissions associated with the construction and/or 

decommissioning of the liquefaction and gasification facilities, transport ships, etc. 

• For traditional gas development and production, it excludes emissions associated with 

construction/decommissioning of drilling rigs, compressors, gas processing facilities, etc. 

• For both, it excludes CO2e emissions associated with construction and/or 

decommissioning of pipelines, distribution systems, power plants, etc. 

The comparison considered the GHG emissions associated with carbon dioxide (CO2), methane 

(CH4), and nitrous oxide (N2O). GHG emissions estimates are provided under current (defined 

for purposes of this study as 2006) and forecast (defined for purposes of this study as 2020) 

conditions, based on existing and expected future supplies and infrastructure. In all cases, the 

primary specification parameter is pounds (lbs) of CO2e per MMBtu of natural gas. For the 

overall national comparison, GHG emissions intensities associated with each stage of the 

natural gas supply chain were determined using total natural gas delivered to end users as a 

common denominator across all sectors, for both U.S. natural gas supply and imported LNG. 

For the regional comparisons, on the other hand, the emissions intensities were based on the 

natural gas volumes associated with operations at each stage of the supply chain. For example: 

• The emissions intensities for exploration, development, and production are associated 

with the gas volumes produced. 

 

∗

 In the case of LNG, gas processing and liquefaction are part of a single process chain. 
 November 10, 2008

6

• The emissions intensities for gas processing, liquefaction, shipping, and regasification 

are associated with the gas volume throughput for these processes. 

• The emissions intensities for gas transmission, distribution, and consumption are 

associated with the ultimate natural gas volumes delivered and consumed. 

In interpreting the results of this analysis, two important caveats must be kept in mind: 

• The analysis assumes that there are no major changes to policies affecting GHG 

emissions controls, at either the state or federal level; in particular, it assumes that no 

emission trading systems or carbon taxes are established in the U.S. or in specific 

regions supplying natural gas for LNG to the U.S. market. 

• The analysis assumes that new facilities/supplies built after 2006 for the 2020 case 

utilize state-of-the-art technology to minimize GHG emissions. 

The analysis of the life cycle GHG emissions intensity of natural gas produced in U.S. versus 

LNG imported into the U.S. was performed jointly by Advanced Resources (ARI) and ICF 

International (ICF). ARI worked primarily to develop activity data to characterize the two 

scenarios, while ICF provided emissions factor data and modeled each supply chain. 

The overall approach for estimating GHG emissions from the supply chain for the U.S. was 

derived from ICF’s proprietary set of data, models, and analytical procedures, for the most part 

developed to support EPA in its GHG emission inventory work for the U.S. petroleum and 

natural gas sectors.1

 For the LNG supply chain, new data, assumptions and analytical 

procedures were developed specifically for this study. 

In general, GHG emissions were estimated for each sector at the lowest level of aggregation, i.e. 

at an individual source level. For example, emissions were estimated from individual sources 

like compressors, engines, wellheads, etc. There are a few exceptions to this, such as: 

• Offshore platform emissions, which are estimated on a per platform basis 

• Emissions from fuel combustion in production and processing, which are estimated at a 

national level. 

The individual sources of GHG emissions are classified into three broad categories: 

• Vented emissions from designed/intentional equipment or process vents 

• Fugitive emissions are unintentional equipment leaks 

• Combustion emissions are those associated with the fuel combustion. 

The emissions from each source were estimated as a product of individual emission factors and 

activity factors: 

• Emission factor is defined as the emissions rate per equipment or activity. 

• Activity factor is defined as an equipment count or frequency of an activity. 

The emissions from natural gas production and processing were primarily estimated using 

emission factors and activity factors from: 

• API’s Compendium of Greenhouse Gas Emissions Estimation Methodologies for the Oil 

and Gas Industry (API 2004) 

 

1

 http://www.epa.gov/climatechange/emissions/usinventoryreport.html 
 November 10, 2008

7

• U.S. Environmental Protection Agency (EPA) Study – Methane Emissions from the 

Natural Gas Industry (EPA/GRI 1996) 

• EPA study Estimates of Methane Emissions from the U.S. Oil Industry (EPA/ICF 1999). 

A schematic of the emissions estimation process is provided in Exhibit 5. 

Exhibit 5: Process for Estimating GHG Emissions 

The two years of interest for this study are 2006 and 2020, while the measurements made in the 

various EPA studies are from different historical years. The activity factors (and total emissions) 

needed to be adjusted to provide for updated emission estimates. Activity factor drivers were 

used to proportion activity factors in the reference study base year and then were used for each 

year of interest (either 2006 or 2020) in the same proportion, using the following formula: 

Analysis Year Activity Factor = (RSBY Activity Factor * Analysis Year Activity Factor Driver)

 RSBY Activity Factor Driver 

Where RSBY = Reference Study Base Year 

Methodology Description – U.S. Natural Gas 

The U.S. natural gas supply chain consists of six sectors: exploration and development, 

production, gas processing, transmission, distribution, and consumption. The current state of 

the U.S. natural gas industry is well defined in data from the U.S. Energy Information 

Administration (EIA). Greenhouse gas emissions from the natural gas industry are also 

estimated in the Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990 – 2005,

2

 so the 

estimate of emissions intensity for U.S. natural gas supply in 2006 should accurately reflect the 

current state of the industry. 

Projections to 2020 are subject to many factors, including changing natural gas prices and GHG 

emission legislation, which are outside the scope of this study. The emissions intensity 

estimates for 2020 are built primarily off of the EIA’s Annual Energy Outlook (AEO) for 2007.3

Some adjustments to the emissions profile of the U.S, gas industry have been made to 

characterize changing technology in 2020. The EPA Natural Gas STAR Program4

 tracks 

emission reductions from Partner companies in the U.S. natural gas industry; data from this 

program was used to project reductions to non-Partner companies and implementing best 

available technology industry-wide by 2020. The Natural Gas STAR Program reports reductions 

 

2

 http://www.epa.gov/climatechange/emissions/usinventoryreport.html 

3

 http://www.eia.doe.gov/oiaf/archive/aeo07/index.html 

4

 http://www.epa.gov/gasstar/ 

Model Inputs 

(Activity Drivers)

Natural Gas 

STAR Reductions

Activity Factors

Emission Factors

Emissions (for CH4, 

CO2, and N2O

Model Inputs 

(Activity Drivers)

Natural Gas 

STAR Reductions

Activity Factors

Emission Factors

Emissions (for CH4, 

CO2, and N2O
 November 10, 2008

8

for four sectors: Production, Processing, Transmission, and Distribution. No other sectors have 

reductions accounted for (i.e., E&D, Liquefaction, Shipping, Regasification, and Consumption). 

For purposes of this study, forecasts for U.S. upstream activities (exploration and development, 

production and processing) were based on ICF’s Hydrocarbon Supply Model (HSM). For both 

current (2006) and forecast (2020) activity, supply-related emissions are developed by AEO 

supply region and resource type: conventional gas (associated and non-associated) and 

unconventional gas (tight gas, gas shales, coalbed methane). Estimates were developed by 

play and basin, and then were aggregated to the AEO supply region, as represented in EIA’s 

Annual Energy Outlook (AEO). AEO supply regions are illustrated in Exhibit 6. 

Exhibit 6: EIA AEO Supply Regions 

Exploration and Development 

The two major GHG emissions sources associated with natural gas exploration and 

development include diesel combustion from drilling rigs, which is a function of the depth of the 

wells drilled, and natural gas venting and flaring during gas well drilling and completion 

operations, which is a function of the number and type of completion practices used. 

Data factoring into emissions included, by AEO supply region and resource type: 
 November 10, 2008

9

• Number of oil and gas wells drilled 

• Type of well (oil with associated gas or non-associated gas) 

• Well depth 

• Drilling time, in days per representative well 

• Number of completions per well drilled 

• Fraction of gas wells requiring hydraulic fracturing to stimulate production. 

U.S. natural gas well drilling in 2006 and 2020 was estimated using the ICF Hydrocarbon 

Supply Model (HSM). In 2006, over 35,000 exploratory and developmental wells were estimated 

to be drilled in the United States; this number was projected to decrease to a little over 20,000 

wells in 2020. The breakdown in well drilling by AEO supply region is summarized below: 

Estimated wells drilled 2006 2020

 

Northeast 14,191 5,975 

Midcontinent 6,383 4,381 

Rocky Mountain 6,530 4,678 

Southwest 3,123 1,904 

West Cost 130 206 

Gulf Coast 5,243 3,254

TOTAL 35,600 20,399 

For purposes of this analysis, it was assumed that well drilling rates averaged 200 feet per day,5

and that diesel fuel consumption in well drilling was 1.5 gallons per foot drilled.6

 The average 

depth of a typical or average well by AEO supply region was assumed to be as follows, based 

on data in the HSM: 

Supply Region

Average Well 

Depth (feet) 

Northeast 4,500 

Midcontinent 6,500 

Rocky Mountain 3,500 

Southwest 8,500 

West Coast 6,500 

Gulf Coast 10,500 

Natural Gas Production 

Natural gas is produced from associated gas wells that produce both oil and gas, nonassociated gas wells that produce gas only, and unconventional wells such as coal-bed 

methane wells. GHG emissions from natural gas production are a function of the amount of gas 

produced, the type of wells producing the gas, and the age and upkeep of producing wells. 

Specifically, the data factoring in GHG emissions estimation include the following: 

• Natural gas production volumes 

• Number of producing wells 

 

5

 Gaddy, Dean E., “Coiled-tubing drilling technologies target niche markets,” Oil and Gas Journal, January 

10, 2000 

6

 www.arb.ca.gov/ei/areasrc/ccosmeth/att_l_fuel_combustion_for_petroleum_production.doc 
 November 10, 2008

10

• Average gas/condensate production per well 

• Average CO2 content of produced gas 

• Average wellhead pressure, methane, and water content of gas 

• Portion of wells requiring workovers. 

For purposes of this analysis, all of these parameters were based on data from the HSM. 

Emissions from most sources in the natural gas production sector were estimated based on the 

EPA-derived emission factors.7 The number of these sources was estimated by adjusting the 

original factors in the EPA studies to 2006 and 2020 conditions based on the number of 

production wells in each AEO supply region for each of the years (2006 and 2020), as forecast 

by the HSM, and summarized in Exhibit 7: 

The primary GHG emission sources in the production sector are as follows: 

• Field separation equipment (heaters, separators, dehydrators, meters/piping) 

• Gathering compressors 

• Operations equipment (pneumatics, chemical injection pumps, Kimray pumps, 

dehydrator vents) 

• Condensate tanks 

• Combustion exhausts (engines, lease fuel, flares) 

• Well workovers and cleanups 

• Blowdowns 

• Upsets (pressure relief, mishaps). 

The number of these emission sources in 2006 and 2020 were estimated as a function of the 

number of producing wells in each of those years. 

CO2 emissions from lease fuel consumption associated with operating field equipment such as 

pumps, compressors, heaters, etc. are calculated for the production sector. Additional CO2 

emissions associated with fugitive leaks and venting of natural gas have also been calculated 

using the average regional CO2 content in produced natural gas. 

Natural Gas Processing 

After the gas is produced from the well, it is generally delivered to a gas processing facility, 

where the gas is processed to meet gas pipeline specifications. The configuration of each gas 

processing plant was estimated from details in the Annual Worldwide Processing Survey from 

the Oil and Gas Journal.

8

 

Data factoring into GHG emissions from gas processing are the number of number of 

processing plants, by type and the gas throughput of plants, again by type for each region. The 

major factors contributing to GHG emissions are the energy requirements for processing (which 

is function of gas composition), and the CO2 vented from processing (which is a function of the 

CO2 content of produced gas). 

 

 

7

 U.S. Environmental Protection Agency, Methane Emissions from the Natural Gas Industry (EPA/GRI) 

1996 

8

 See, for example, Warren True, “SPECIAL REPORT: Mideast leads global growth; shift from US, 

Canada holds,” Oil and Gas Journal, March 18, 2008 
 November 10, 2008

11

Exhibit 7: Estimated Number of Production Wells, 

by Region and Resource Type, in 2006 and 2020 

Emission Sources (Producing Wells) 2006 2020

Northeast Region 

Associated Gas Wells 47,034 54,744 

Non-associated Gas Wells 164,319 114,734 

Unconventional Gas Wells 0 48,398

 211,353 217,876 

Midcontinent Region 

Associated Gas Wells 65,903 84,722 

Non-associated Gas Wells 67,188 86,795 

Unconventional Gas Wells 6,726 32,810

 139,816 204,327 

Rocky Mountain Region 

Associated Gas Wells 13,579 19,206 

Non-associated Gas Wells 53,419 46,212 

Unconventional Gas Wells 22,195 81,495

 89,193 146,914 

Southwest Region 

Associated Gas Wells 55,301 44,012 

Non-associated Gas Wells 29,640 26,462 

Unconventional Gas Wells 6,519 25,531

 91,460 96,006 

West Cost Region 

Associated Gas Wells 22,189 32,965 

Non-associated Gas Wells 1,503 3,819 

Unconventional Gas Wells 0 1,817

 23,692 38,602 

Gulf Coast Region 

Associated Gas Wells 27,319 51,159 

Non-associated Gas Wells 60,715 57,025 

Unconventional Gas Wells 0 31,801

 88,034 139,985 

TOTAL US 

Associated Gas Wells 231,325 286,809 

Non-associated Gas Wells 376,784 335,048 

Unconventional Gas Wells 35,440 221,852

 643,549 843,709 

Both direct (combustion, fugitive and vented/flared) and indirect (imported electrical power) 

emissions are estimated for each U.S. processing plant. The carbon-dioxide (CO2), methane 

(CH4), and nitrous oxide (N2O) emissions for the natural gas processing sector were estimated 

using the ICF Gas Processing GHG Model for the base year 2006, and projected forward to 

2020. The model calculates source-specific CO2, CH4, and N2O emissions from individual gas 
 November 10, 2008

12

processing facilities in the United States. These data were developed based on initial work for 

the Gas Research Institute (GRI).9

 

The average CO2 content assumed for each AEO supply region, for both conventional and 

unconventional gas production, for each resource type, is shown in Exhibit 8, for 2006 and 2020. 

As shown, in most regions, based the mix of supply sources in the two years, the overall CO2 

content of produced gas in the region, on average, often does not change much. 

 

Exhibit 8: Average CO2 Content (weighted by production), 

by Region and Resource Type, in 2006 and 2020 

2006 Gas Composition 2020 Gas Composition 

Region Well Type 

CO2 Content in 

Produced Gas Well Type 

CO2 Content in 

Produced Gas

Northeast Conventional 0.9% Conventional 0.9% 

 Unconventional 7.4% Unconventional 7.4% 

 All 1.2% All 2.9% 

Gulf Coast Conventional 2.2% Conventional 2.2% 

 Unconventional 0.2% Unconventional 2.0% 

 All 2.1% All 2.1% 

Southwest Conventional 3.8% Conventional 3.8% 

 Unconventional 4.0% Unconventional 4.0% 

 All 3.8% All 3.9% 

Midcontinent Conventional 0.8% Conventional 0.8% 

 Unconventional 0.3% Unconventional 1.0% 

 All 0.7% All 0.8% 

Rocky Conventional 8.0% Conventional 8.0% 

Mountains Unconventional 2.0% Unconventional 4.0% 

 All 6.1% All 5.4% 

West Coast Conventional 0.2% Conventional 0.2% 

 Unconventional 0.0% Unconventional 0.0% 

 All 0.1% All 0.1% 

However, there can still be considerable variability within supply regions and between basins, as 

well as considerable variability even within the same basin. Based on the GRI database 

referenced above, 10 Exhibit 9 gives some examples of the variability in CO2 content that exists 

within supply regions and within basins. 

 

9

 Gas Research Institute, Gas Resource Database: Unconventional Natural Gas and Gas Composition 

Databases, Second Edition GRI-01/0136 (2001) 

10 Gas Research Institute, Gas Resource Database: Unconventional Natural Gas and Gas Composition 

Databases, Second Edition GRI-01/0136 (2001) 
 November 10, 2008

13

Exhibit 9: Ranges of CO2 Content for Selected Regions 

by Basin and Resource Type 

Region Basin Name Formation

No. of 

Reservoirs

Avg. CO2 

Content 

(%)

Min. CO2 

Content 

(%)

Max. CO2 

Content 

(%)

Ann 

Production 

(Bcf)

Undiscovered 

Conventional 

Resources 

(Bcf)

Undiscovered 

Unconventional 

Resources (Bcf)

Resource 

Type

GULF COAST WARRIOR BASIN CARTER 107 0.97 0 20.7 4.62 1,513 0

WARRIOR BASIN OTHER 71 0.17 0.1 0.4 6.372 359 0

MID-GULF COAST BASIN VALLEY 12 7.29 4.6 8.85 3.411 79 0

MID-GULF COAST BASIN HOSSTON 51 4.64 1.5 6.83 27.792 1,140 0

MID-GULF COAST BASIN SPORT 12 4.47 4.1 4.65 2.642 128 0

MID-GULF COAST BASIN T 10 12.26 6.1 42.35 23.767 5,132 0

MID-GULF COAST BASIN OTHER 140 1 0.1 4.2 9.87 1,008 0

MID-GULF COAST BASIN PALUXY 25 2.31 1.6 2.8 6.624 146 0

MID-GULF COAST BASIN RODESSA 24 2.82 2.5 4 8.524 134 0

MID-GULF COAST BASIN SLIGO 23 3.54 2.4 4.34 2.866 62 0

MID-GULF COAST BASIN OSA 41 3.63 0.9 5.1 2.747 23 0

MID-GULF COAST BASIN WASHITA 14 2.2 2.2 2.2 5.034 43 0

EAST TEXAS BASIN BOSSIER 45 2.38 2 2.4 25.733 118 73 Tight

EAST TEXAS BASIN VALLEY 208 2.19 0.8 3.1 464.39 796 37,561 Tight

EAST TEXAS BASIN PETTIT 188 1.02 0.5 2 35.573 254 0

EAST TEXAS BASIN RODESSA 192 1.35 0 2.4 13.699 191 0

EAST TEXAS BASIN E 83 1.91 0.5 2.4 7.273 254 0

LOUISIANA GULF COAST CHALK 10 3.87 3.87 3.87 1.36 0 0

LOUISIANA GULF COAST OSA 25 6.91 4.72 7.35 106.015 1,881 908 CoProd

TEXAS GULF COAST CHALK 45 4.73 4.7 5.2 220.351 352 1,015 Tight

TEXAS GULF COAST G 507 0.34 0 3.3 412.989 4,069 4,758 Tight

TEXAS GULF COAST WILCOX 1,358 3.28 0.14 17.9 991.211 14,017 15,671 Tight

TEXAS GULF COAST YEGUA 940 1 0.1 3 118.177 2,249 9,417 CoProd

NORTHEAST MICHIGAN BASIN SHALE 5 10.17 0 37 192.159 0 16,880 Shale

MICHIGAN BASIN OTHER 36 0.52 0 4.05 2.482 308 0

CENTRAL APPALACHIA 2.09

NORTHERN APPALACHIA 8.84

NORTHERN APPALACHIA 2.44

MIDCONTINENT ARKLA BASIN VALLEY 110 2.32 1.6 6.4 48.381 1,904 4,171 Tight

ARKLA BASIN OTHER 352 2.3 1.35 3.3 71.241 7,336 273 Tight

ARKLA BASIN PEAK 112 1.35 0.7 5.8 182.175 1,993 1,393 Tight

ARKOMA BASIN E 4 2 1.7 2 5.42 555 0

ARKOMA BASIN ATOKA 151 1.55 0 4.5 267.952 1,089 2,758 Tight

ARKOMA BASIN OTHER 652 0.93 0 4.8 121.381 418 0

ANADARKO BASIN CHESTER 243 0.48 0.1 14.6 54.526 2,826 0

ANADARKO BASIN DOUGLAS 72 3.58 0.05 10.9 24.294 989 0

ANADARKO BASIN HUNTON 128 3.33 0 8.37 50.289 332 212 Tight

ANADARKO BASIN MORROW 877 1 0 5.1 374.949 20,271 178 Tight

ANADARKO BASIN OTHER 2,221 0.69 0 2.9 297.555 11,235 0

ANADARKO BASIN RED FORK 135 1.24 0.1 2.3 144.312 5,199 4,726 Tight

ANADARKO BASIN SKINNER 63 1.09 0.1 3.5 29.951 471 0

ANADARKO BASIN VIOLA 44 2.27 0.2 2.65 3.315 115 0
 November 10, 2008

14

Exhibit 9: Ranges of CO2 Content for Selected Regions 

by Basin and Resource Type (continued) 

Region Basin Name Formation

No. of 

Reservoirs

Avg. CO2 

Content 

(%)

Min. CO2 

Content 

(%)

Max. CO2 

Content 

(%)

Ann 

Production 

(Bcf)

Undiscovered 

Conventional 

Resources 

(Bcf)

Undiscovered 

Unconventional 

Resources (Bcf)

Resource 

Type

ROCKY MTNS POWDER RIVER BASIN UNION 2 0.47 0.47 0.47 58.178 0 10,036 Coal

POWDER RIVER BASIN MUDDY 37 1.89 0.4 2.2 8.886 511 0

POWDER RIVER BASIN OTHER 78 0.91 0.1 14.3 1.038 748 0

WIND RIVER BASIN CODY 11 2.92 1.5 3 4.511 599 0

WIND RIVER BASIN UNION 25 2.04 0.3 4.85 48.759 393 8,280 Tight

WIND RIVER BASIN DE 10 3.96 1.3 5.1 4.842 735 4,541 Tight

WIND RIVER BASIN OTHER 58 3.31 0.1 3.95 9.267 59 540 Coal

GREEN RIVER BASIN DAKOTA 68 0.76 0 3.2 34.209 2,175 1,143 Tight

GREEN RIVER BASIN UNION 24 0.66 0.1 2.55 4.952 165 7,526 Tight

GREEN RIVER BASIN FRONTIER 113 0.69 0.1 4.15 168.205 2,786 7,342 Tight

GREEN RIVER BASIN LEWIS 65 0.66 0 2 29.332 459 205 Tight

GREEN RIVER BASIN DE 127 2.42 0.1 5.7 131.949 12,368 117,288 Tight

GREEN RIVER BASIN DE 6 0.04 0.04 0.04 0.07 0 4,660 Coal

GREEN RIVER BASIN NUGGET 15 2.39 1.4 2.95 8.994 377 0

GREEN RIVER BASIN OTHER 162 0.38 0.1 0.7 19.168 122 0

DENVER BASIN D SAND 129 1.25 0.9 2.15 0.805 54 0

DENVER BASIN DAKOTA 5 2.3 2.3 2.3 1.352 7 106 Tight

DENVER BASIN J SAND 180 2.46 0.3 2.7 27.293 435 2,426 Tight

UINTA BASIN DE 6 4.29 3.05 5.53 52.331 0 3,810 Coal

UINTA BASIN OTHER 53 0.9 0.04 1.7 3.411 197 0

PICEANCE BASIN DAKOTA 47 4.11 0.1 27.9 6.54 69 1,062 Tight

PICEANCE BASIN DE 43 2.9 0.8 18.3 50.768 1,583 43,843 Tight

PICEANCE BASIN DE 13 14.8 14.8 14.8 2.058 0 11,550 Coal

PICEANCE BASIN OTHER 74 0.54 0.3 37.5 4.709 60 0

PICEANCE BASIN WASATCH 13 1.48 0 3.2 6.498 61 821 Tight

SOUTHWEST SAN JUAN BASIN DAKOTA 11 0.96 0.4 4.8 123.001 259 6,352 Tight

SAN JUAN BASIN D 31 1.13 0.09 4.83 1.877 7 319 Tight

SAN JUAN BASIN D COAL 4 5.72 3.61 7.79 970.512 0 7,690 Coal

SAN JUAN BASIN OTHER 56 1.4 1.4 1.4 10.352 361 0

SAN JUAN BASIN CLIFFS 28 0.83 0.05 2.07 80.817 130 3,947 Tight

PERMIAN BASIN ATOKA 246 0.5 0 3.3 36.479 1,560 1,099 Tight

PERMIAN BASIN RGER 150 18.06 0.1 47.7 220.086 3,846 0

PERMIAN BASIN AN 81 4.98 0.1 21.3 12.637 656 0

PERMIAN BASIN OTHER 836 0.28 0 7.2 81.168 2,297 0

PERMIAN BASIN STRAWN 334 1.85 0.1 4.9 90.31 376 1,099 Tight

PERMIAN BASIN P 287 0.65 0 6.8 66.747 2,255 1,254 Tight

WEST COAST SAN JOAQUIN BASIN OTHER 40 0.1 0.1 0.1 6.814 823 0

SAN JOAQUIN BASIN STEVENS 10 4.3 4.3 4.3 0.759 13 0
 November 10, 2008

15

Natural Gas Transmission 

Emissions from the transport of natural gas in North America occur chiefly from compressor 

exhaust at compressor stations located along a natural gas pipeline. To calculate emissions, the 

amount of fuel used by the compressor was needed. The amount of fuel was calculated from 

the horsepower and efficiency of the compressor. Centrifugal compressor horsepower was 

obtained from the Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990 - 2005, while 

the value for compressor efficiency was obtained from the Standard Handbook of Petroleum 

and Natural Gas Engineering. Emissions factors from the API Compendium were then applied 

to the calculated fuel use, thus determining emissions from transmission compressors. 

Specifically, the data factoring into GHG emissions included the following activity factors: 

• Gas consumption associated with transmission 

• Transmission pipelines’ length 

• Representative length that produced gas travels in transmission lines 

• Number of LNG storage facilities w/liquefaction (not import terminals) 

• Total LNG storage facility (w/liquefaction) capacity 

• Number of LNG storage facilities w/o liquefaction (not import terminals) 

• Total LNG storage facility (w/o liquefaction) capacity 

• Required electricity for transmission/storage 

These data were aggregated by AEO demand region, which correspond to U.S. Bureau of the 

Census regions. These AEO demand regions are illustrated in Exhibit 10. 

The key activity factor drivers are summarized in Exhibit 11, by AEO demand region, for 2006 

and 2020. 
 November 10, 2008

16

Exhibit 10: EIA AEO Demand Regions 
 November 10, 2008

17

Exhibit 11: Estimates of Key Activity Factors for Natural Gas Transmission, 

by Region, in 2006 and 2020 

NATIONAL 

TOTAL

New 

England

Middle 

Atlantic

East 

North 

Central

West 

North 

Central

South 

Atlantic

East 

South 

Central

West 

South 

Central

 

Mountain Pacific

2006

Gas Consumption: Residential Quads 4.48 0.18 0.79 1.26 0.39 0.41 0.17 0.28 0.33 0.66

Transmission Pipelines Length miles 290,680

Average length that N. A. produced 

gas travels in transmission line miles 850 950 800 1400 450 200 200 200 1100

No. of LNG storage facilities 

w/liquefaction (not import terminals) 57 20 23 8 6 7 4 0 0 3

Total LNG storage facility 

(w/liquefaction) capacity Bcf 49 17 20 7 5 6 3 0 0 3

No. of LNG storage facilities w/o 

liquefaction (not import terminals) 39 12 18 5 4 5 3 0 0 2

Total LNG storage facility (w/o 

liquefaction) capacity Bcf 33 10 15 4 3 4 3 0 0 2

2020

Gas Consumption: Residential Quads 5.27 0.21 0.88 1.44 0.47 0.52 0.20 0.34 0.43 0.79

Transmission Pipelines Length miles 342,399

Average length that N. A. produced 

gas travels in transmission line miles 850 950 800 1,400 450 200 200 200 1,100

No. of LNG storage facilities 

w/liquefaction (not import terminals) 67 24 25 9 7 9 5 0 0 4

Total LNG storage facility 

(w/liquefaction) capacity Bcf 57 21 22 8 6 8 4 0 0 3

No. of LNG storage facilities w/o 

liquefaction (not import terminals) 46 14 20 6 5 6 4 0 0 2

Total LNG storage facility (w/o 

liquefaction) capacity Bcf 39 12 17 5 4 5 3 0 0 2

Natural Gas Distribution 

Natural gas distribution uses essentially no energy to move gas, as the operating pressures are 

low, and high pressure gas received from transmission pipelines can flow through the system 

with no additional compression. Therefore, nearly all emissions from this sector are fugitive 

emissions, which are a function of the types of pipes and services deployed. Specifically, data 

factoring into GHG emissions from the distribution sector include the following (by AEO demand 

region): 

• Type of distribution mains - cast iron, unprotected steel, protected steel, plastic 

• Type of services - unprotected steel, protected steel, plastic, copper. 

These data are summarized in Exhibit 12. 

Imported LNG and U.S. natural gas supply have identical emissions profiles in the distribution 

sector. 

End Use Consumption 

Emissions from consumption of natural gas by end users were estimated by assuming the 

complete combustion of all natural gas delivered. Consumption was disaggregated nationally by 

residential, commercial, industrial, transportation, and electric generation consumers, as 

reported in the 2007 EIA AEO. Small amounts of unburned hydrocarbons may be vented from 

combustion devices that are not 100% efficient, but the portion of unburned methane would 
 November 10, 2008

18

have an insignificant impact on overall emissions from end use consumption. This breakdown of 

end use consumption by AEO demand region and sector is provided in Exhibit 13. 

Again, imported LNG and U.S. natural gas supply have identical emissions profiles in the end 

use consumption sector. 

Exhibit 12: Estimates of Key Activity Factors for Natural Gas Distribution, 

by Region, in 2006 and 2020 

2006 TOTAL

New 

England

Middle 

Atlantic

East 

North 

Central

West 

North 

Central

South 

Atlantic

East 

South 

Central

 West 

South 

Central

 

Mountain Pacific California Only

Consumption: Residential Quads 4.48 0.18 0.79 1.26 0.39 0.41 0.17 0.28 0.33 0.66 0.52

Consumption: Commercial Quads 2.92 0.12 0.57 0.65 0.26 0.34 0.13 0.30 0.22 0.33 0.24

Consumption: Industrial Quads 6.76 0.08 0.35 1.15 0.44 0.55 0.47 2.41 0.31 0.99 0.80

Dist. Mains - Cast Iron miles 37,371 1,484 6,627 10,517 3,248 3,382 1,417 2,376 2,791 5,530 4,317

Dist. Mains - Unprotected steel miles 69,291 2,800 13,609 15,398 6,204 8,036 3,042 7,077 5,254 7,872 6,145

Dist. Mains - Protected steel miles 461,459 5,655 24,016 78,770 30,204 37,661 31,929 164,336 20,973 67,915 53,016

Dist. Mains - Plastic miles 525,788 20,875 93,232 147,972 45,695 47,581 19,932 33,436 39,265 77,801 60,733

Services - Unprotected steel 5,308,375 210,757 941,276 1,493,928 461,336 480,378 201,237 337,566 396,418 785,479 613,163

Services Protected steel 15,833,423 639,736 3,109,800 3,518,550 1,417,686 1,836,270 695,011 1,617,117 1,200,479 1,798,772 1,404,163

Services - Plastic 36,152,277 443,051 1,881,500 6,171,081 2,366,316 2,950,454 2,501,429 12,874,612 1,643,118 5,320,718 4,153,475

Services - Copper 1,212,260 48,130 214,957 341,165 105,354 109,703 45,956 77,089 90,529 179,378 140,026

2020

Consumption: Residential Quads 5.27 0.21 0.88 1.44 0.47 0.52 0.20 0.34 0.43 0.79 0.62

Consumption: Commercial Quads 3.75 0.15 0.67 0.81 0.34 0.52 0.18 0.39 0.29 0.39 0.28

Consumption: Industrial Quads 8.02 0.12 0.38 1.41 0.65 0.53 0.47 3.13 0.35 0.97 0.78

Dist. Mains - Cast Iron miles 37,371 1,514 6,230 10,173 3,297 3,692 1,435 2,390 3,035 5,605 4,363

Dist. Mains - Unprotected steel miles 69,291 2,814 12,390 14,942 6,246 9,669 3,313 7,247 5,383 7,287 5,672

Dist. Mains - Protected steel miles 572,919 8,917 26,910 101,027 46,196 38,041 33,661 223,790 25,187 69,190 53,856

Dist. Mains - Plastic miles 637,248 25,820 106,234 173,461 56,219 62,958 24,469 40,760 51,750 95,577 74,396

Services - Unprotected steel 5,308,375 215,082 884,947 1,444,956 468,314 524,452 203,829 339,538 431,084 796,173 619,730

Services Protected steel 15,833,423 642,948 2,831,222 3,414,338 1,427,242 2,209,435 757,111 1,655,918 1,230,153 1,665,056 1,296,055

Services - Plastic 47,827,785 744,397 2,246,465 8,433,804 3,856,500 3,175,731 2,810,060 18,682,190 2,102,602 5,776,036 4,495,981

Services - Copper 1,459,297 59,127 243,276 397,225 128,742 144,174 56,033 93,341 118,507 218,872 170,367

Exhibit 13: Estimates of Key Activity Factors for Natural Gas Consumption, 

by Region, in 2006 and 2020

Gas Consumption in Sector, in Quads

2006 TOTAL

New 

England

Middle 

Atlantic

East 

North 

Central

West 

North 

Central

South 

Atlantic

East 

South 

Central

 West 

South 

Central

 

Mountain Pacific

California 

only

National 21.78 0.79 2.20 3.68 1.26 2.19 1.02 5.73 1.75 3.16 2.50

Residential 4.48 0.18 0.79 1.26 0.39 0.41 0.17 0.28 0.33 0.66 0.52

Commercial 2.92 0.12 0.57 0.65 0.26 0.34 0.13 0.30 0.22 0.33 0.24

Industrial 6.76 0.08 0.35 1.15 0.44 0.55 0.47 2.41 0.31 0.99 0.80

Elec. Generarion 5.88 0.40 0.43 0.54 0.05 0.81 0.17 2.07 0.54 0.87 0.71

Lease & Plant Fuel 1.12 0.00 0.01 0.01 0.03 0.02 0.03 0.53 0.22 0.27 0.21

Pipeline Fuel 0.58 0.01 0.04 0.06 0.08 0.05 0.06 0.13 0.12 0.03 0.02

Transportation 0.04 0.00 0.01 0.01 0.00 0.01 0.00 0.00 0.00 0.01 0.01

2020

National 26.30 1.07 2.59 4.34 1.67 2.74 1.43 6.93 2.05 3.48 2.75

Residential 5.27 0.21 0.88 1.44 0.47 0.52 0.20 0.34 0.43 0.79 0.62

Commercial 3.75 0.15 0.67 0.81 0.34 0.52 0.18 0.39 0.29 0.39 0.28

Industrial 8.02 0.12 0.38 1.41 0.65 0.53 0.47 3.13 0.35 0.97 0.78

Elec. Generarion 7.19 0.56 0.60 0.59 0.08 1.05 0.48 2.38 0.62 0.82 0.67

Lease & Plant Fuel 1.21 0.00 0.01 0.01 0.03 0.02 0.03 0.51 0.23 0.37 0.30

Pipeline Fuel 0.76 0.01 0.05 0.07 0.10 0.08 0.06 0.17 0.12 0.12 0.09

Transportation 0.09 0.01 0.01 0.01 0.01 0.02 0.01 0.01 0.01 0.01 0.01
 November 10, 2008

19

Methodology Description – Liquefied Natural Gas 

Imported LNG shares the same six supply chain steps as for U.S. natural gas supply; and 

includes three additional steps: liquefaction and loading, shipping, and regasification and 

storage. However, it is important to note that in the case of LNG, gas processing and 

liquefaction are generally consolidated as part of liquefaction facility operations. For purposes 

of this analysis, emissions from small, land-based peak shaving LNG facilities were not 

considered. In addition, it was assumed that LNG from Alaska would continue to serve 

Japanese, rather than U.S., markets. 

The United States currently has only five active LNG import terminals along the East and Gulf 

coasts. Countries importing LNG to the U.S. in 2006 were Algeria, Egypt, Nigeria, and Trinidad 

& Tobago. The EIA tracks LNG imports delivered to these terminals, but does not report data on 

the activities upstream of the import terminals in the countries of origin. Downstream of the 

import terminals, LNG is regasified and enters the U.S. transmission and distribution systems as 

any other source of supply of natural gas. Natural gas losses through fugitives, venting, and 

consumption upstream of the LNG import terminal were estimated to back calculate the amount 

of natural gas that must be produced in each foreign country to satisfy market requirements for 

LNG. 

Actual data on LNG imports and the sources of those LNG supplies were used to develop the 

supply and emissions characterization for 2006. This information is provided below: 

Existing LNG 

Terminals 

Capacity 

(Bcf/d) 

Capacity 

(Bcf/year)

2006 

Imports 

(Bcf/year) 

2006 

Capacity 

Utilization 

2006 

Imports 

(Bcf/day) 

Everett, MA 1.035 378 176 47% 0.48 

Cove Pt., MD 1.000 365 117 32% 0.32 

Elba Island, GA 1.200 438 147 34% 0.40 

Lake Charles, LA 2.100 767 144 19% 0.39 

Gulf Gateway, LA 0.500 183 0.453 0% 0.00

 5.835 2,130 584 27% 1.60 

Source: FERC (Capacity), EIA (Imports) 

The data on sources or countries of origin of LNG imports for 2006 were based on data 

acquired by the U.S. Department of Energy11 and reported by EIA.12 Data on capacity were 

obtained from Federal Energy Regulatory Commission (FERC).13 The sources and volumes of 

LNG supplying these terminals in 2004, 2005, and 2006 are summarized in Exhibit 14:

 

11 http://www.fe.doe.gov/programs/gasregulation/analyses/Analyses.html 12 http://tonto.eia.doe.gov/dnav/ng/ng_move_poe1_a_EPG0_IML_Mmcf_a.htm 13 http://www.ferc.gov/industries/lng/indus-act/terminals/exist-prop-lng.pdf 
 November 10, 2008

20

Exhibit 14: Sources and Volumes of LNG Supplying 

U.S. LNG terminals in 2004, 2005, and 2006 

(All volumes in MMcf/year) 

As demand for LNG increases, additional import terminals will likely be constructed along the 

U.S. coasts. The FERC tracks existing and proposed LNG terminals; there are currently 21 new 

LNG terminals approved by FERC and many more terminals are proposed.14 Exhibit 15 shows 

the locations of proposed LNG import terminals in North America. Not all of these terminals will 

be built. 

 

14 http://www.ferc.gov/industries/lng/indus-act/terminals/exist-prop-lng.pdf 

2004 2005 2006

% of U.S 

Total in 2006

U.S. Total 652,015 631,260 583,537

From Algeria 120,343 97,157 17,449 3%

Cove Point, MD 33,554 35,222 17,449 3%

Lake Charles, LA 86,789 61,935 0

From Australia 14,990 0%

Lake Charles, LA 14,990 0 0

From Egypt 72,540 119,528 20%

Cove Point, MD 0 22,591 14,575 2%

Elba Island, GA 0 24,891 42,411 7%

Lake Charles, LA 0 25,058 62,542 11%

From Malaysia 19,999 8,719 0%

Gulf Gateway, LA 0 2,624 0

Lake Charles, LA 19,999 6,095 0

From Nigeria 11,818 8,149 57,292 10%

Cove Point, MD 2,986 0 0

Elba Island, GA 0 2,895 0

Gulf Gateway, LA 0 2,574 0

Lake Charles, LA 8,831 2,681 57,292 10%

From Oman 9,412 2,464 0%

Lake Charles, LA 9,412 2,464 0

From Qatar 11,854 2,986 0%

Lake Charles, LA 11,854 2,986 0

From 

Trinidad/Tobago 462,100 439,246 389,268 67%

Cove Point, MD 172,753 163,876 84,590 14%

Elba Island, GA 105,203 104,276 104,356 18%

Everett, MA 173,780 168,542 176,097 30%

Gulf Gateway, LA 0 453 0%

Lake Charles, LA 10,364 2,552 23,773 4%

From Other 

Countries 1,500 0%

Lake Charles, LA 1,500 0 0 0%
 November 10, 2008

21

Exhibit 15: Existing and Proposed North American LNG Import Terminals 

New sources of LNG supplies will also come online as LNG export terminals are constructed 

worldwide in areas of abundant gas supply to serve increasing worldwide requirements for LNG, 

including increasing requirements in the U.S. 

For purposes of this analysis, the characterization of future supplies of LNG delivered to the U.S. 

was developed by ARI. Estimates for total LNG imported into the U.S. in 2020 were based on 

the AEO 2007 forecasts. Estimates for future increases of U.S. LNG import capacity were 

developed, which included both expansions of existing facilities and the building of new facilities 

on the East Coast, Gulf Coast, and West Coast. Expansions of existing facilities were based on 

literature reports15 and numerous company press releases. 

EIA’s 2007 Annual Energy Outlook forecasts that 3.69 trillion cubic feet (Tcf) of natural gas will 

be imported into the U.S. in 2020.16 Consistent with this forecast, this analysis assumed the 

following: 

• Expansions of each of the existing LNG import terminals on the Gulf Coast, along with 

three new facilities constructed on the Gulf by 2020 

 

15 U.S. Department of Energy, Office of Fossil Energy, Liquefied Natural Gas: Understanding the Basic 

Facts, DOE/FE-0489, August 2005 

(http://www.fe.doe.gov/programs/oilgas/publications/lng/LNG_primerupd.pdf) 16 The more recent AEO (2008) now forecasts that LNG imports into the U.S. in 2020 will be 2.37 Tcf, a 

36% drop in LNG imports compared to the forecast for 2020 in the 2007 AEO. 
 November 10, 2008

22

• Expansions of existing LNG import terminals on the East Coast, along with one new 

East Coast facility 

• One new West Coast facility, probably built in Mexico in Baja California. 

The assumed capacity expansions for existing facilities, sizes for new facilities, and their 

assumed capacity utilizations in 2020 are summarized in Exhibit 16. 

Exhibit 16: Assumed Capacity Expansions for Existing LNG Import Facilities, Sizes for New 

Facilities, and Assumed Capacity Utilization in 2020 

Existing LNG 

Terminals 

2006 

Capacity 

(Bcf/d) 

Assumed 

Capacity 

Expansion 

(Bcf/d) 

2020 

Capacity 

(Bcf/year) 

Est. 2020 

Imports 

(Bcf/year)

Est. 

2020 

Imports 

(Bcf/day) 

2020 

Capacity 

Utilization

Everett, MA 1.035 0.000 378 268 0.73 71% 

Cove Pt., MD 1.000 0.800 657 493 1.35 75% 

Elba Island, GA 1.200 0.900 767 575 1.58 75% 

Lake Charles, LA 2.100 0.000 767 575 1.58 75% 

Gulf Gateway, LA 0.500 0.000 183 137 0.38 75% 

 5.835 1.700 2,750 2,048 5.61 

Representative New 

LNG Terminals 

2006 

Capacity 

(Bcf/d) 

Assumed 

Capacity 

Expansion 

(Bcf/d) 

Capacity 

(Bcf/year) 

Est. 2020 

Imports 

(Bcf/year)

Est. 

2020 

Imports 

(Bcf/day) 

2020 

Capacity 

Utilization

Other Gulf 4.000 1,460 1,095 3.00 75% 

Baja California, Mex. 1.500 548 411 1.13 75% 

East Coast 0.500 183 137 0.38 75% 

 6.000 2,190 1,643 4.50 

Total 

Capacity/Imports 5.835 7.700 4,940 3,690 10.11 

LNG imports forecast for 2020 in 2007 AEO 3,690 10.11 

Again, these assumptions for new facilities were based on selected proposed LNG terminals 

that have received FERC approval. 

To provide the gas supplies to meet these LNG import requirements in 2020, the following was 

assumed: 

• The sources of gas to East Coast (3 existing plus 1 new facility) would be Trinidad & 

Tobago, Egypt, Nigeria, Algeria, Norway, and Qatar 

• The sources of gas to the Gulf Coast (2 existing plus 4 new facilities) would be Nigeria, 

Egypt, Algeria, Trinidad & Tobago, and Norway 

• The sources of gas to the Baja California facility would be Russia, Indonesia/Papua New 

Guinea, and Australia. 

The primary factors leading to these assumptions for future supply sources of LNG to the U.S. 

include the establishment of existing, long-term relationships, the relative cost of supply 

(primarily related to transportation distance), and the anticipated ownership of both liquefaction 

facilities and receiving terminals.17,18,19

 

17 http://intelligencepress.com/features/lng/terminals/lng_terminals.html 
 November 10, 2008

23

The breakdown of 2020 LNG imports by country of origin for the East Coast, Gulf Coast, and 

West Coast facilities is summarized in Exhibit 17, along with the estimated transport distance 

from the country of origin to the respective delivery locations.20,21

Exhibit 17: LNG Imports and Estimated Transport Distance by Country of Origin in 2020 

T & T Nigeria Egypt Algeria Russia Australia Indonesia Qatar Norway

Gulf Coast 361 335 351 361 396

East Coast 368 354 157 515 79

West Coast 205 123 82

TOTAL 730 689 509 361 205 123 82 515 475

2006 Exports 584 628 528 844 702 1,074 1,110 0

2006 Capacity 735 863 594 1,104 562 1,400 941 200

Planned Exp 466 920 341 339

Other Expansions 919 1,079 743 1,380 702 500 1,176 250

TOTAL 919 1,079 743 1,380 466 1,622 841 1,176 589

Distances between Various Regions (miles)

Gulf Coast 2,200 6,100 6,500 4,700 5,000

East Coast 2,000 5,000 5,000 8,000 3,800

West Coast 4,000 7,500 7,000

Volumes of LNG (Bcf/year) to Various Regions - 2020

Exploration and Development 

The activity factors and emission factors affecting emissions from exploration and production 

activities serving LNG exports are the same as those for U.S. natural gas supply, and the 

drivers establishing the activity factors are also essentially the same. U.S. natural gas is 

produced through a mix of associated, non-associated, and unconventional oil and gas wells; 

the average natural gas production rate from individual wells in the U.S. is only around 30 

million cubic feet per year. In contrast, natural gas wells from countries exporting LNG can have 

production rates of nearly 20 million cubic feet per well per day. The larger number of wells 

needed to produce the same amount of gas in the U.S. requires more equipment, more activity 

factors, and consequently more fugitive and venting emissions, than that associated with 

producing gas to serve as the supply for LNG exports. 

In the process of assessing LNG imports, the emissions intensity associated with only wells 

drilled (oil and gas) for the purposes of producing gas to meet the demand requirements of the 

United States were counted in the supply chain emissions. Well drilling activities associated with 

LNG export terminals anticipated to meet U.S. demand were estimated to be 144 wells in 2006 

and 820 wells in 2020. 

The number of wells required in each source country was estimated by dividing the anticipated 

supply volume from that country by the expected average production per well from the source 

fields. Estimates of typical production per well, along with the average depth per well, were 

developed primarily from country statistics, where reported, and from a variety of Environmental 

Impact Statements (EISs) and supporting documentation prepared for the proposed export 

 18 Energy Information Administration, “U.S. LNG Markets and Uses, June 2004 Update,”, June 2004 19 http://www.energy.ca.gov/lng/documents/2005-08_EXISTING_LNG_EXPORT_WORLDWIDE.PDF 

20 True, Warren R., “LNG questions loom amid wave of project completions,” Oil and Gas Journal, 

January 7, 2008 

21 Energy Information Administration, “The Global Liquefied Natural Gas Market: Status and Outlook,” 

DOE/EIA-0637, December 2003 (http://www.eia.doe.gov/oiaf/analysispaper/global/index.html) 
 November 10, 2008

24

terminals. A complete listing of all of the EISs and supporting documentation used this analysis 

is provided in Appendix A. 

The key activity factors affecting emissions from exploration and development activities to serve 

U.S. LNG requirements for 2006 and 2020 are summarized in Exhibit 18, by source of supply. 

Exhibit 18: Key Activity Factors Affecting Emissions from Exploration and Development Activities 

to Serve U.S. LNG Requirements for 2006 and 2020 

T&T Nigeria Egypt Algeria

Required Supply Bcf 436 67 139 20

MMcf/d 1,200 186 386 55

Rep. Well Depth feet 10,000 10,000 10,500 15,000

No. of wells drilled 72 22 46 4

Drilling Time Days/well 50 50 53 75

No. of Completions 61 19 39 3

T&T Nigeria Egypt Algeria PNG Russia Australia Qatar Norway

Required Supply Bcf 826 811 603 422 98 232 148 633 540

MMcf/d 2,248 2,214 1,647 1,148 269 634 406 1,734 1,479

Rep. Well Depth feet 10,000 10,000 10,500 15,000 12,000 15,000 13,500 10,000 10,000

No. of wells drilled 133 261 194 54 18 33 14 39 75

Drilling Time Days/well 50 50 53 75 60 75 68 50 50

No. of Completions 113 222 165 46 14 26 11 35 60

2020

2006

Representative emission factors for exploration and production for Trinidad and Tobago, which 

served as a major source of LNG imports to the U.S. in 2006, and is anticipated to also play a 

major role in 2020, are summarized in Exhibit 19. 

Natural Gas Production 

Again, because of the much larger number of wells needed to produce the same amount of gas 

in the U.S. compared to that required to produce the same amount of LNG, U.S. production will 

have considerably greater fugitive and venting emissions from production operations. 

Again, estimates of production per well, the relative supplies coming from associated gas (with 

condensate) and non-associated gas wells, the distances from the producing fields to the export 

terminals, and average gas composition, were based primarily on estimates reported in the 

variety of EISs and supporting documentation described above and referenced in Appendix A. 

The key activity factors affecting emissions from production activities to serve U.S. LNG 

requirements for 2006 and 2020 are summarized in Exhibit 20, by source of supply. 

Representative emission factors for fugitive emissions for Trinidad and Tobago in the production 

sector for 2020 are summarized in Exhibit 21. 
 November 10, 2008

25

Exhibit 19: Representative Emission Factors for Exploration and Development for Trinidad and 

Tobago for 2006 and 2020 

Trinidad & Tobago

 Carbon Dioxide Emissions

Emission Sources 

CO2 Emissions 

Factor 

Activity 

Factor 

CO2

Emissions

 (Mg) 

 

Drilling and Well Completion 

Completion Venting and 

Flaring 192,469 scf/comp 90.05 completions/year 899.32

Well Drilling Venting 106.72 scf/well 132.94 wells 0.7362

Well Drilling Combustion 152.79 tonnes/well 132.94 wells 20,312

Methane Emissions

Emission Sources 

CH4 Emissions 

Factor 

Activity 

Factor 

CH4

Emissions

 (Mg) 

 

Drilling and Well Completion 

Completion Venting and 

Flaring 4,993,593 scf/comp 90.05 completions/year 8,660

Well Drilling Venting 2,769 scf/well 132.94 wells 7.09

 

 
 November 10, 2008

26

Exhibit 20: Representative Activity Factors for Fugitive Emissions for Trinidad and Tobago in the 

Production Sector for 2006 and 2020 

T&T Nigeria Egypt Algeria

Gas Production Tcf 0.436 0.067 0.139 0.020

Assoc. Gas Wells 23 22 39 3

Non-ass. Gas Wells 38 0 0 0

Avg. Gas Prod/Well MMcfd 20 8 10 18

Condensate Prod. MMbbl 6.94 5.5 9.45 2.0

WH Pressure psig 250 250 250 250

Wells workovers 12 4 8 1

Dist. To export facility miles 125 50

CH4 content vol % 85 88 92 90

CO2 content vol % 0.8 0.8 2.0 2.0

T&T Nigeria Egypt Algeria PNG Russia Australia Qatar Norway

Gas Production Tcf 0.826 0.811 0.603 0.422 0.098 0.232 0.148 0.633 0.540

Assoc. Gas Wells 23 148 39 30 14 0 0 0 0

Non-ass. Gas Wells 90 74 126 16 0 26 11 35 60

Avg. Gas Prod/Well MMcfd 20 10 10 25 19 24 37 50 25

Condensate Prod. MMbbl 12.99 65.1 40.27 41.3 2.6 0.02 0.00 438 8.97

WH Pressure psig 250 250 250 250 250 250 250 250 250

Wells workovers 23 44 33 9 3 5 2 7 12

Dist. To export facility miles 150 100 184 75 50 89

CH4 content vol % 85 88 88 88 88 95 80 90 85

CO2 content vol % 0.8 0.8 2.0 2.0 5.0 0.3 7.0 2.0 8.0

2006

2020
 November 10, 2008 

27

Exhibit 21: Selected Key Emission Factors for Fugitive Emissions for 

Trinidad and Tobago in the Production Sector 

Emission Sources Units 

CO2

Emission 

Factor 

CH4

Emission 

Factor 

Gas Wells 

Associated Gas Wells scfd/well 0.000 0.000 

Non-associated Gas Wells scfd/well 0.925 39.311 

Unconventional Gas Wells scfd/well 0.180 0.000 

Field Separation Equipment 

Heaters scfd/heater 1.465 62.256 

Separators scfd/sep 3.097 131.617 

Dehydrators scfd/dehy 2.313 98.299 

Meters/Piping scfd/meter 1.343 57.067 

Gathering Compressors 

Small Reciprocating Comp. scfd/comp 6.796 4,610.202 

Large Reciprocating Comp. scfd/comp 385.914 16,401.332 

Large Reciprocating Stations scfd/station 209.304 8,895.418 

Pipeline Leaks scfd/mile 1.349 57.334 

Normal Operations 

Pneumatic Device Vents scfd/device 8.756 372.145 

Chemical Injection Pumps scfd/pump 6.294 267.513 

Kimray Pumps scf/MMscf 25.178 1,070.051 

Dehydrator Vents scf/MMscf 6.995 297.284 

Condensate Tank Vents 

Tanks w/o Control Devices scf/bbl 3.528 21.870 

 Tanks w/ Control Devices scf/bbl 0.706 4.374 

Well Workovers 

Conventional Gas scfy/w.o. 62.284 2,647.081 

Blowdowns 

Vessel BD scfy/vessel 1.980 84.137 

Pipeline BD scfy/mile 7.843 333.312 

Compressor BD scfy/comp 95.787 4,070.939 

Compressor Starts scfy/comp 214.289 9,107.297 

Upsets 

Pressure Relief Valves PRV 0.863 36.675 

Mishaps miles 16.980 721.637 
 November 10, 2008 

28

Natural Gas Processing 

Again, data factoring into GHG emissions from gas processing associated with LNG is 

equivalent to that for U.S. natural gas supply, which is primarily a function of gas throughput. 

The major factors contributing to GHG emissions are the energy requirements for processing 

(which is a function of gas composition), and the CO2 vented from processing (which is a 

function of the CO2 content of produced gas). The average CO2 content of gas produced in 

each country of origin exporting LNG to the U.S. was shown in Exhibit 20, along with the 

references from which those values were derived. 

Gas processing emissions in LNG exporting countries was estimated from the proprietary ICF 

Gas Processing GHG Model. U.S. plants of similar size and configuration necessary to handle 

gas produced in foreign countries were selected to model the processing emissions associated 

with exported LNG. This structure was utilized since it was that already established for 

developing emissions from natural gas processing from U.S. source gas. This was done for 

modeling convenience, and does not necessarily reflect the process train for LNG. Natural gas 

processing for LNG generally occurs at the LNG liquefaction plant and is integrated into that 

process; i.e., it is generally not a stand-alone operation. 

The representative gas processing facilities assumed to estimate the GHG emissions were 

required to include Acid Gas Removal (AGR) units for the removal of CO2 and hydrogen sulfide 

(H2S) where and in the amounts present, along with dehydrators with molecular sieves for the 

extraction of water from the natural gas feed, as these impurities will cause difficulties in gas 

liquefaction downstream of the gas processing plant. The representative gas processing 

facilities also required fractionation for the removal of heavy hydrocarbons when the throughput 

was associated gas (which included condensate production), whereas, no fractionation was 

assumed to be required for non-associated gas throughput. Gas throughput and CO2 content of 

the gas were adjusted in the representative facility to match the production characteristics of the 

producing country. 

The one factor that may be somewhat different for imported LNG relative to U.S. natural gas 

supply (except for selected fields in certain areas of the country, like West Texas and Wyoming) 

is that several large LNG projects overseas currently plan to permanently sequester the CO2

separated in nearby geologic formations. Such plants include Gorgon (Australia), In Salah 

(Algeria), Tangguh (Papua/New Guinea), Snohvit (Norway), and possibly others. 

The assumed gas throughput of the plants anticipated to serve U.S. LNG requirements for 2006 

and 2020 are summarized below, by source of supply. 

T&T Nigeria Egypt Algeria

Gas throughput MMcfd 1,163 179 371 53

T&T Nigeria Egypt Algeria PNG Russia Australia Qatar Norway

Gas throughput MMcfd 2,185 2,143 1,591 1,116 260 629 392 1,617 1,447

2006

2020
 November 10, 2008 

29

Natural Gas Liquefaction and Loading 

The volume of natural gas consumed by the liquefaction process was estimated by conducting 

an energy and material balance around the LNG liquefaction plant and loading activities. 

Specifications from the Pluto LNG and Darwin LNG projects in Australia, as well as the 

ConocoPhillips Optimized Cascade process, were utilized to construct a generic LNG 

liquefaction plant and loading model.22 

The fuel required for the loading activities is dependent on the natural gas consumed by the 

electric power generators and boil off compressors. The natural gas fired generators are used to 

run the loading pump used to deliver LNG from the storage tanks to the LNG carriers, as well as 

satisfy the base electricity needs of the liquefaction plant. The loading pump horsepower was 

calculated by assuming the LNG shipping carrier specifications and the loading pipe parameters. 

These generators have a higher fuel requirement during loading operations, however, they are 

assumed to be functional throughout the year. 

The LNG liquefaction and storage plant was assumed to have boil-off compressors sized to 

meet the daily boil-off rate, and included the assumption of an additional compressor to handle 

gas from the ship vapor return lines during loading activities. The amount of natural gas required 

to fuel the boil-off compressor is based on the horsepower requirement of the compressor, and 

is assumed to operate throughout the year. The ship vapor recovery compressor is assumed to 

have a similar horsepower requirement as the boil-off, operating only during loading. 

Total natural gas consumption as fuel for liquefaction and loading was estimated to be around 

8% of the amount of gas liquefied and delivered to the U.S. 

The key activity factors affecting emissions from liquefaction facilities for 2006 and 2020 are 

summarized in Exhibit 22, by source of supply. 

Exhibit 22: Key Activity Factors for Gas Liquefaction by 

Source Country for 2006 and 2020 

T&T Nigeria Egypt Algeria

Amount LNG Delivered 

to US MMcf 389,269 57,292 119,528 17,449

Storage cap alloc to 

U.S. m3 360,826 25,011 73,490 4,348

Allocation factor 69% 10% 24% 2%

T&T Nigeria Egypt Algeria PNG Russia Australia Qatar Norway

Amount LNG Delivered 

to US MMcf gas 752,734 741,491 551,368 384,547 90,037 212,418 135,865 580,525 495,392

Storage cap alloc to 

U.S. m3 540,319 271,844 152,512 108,676 14,640 91,166 26,804 167,839 252,322

Allocation factor 82% 69% 74% 28% 4% 46% 8% 49% 84%

2020

2006

 

22 ConocoPhillips. “ConocoPhillips Optimized Cascade Process.” March. 2006. 

http://lnglicensing.conocophillips.com/lng_tech_licensing/cascade_process/index.htm 

ConocoPhillips. “Darwin LNG – Environment.” March 2006. www.darwinlng.com/Environment/Index.htm 

GE. “GE Aero Energy.” January 2008. 

www.gepower.com/prod_serv/products/aero_turbines/en/downloads/lm2500plus.pdf 

Pluto LNG. “Emissions, Discharges, and Wastes.” 

http://standupfortheburrup.de/downloads/05emissionsdischargesandwaste.pdf 
 November 10, 2008 

30

LNG Shipping 

LNG is transported in specialized cryogenic tankers that keep the LNG insulated to minimize 

boil-off during the voyage. LNG tankers can be fueled in a number of ways: boil-off fired steam 

plants, dual-fired boil-off gas and diesel, and diesel only with boil-off gas re-liquefaction. For this 

analysis, all LNG shipping was assumed to use a dual-fired engine that consumes boil-off gas 

for 80% to 90% of its fuel requirements, with the remainder supplemented by diesel. In 2006, 

the average tanker volume shipped was assumed to be 80,000 m3

. This assumed tanker size 

was estimated by dividing the volume of LNG imported into the U.S. by the number of import 

shipments reported. Newly constructed tankers were assumed to increase the average fleet 

size to 154,000 m3

 in 2020.23 

Voyage duration was estimated using a service speed of 19.5 knots to cover the approximate 

distance between the port of origin and destination terminal. LNG losses along the voyage were 

estimated assuming a 0.15% of cargo capacity per day boil-off rate for the laden voyage.24 The 

LNG tanker was assumed to keep a small heel of LNG in its tanks to maintain cryogenic 

temperatures on the unladen voyage. This heel was estimated to be 200% of the boil-off fuel 

required for the laden voyage. 

The key activity factors affecting emissions from LNG shipping are shown, by source of supply 

and destination, for 2006 in Exhibit 23, and for 2020 in Exhibit 24. 

Exhibit 23: Key Activity Factors for LNG Shipping, by 

Source Country and Delivery Point, for 2006 

Volume 

Imported 

(MMcf)

Average 

size of ship 

Distance 

between 

ports 

(m3) (miles)

Algeria 

Cove Point, MD 17,449 80,000 3,300 

Egypt 

Cove Point, MD 14,575 80,000 5,000 

Elba Island, GA 42,411 80,000 5,000 

Lake Charles, 

LA 62,542 80,000 6,500 

Nigeria 

Lake Charles, 

LA 57,292 80,000 6,100 

Trinidad & Tobago 

Cove Point, MD 84,590 80,000 2,000 

Elba Island, GA 104,356 80,000 2,000 

Everett, MA 176,097 80,000 2,000 

Gulf Gateway, 

LA 453 80,000 2,200 

Lake Charles, 

LA 23,773 80,000 2,200 

 

23 U.S. Department of Energy, Office of Fossil Energy, Liquefied Natural Gas: Understanding the Basic 

Facts, DOE/FE-0489, August 2005 

(http://www.fe.doe.gov/programs/oilgas/publications/lng/LNG_primerupd.pdf) 24http://www.shell.com/static/shipping-en/downloads/lngbrochure.pdf
 November 10, 2008 

31

Exhibit 24: Key Activity Factors for LNG Shipping, by 

Source Country and Delivery Point, for 2020 

 

Volume 

Imported 

(MMcf)

Average 

size of ship 

Distance 

between 

ports 

(m3) (miles)

Algeria 

New Gulf 361,000 154,000 4,700 

Egypt 

Cove Point, MD 147,000 154,000 5,000 

Lake Charles, 

LA 214,000 154,000 6,500 

Gulf Gateway, 

LA 137,000 154,000 6,500 

New East Coast 10,000 154,000 5,000 

Nigeria 

Cove Point, MD 147,000 154,000 5,000 

Elba Island, GA 207,000 154,000 4,500 

New Gulf 335,000 154,000 6,100 

Trinidad & Tobago 

Elba Island, GA 368,000 154,000 2,000 

Lake Charles, 

LA 361,000 150,000 2,200 

Indonesia/Papua New Guinea 

Baja California 82,000 154,000 7,000 

Russia 

Baja California 205,000 154,000 4,000 

Australia 

Baja California 123,000 154,000 7,500 

Middle East/Qatar 

Everett, MA 268,000 154,000 8,000 

Cove Point, MD 199,000 154,000 9,700 

New East Coast 48,000 154,000 9,700 

Norway 

New East Coast 79,000 154,000 4,000 

New Gulf 396,000 154,000 5,000 

LNG Storage and Regasification 

LNG delivered to the U.S. is stored as LNG at the import terminals, and is then pumped up to 

pipeline pressure and vaporized for injection into the U.S. transmission system. Storage tanks 

are equipped with boil-off gas compression, all vaporization was assumed to use submerged 

combustion vaporizers (SCV). Vaporization of LNG requires around 1.5% of the gas send-out 

as fuel for the SCV. However, it should be noted that the LNG industry is making considerable 

advancements in the area of revaporization, that, when implemented, will result in substantial 

reductions in fossil fuel consumption and GHG emissions. For example, the use of seawater 

and open rack vaporizers (ORVs) uses renewable resources and no fossil fuels, resulting in no 

CO2 (and NOx) emissions.25

 

25 http://fwc.com/publications/tech_papers/files/Lower%20Emission%20LNG%20Vap.pdf
 November 10, 2008 

32

The key activity factors affecting emissions from LNG storage and regasification are shown 

below, by receiving coast, for 2006 and 2020. 

Natural Gas Transmission 

LNG imports enter the domestic transmission system and have been assumed to travel only a 

short distance to the nearest market of sufficient size to consume the total imports to a particular 

region. Because LNG imports make up a small portion of the overall transmission system 

throughput and travel much shorter distances in the pipeline as compared to U.S. natural gas 

supplies, transmission sector emissions intensity for imported LNG is relatively small. Emissions 

were allocated to LNG imports using an estimate of emission intensity per mile that the gas 

travels. Applying this intensity factor to the distances traveled by imported LNG yielded the 

portion of total transmission emissions associated with LNG, the remainder was allocated to U.S. 

natural gas supplies. 

 

 

 West Coast Gulf Coast East Coast

 2006 2020 2006 2020 2006 2020

No. of terminals 1 2 6 3 4 

Volume imported into 

region MMcf 410,000 144,000 1,804,000 439,476 1,473,000 

Number of unloadings 120 81 521 234 431 

Storage capacity m3 303,000 425,000 1,232,000 354,233 632,850 

Gas used for 

regasification MMcf 6,080 2,136 26,751 6,516 21,542 
 November 10, 2008 

33

OVERVIEW OF SECTOR-SPECIFIC RESULTS 

Exploration and Development 

As described above, in 2006, it was estimated that over 35,000 exploratory and developmental 

wells were drilled in the United States; this number is projected to decrease to about 20,000 

wells drilled in 2020. 

For LNG, only wells drilled for the purposes of producing gas to meet the demand requirements 

of the United States are accounted for in the supply chain emissions estimates. Well drilling 

activities to meet U.S. demand were estimated to be only 144 wells in 2006 and 820 wells in 

2020. 

For either U.S. natural gas supply or for LNG, emissions from exploration and development are 

small and account for less than 1% of supply chain emissions. Overall, total emissions from 

exploration and development from U.S. supply sources were 4.4 million tonnes of CO2e in 2006, 

declining to 3.5 million tonnes of CO2e in 2020. In comparison, total emissions from exploration 

and development of the various sources of supply of LNG to serve U.S. markets were only 

100,000 tonnes of CO2e in 2006, growing to over 980,000 tonnes of CO2e by 2020. 

Emissions from exploration and development are characterized in Exhibit 25 for U.S. natural 

gas supplies in each of the AEO supply regions, for the three main sources of emissions. As 

shown, the vast majority (over 99%) of the emissions are associated with energy consumption 

during drilling operations, in most cases diesel fuel. Consequently, the regions with the highest 

drilling levels (in both 2006 and 2020) are the regions with the greatest GHG emissions. Overall, 

emissions decline between 2006 and 2020 almost directly proportional to the decline in well 

drilling assumed in the HSM. Methane emissions from natural gas venting and flaring during gas 

well completion operations increases somewhat, due to the increased number of wells targeted 

at unconventional gas, relative to conventional gas well completions, in most regions. 

Emissions from exploration and development associated with LNG supplies serving the U.S. 

market are characterized in Exhibit 26. Similar to U.S. natural gas, nearly all of the emissions 

are associated with energy consumption during drilling operations. CO2 and methane emissions 

increase significantly between 2006 and 2020, due to the increased drilling levels that must be 

pursued to supply the growing U.S. requirements for LNG. 

The total emissions associated with exploration and development for LNG is still only 6% of 

those from U.S. operations, even in 2020. 

Overall the emissions intensity for exploration and development associated U.S.-sources natural 

gas supplies was 0.50 lb CO2e/MMBtu in 2006 and 0.37 lb CO2e/MMBtu in 2020, though it can 

range considerably by AEO supply region, as shown in Exhibit 27. The emission intensity is 

greatest in the areas with the lowest productivity wells, such as the Northeast and Mid-continent. 

For exploration and production associated with LNG, the overall emissions intensity was 0.37 lb 

CO2e/MMBtu in 2006 and 0.60 lb CO2e/MMBtu in 2020. The emissions intensity by supply 

region in 2020 for LNG is shown in Exhibit 28. 
 November 10, 2008 

34

Exhibit 25: Comparison of GHG Emissions for Exploration and Development for U.S. Natural Gas 

for 2006 and 2020 

(Not Accounting for Natural Gas Star Program Reductions) 

Emission Sources 

CO2 Emissions 

(Mg) 

CH4 Emissions 

(Mg) 

 2006 2020 2006 2020

Northeast Region 

Drilling and Well Completion 

Completion Venting and Flaring 914 2,217 22,903 22,738 

Well Drilling Venting 30 31 757 319 

Well Drilling Combustion 975,671 410,829 

 

Midcontinent Region 

Drilling and Well Completion 

Completion Venting and Flaring 254 466 9,925 16,060 

Well Drilling Venting 8 7 328 225 

Well Drilling Combustion 633,930 435,085 

 

Rocky Mountain Region 

Drilling and Well Completion 

Completion Venting and Flaring 2,014 3,043 9,706 16,393 

Well Drilling Venting 67 43 321 230 

Well Drilling Combustion 349,199 250,148 

 

Southwest Region 

Drilling and Well Completion 

Completion Venting and Flaring 620 907 4,729 6,800 

Well Drilling Venting 20 13 156 95 

Well Drilling Combustion 405,545 247,331 

 

West Cost Region 

Drilling and Well Completion 

Completion Venting and Flaring 1 3 224 841 

Well Drilling Venting 0 0 7 12 

Well Drilling Combustion 12,891 20,504 

 

Gulf Coast Region 

Drilling and Well Completion 

Completion Venting and Flaring 618 923 8,739 12,784 

Well Drilling Venting 20 13 289 179 

Well Drilling Combustion 841,181 521,964 

 

 3,222,983 1,893,527 58,084 76,676 
 November 10, 2008 

35

Exhibit 26: Comparison of GHG Emissions for Exploration and Development for LNG Supplies 

Serving U.S. Markets for 2006 and 2020 

(Not Accounting for Natural Gas Star Program Reductions) 

 

CO2 Emissions 

 (Mg)#

CH4 Emissions 

 (Mg) 

Region/Emission Source 2006 2020 2006 2020

Trinidad & Tobago 

Completion Venting and Flaring 379.99 899.32 3,659.30 8,660.48 

Well Drilling Venting 0.40 0.74 3.83 7.09 

Well Drilling Combustion 10,964.62 20,311.51 

Nigeria 

Completion Venting and Flaring 0.00 185.66 0.00 6,870.13 

Well Drilling Venting 0.03 0.36 1.15 13.42 

Well Drilling Combustion 3,415.21 39,904.03 

Egypt 

Completion Venting and Flaring 0.00 2,893.33 0.00 11,160.52 

Well Drilling Venting 0.58 2.47 2.25 9.53 

Well Drilling Combustion 7,360.68 31,141.32 

Algeria 

Completion Venting and Flaring 0.00 183.80 0.00 1,411.39 

Well Drilling Venting 0.02 0.35 0.18 2.71 

Well Drilling Combustion 808.87 12,402.61 

Indonesia/Papua New Guinea 

Completion Venting and Flaring 0.00 0.00 

Well Drilling Venting 0.11 0.88 

Well Drilling Combustion 3,208.50 

Russia 

Completion Venting and Flaring 305.55 2,346.30 

Well Drilling Venting 0.21 1.63 

Well Drilling Combustion 7,448.30 

Australia 

Completion Venting and Flaring 129.27 992.67 

Well Drilling Venting 0.09 0.69 

Well Drilling Combustion 2,836.08 

Middle East/Qatar 

Completion Venting and Flaring 411.32 3,158.49 

Well Drilling Venting 0.25 1.95 

Well Drilling Combustion 5,941.67 

Norway 

Completion Venting and Flaring 705.11 5,414.55 

Well Drilling Venting 0.49 3.75 

Well Drilling Combustion 11,458.93 

TOTAL EMISSIONS 22,930.40 140,371.39 3,666.70 40,056.17 

 # Mg = megagram = 1,000 kg = 1 metric tonne
 November 10, 2008 

36

Exhibit 27: Exploration and Development 

Emissions Intensity by AEO Supply Region for 2006 and 2020 

Exploration and Development

Total Emissions (1,000 lbs CO2e) 2006 2020

Northeast 3,248,396 1,978,082 

Midcontinent 1,872,804 1,714,173 

Rocky Mountain 1,238,637 1,327,865 

Southwest 1,121,637 866,509 

West Coast 39,150 84,703 

Gulf Coast 2,273,791 1,752,944 

Offshore n.e. n.e. 

Natural Gas Supply (Quads) 

Northeast Region 0.86 1.12 

Midcontinent Region 2.30 3.24 

Rocky Mountain Region 4.34 3.74 

Southwest Region 1.84 3.40 

West Cost Region (inc AK) 0.71 2.34 

Gulf Coast Region 9.22 9.10 

Offshore n.e. n.e. 

 

Emissions Intensity (lb. CO2e/MMBtu) 

Northeast Region 3.79 1.77 

Midcontinent Region 0.81 0.53 

Rocky Mountain Region 0.29 0.36 

Southwest Region 0.61 0.25 

West Cost Region 0.05 0.04 

Gulf Coast Region 0.25 0.19 

Offshore n.e. n.e. 
 November 10, 2008 

37

Exhibit 28: Exploration and Development 

Emissions Intensity for LNG, by Source Country, for 2006 and 2020 

Total Emissions (1000 lbs CO2e) Exploration and Development

2006 2020

Trinidad & Tobago 194,600 448,039 

Nigeria 7,582 407,065 

Egypt 16,332 592,170 

Algeria 1,791 93,216 

Indonesia/Papua N. Guinea 7,114 

Russia 125,795 

Australia 52,526 

Qatar 160,323 

Norway 277,665

 

Natural Gas Supply (Quads) 2006 2020

Trinidad & Tobago 0.44 0.84 

Nigeria 0.07 0.82 

Egypt 0.14 0.61 

Algeria 0.02 0.43 

Indonesia/Papua N. Guinea 0.10 

Russia 0.24 

Australia 0.15 

Qatar 0.64 

Norway 0.55

 

Emissions Intensity (lb. CO2e/MMBtu) 

2006 2020

Trinidad & Tobago 0.44 0.53 

Nigeria 0.11 0.49 

Egypt 0.12 0.97 

Algeria 0.09 0.22 

Indonesia/Papua N. Guinea 0.07 

Russia 0.54 

Australia 0.35 

Qatar 0.25 

Norway 0.51 
 November 10, 2008 

38

Natural Gas Production 

U.S. natural gas is produced through a mix of associated, non-associated, and unconventional 

wells. Proportionally, on a per-unit-of-production basis, emissions are much higher for U.S. gas 

production than for that associated with gas production serving LNG exports. This is because 

the average production rate from individual wells in the U.S. is only around 30 million cubic feet 

per year, whereas wells from countries exporting LNG can have natural gas production rates of 

nearly 20 million cubic feet per well per day. The larger number of wells needed to produce the 

same amount of gas in the U.S. requires more equipment, and consequently, results in more 

fugitive and vented emissions. 

Overall, total emissions from natural gas production from U.S. supply sources were 116 million 

tonnes of CO2e in 2006, decreasing to 105 million tonnes of CO2e in 2020. In comparison, total 

emissions from natural gas production from the various sources of supply of LNG to serve U.S. 

markets were only about 420,000 tonnes of CO2e in 2006, growing to over 3.4 million tonnes of 

CO2e by 2020. 

In 2006, GHG emissions intensity from U.S. production was 13.10 lb CO2e/MMBtu as compared 

to 1.57 lb CO2e/MMBtu for countries exporting LNG. In 2020, GHG emissions intensity from U.S. 

production decreases to 11.19 lb CO2e/MMBtu, while increasing to 2.08 lb CO2e/MMBtu for 

countries exporting LNG to the U.S. However, the emissions and emissions intensity can range 

considerably by supply region. Total U.S. emissions by AEO supply region are shown in Exhibit 

29 for 2006, and Exhibit 30 for 2020, not accounting for emissions reductions attributable to the 

Natural Gas Star Program. Overall emission intensity is shown by AEO supply region for U.S. 

gas supply sources for both 2006 and 2020 in Exhibit 31 and for the source countries for LNG 

(for both 2006 and 2020) in Exhibit 32, this time adjusting to take into account for emissions 

reductions attributable to the Natural Gas Star Program. 

The uniquely high emissions level and emissions intensity for Qatar is the result of the very high 

condensate production associated with natural gas production in this country. The model used 

for this analysis assumed condensate was stored in tanks without vapor recovery or other 

emissions controls. While this was assumed in all countries and regions of the U.S., the 

implications of this for Qatar, given its high ratio of condensate to gas, was most pronounced. 

Given this high level of condensate production, vapor recovery or other emissions controls 

would most likely be implemented in this case, resulting in emission rates of approximately onefifth of that assumed in this analysis. 

Moreover, it is important to note that the emissions intensity of U.S. offshore production, again 

given the much higher productivity per well characteristic of offshore production, is much less 

intensive that onshore production, and in fact approaches the intensity of the sources of supply 

for LNG. 
 November 10, 2008 

39

Exhibit 29: Emissions from Production Operations by AEO Supply Region – 2006 

(Not Accounting for Natural Gas Star Program Reductions) 

Emission Sources 

CO2

Emissions 

 (Mg) 

CH4

Emissions 

 (Mg) 

N2O 

Emissions 

 (Mg) 

 

Northeast Region 1,572,247 847,450 36 

Midcontinent Region 1,544,828 1,062,868 34 

Rocky Mountain Region 7,021,187 1,252,766 125 

Southwest Region 5,164,753 574,899 119 

West Cost Region 632,403 87,640 16 

Gulf Coast Region 11,032,555 806,692 229 

Onshore 

Purchased Electricity 16,317,494 135 

Offshore 3,035,939 227,774 

46,321,406 4,860,224 559 

 

Exhibit 30: Emissions from Production Operations by AEO Supply Region – 2020 

(Not Accounting for Natural Gas Star Program Reductions)

Emission Sources

CO2

Emissions 

 (Mg) 

CH4

Emissions 

 (Mg) 

N2O 

Emissions 

 (Mg) 

 

Northeast Region 2,215,590 1,044,129 50 

Midcontinent Region 2,036,861 1,783,394 45 

Rocky Mountain Region 6,792,467 2,218,582 115 

Southwest Region 6,488,166 879,461 152 

West Cost Region 747,939 312,823 19 

Gulf Coast Region 12,545,320 1,274,922 266 

Onshore 

Purchased Electricity 15,934,637 132 

Offshore 2,955,576 213,424 

 49,716,556 7,726,868 648 
 November 10, 2008 

40

Exhibit 31: Natural Gas Production 

Emissions Intensity by AEO Supply Region for 2006 and 2020 

(Including Natural Gas Star Program Reductions)

Total Emissions (1,000 lbs CO2e) 

2006 2020

Northeast 35,101,370 25,163,970 

Midcontinent 42,919,609 38,406,488 

Rocky Mountain 63,999,846 58,893,138 

Southwest 34,403,659 33,295,210 

West Coast 4,845,579 7,761,123 

Gulf Coast 74,170,117 68,102,362 

 

Natural Gas Supply (Quads) 

2006 2020

Northeast 0.86 1.12 

Midcontinent 2.30 3.24 

Rocky Mountain 4.34 3.74 

Southwest 1.84 3.40 

West Coast 0.71 2.34 

Gulf Coast 9.22 9.10 

Offshore 

 

Emissions Intensity (lb. CO2e/MMBtu) 

2006 2020

Northeast 40.97 22.50 

Midcontinent 18.64 11.87 

Rocky Mountain 14.75 15.75 

Southwest 18.69 9.79 

West Coast 6.78 3.31 

Gulf Coast 8.04 7.49 
 November 10, 2008 

41

Exhibit 32: Natural Gas Production 

Emissions Intensity for LNG, by Source Country, for 2006 and 2020 

(Including Natural Gas Star Program Reductions)

Total Emissions (1,000 lbs CO2e) 

2006 2020

Trinidad & Tobago 486,289 718,473 

Nigeria 135,420 1,073,276 

Egypt 258,246 740,925 

Algeria 46,419 603,453 

Indonesia/Papua N. Guinea 96,375 

Russia 178,016 

Australia 110,817 

Qatar 3,546,024 

Norway 476,898 

 

Natural Gas Supply (Quads) 

2006 2020

Trinidad & Tobago 0.44 0.84 

Nigeria 0.07 0.82 

Egypt 0.14 0.61 

Algeria 0.02 0.43 

Indonesia/Papua N. Guinea 0.10 

Russia 0.24 

Australia 0.15 

Qatar 0.64 

Norway 0.55

 

Emissions Intensity (lb. CO2e/MMBtu) 

2006 2020

Trinidad & Tobago 1.10 0.86 

Nigeria 1.99 1.30 

Egypt 1.83 1.21 

Algeria 2.28 1.41 

Indonesia/Papua N. Guinea 0.97 

Russia 0.76 

Australia 0.74 

Qatar 5.52 

Norway 0.87 
 November 10, 2008 

42

Natural Gas Processing 

Overall, total emissions from natural gas processing from U.S. supply sources were 59 million 

tonnes of CO2e in 2006, increasing to 64 million tonnes of CO2e in 2020. In comparison, total 

emissions from natural gas processing associated with the sources of supply for LNG to serve 

U.S. markets were only 1.7 million tonnes of CO2e in 2006, growing to over 13 million tonnes of 

CO2e by 2020. 

Emissions intensity from gas processing was 6.64 lb CO2e /MMBtu for U.S. natural gas supply 

and 6.46 lb CO2e /MMBtu for imported LNG in 2006. Gas processing emissions intensity is 

projected to increase slightly to 6.80 lb CO2e /MMBtu for U.S. natural gas supply, while 

increasing to 8.14 lb CO2e/MMBtu for imported LNG in 2020. 

The decrease in emissions intensity for U.S.-sourced supplies is due primarily to slight changes 

in the relative mix of regional production, the changing sources of that production (conventional 

vs. unconventional sources of natural gas) and the CO2 content of production from those 

sources. For LNG, the increase in emissions intensity for gas processing is due to the need to 

bring on new sources of gas to serve U.S. LNG markets that tend to have a lower quality and 

higher CO2 content. Only a relatively small portion of the CO2 produced from planned projects 

is currently planned to be sequestered. If more of the CO2 produced from these LNG operations 

is sequestered, beyond that currently planned, then the emissions intensity associated with 

these sources would decline proportionally. 

For U.S. supplies, natural gas processing facilities were grouped into the NEMS supply region. 

Detailed emissions from these regions are shown in Exhibit 33 for 2006 and Exhibit 34 for 2020. 

A few items are important to note in understanding these results. First, West Coast emissions 

are dominated by Alaska operations. Virtually all of the associated gas produced on the North 

Slope is processed, the gas liquids blended into the crude stream to the Alaska pipeline, and 

what methane is not consumed as fuel for electricity generation, heating, engines and 

processing is re-injected into the oil reservoirs. With regard to the CO2 emissions intensity in the 

Rocky Mountain region, the ICF gas processing model includes consideration of some CO2

capture and injection for EOR operations in the Rockies, which reduced the CO2 that would 

otherwise be emitted to the atmosphere. Emissions from Gulf Coast processing facilities also 

consider gas produced from offshore facilities in the Gulf of Mexico that is brought on shore to 

be processed. 

Based on that, given the assumed throughput for gas processing in each of the NEMS supply 

regions contributing to U.S. supplies, the relative emissions intensity for the various regions, and 

the basis for that emissions intensity, is summarized in Exhibit 35 for 2006 and Exhibit 36 for 

2020. 

Emissions from gas processing for supplies destined to serve U.S. LNG requirements were 

disaggregated by country of origin. These are shown in Exhibit 37 for 2006 and Exhibit 38 for 

2020. Based on that, given the assumed contribution for each of the countries providing LNG to 

U.S. markets, the relative emissions intensity for the various LNG source countries, and the 

basis for that emissions intensity, is summarized in Exhibit 39 for 2006 and Exhibit 40 for 2020. 

As discussed above, a number of large LNG projects overseas plan to permanently sequester 

the CO2 separated in nearby geologic formations. Such plants include Gorgon (Australia),

Tangguh (Papua/New Guinea), Snohvit (Norway) and possibly others. Specifically, proposed 

sequestration rates planned for Gorgon, Snohvit, and Tangguh (assuming a comparable rate) 

are sufficient to sequester all of the vented CO2 emissions from their respective source 

countries that are allocated to U.S. markets, amounting to over 900,000 tonnes per year, as 

shown in the table below. 
 November 10, 2008 

43

Proposed Injection Rate for 

CO2 Sequestration 

Vented CO2

emissions 

allocated to U.S. 

market 

( tonnes/yr) (Mg/year) (Mg/year)

Gorgon (Australia) 1,000,000 1,000,000 365,514 

Tangguh (Papua New Guinea) 1,000,000 1,000,000 42,724 

Snohvit (Norway) 700,000 700,000 495,517

 903,755 

This could result in a reduction in the CO2 emissions associated with gas processing for LNG 

exports, corresponding to a reduction in emissions intensity for LNG serving U.S. markets. 

These reductions are incorporated into the emissions estimates shown in Exhibit 38. If more of 

the CO2 otherwise vented from processing gas serving LNG exports is sequestered, this impact 

could be greater. (The same also applies to the CO2 otherwise vented as part of gas processing 

of U.S.-sourced natural gas.) 
 November 10, 2008 

44

Exhibit 33: Emissions from Natural Gas Processing of U.S. Supplies, by Region for 2006 

(Not Accounting for Natural Gas Star Program Reductions) 

CO2 Emission Sources

Normal Fugitives Northeast Midcontinent Rocky Mountain Southwest West Coast Gulf Coast

Plants - Before CO2 removal 155 289 351 320 109 519

Plants - After CO2 removal 37 69 84 77 26 125

Recip. Comp. - Before CO2 removal 1,138 2,087 2,588 2,057 3,861 6,598

Recip. Comp. After CO2 removal 274 502 623 495 929 1,587

Cent. Comp. - Before CO2 removal 333 662 786 660 1,402 2,328

Cent. Comp. - After CO2 removal 80 159 189 159 337 560

Vented

AGR Vents 398,010 1,101,323 267,617 1,743,951 332,512 3,399,169

Kimray Pumps 14 56 52 67 9 132

Dehydrator Vents 162 320 294 373 57 825

Pneumatic Devices 17 33 39 36 12 58

Combusted 238,327 2,901,053 4,139,745 4,105,403 2,865,187 7,749,253

Routine Maintenance

Blowdowns/Venting 386 718 872 795 270 1,289

Indirect Electricity Emissions 1,637,251 3,232,273 2,178,476 4,048,208 285,726 5,933,601

Methane Emission Sources

Normal Fugitives Northeast Midcontinent Rocky Mountain Southwest West Coast Gulf Coast

Plants 2,779 5,169 6,280 5,725 1,945 9,282

Reciprocating Compressors 20,366 37,354 46,324 36,812 69,097 118,097

Centrifugal Compressors 5,965 11,842 14,062 11,816 25,086 41,669

Vented

AGR Vents 941 1,625 2,609 2,694 812 3,592

Kimray Pumps 145 567 523 676 95 1,333

Dehydrator Vents 1,644 3,243 2,973 3,783 582 8,357

Pneumatic Devices 159 295 358 327 111 530

Combusted 1,441 17,537 25,025 24,817 17,320 46,844

Routine Maintenance

Blowdowns/Venting 3,910 7,272 8,836 8,054 2,737 13,059

Indirect Electricity Emissions 14 27 18 34 2 49

N2O Emission Sources

Northeast Midcontinent Rocky Mountain Southwest West Coast Gulf Coast

Combusted 6 75 107 106 74 200

CO2 Emissions (Mg)

CH4 Emissions (Mg)

N2O Emissions (Mg)
 November 10, 2008 

45

Exhibit 34: Emissions from Natural Gas Processing of U.S. Supplies, by Region for 2020 

(Not Accounting for Natural Gas Star Program Reductions) 

CO2 Emission Sources

Normal Fugitives Northeast Midcontinent Rocky Mountain Southwest West Coast Gulf Coast

Plants - Before CO2 removal 181 338 410 374 127 606

Plants - After CO2 removal 46 86 105 95 32 155

Recip. Comp. - Before CO2 removal 1,224 2,261 2,794 2,234 4,273 7,267

Recip. Comp. After CO2 removal 312 576 712 570 1,089 1,853

Cent. Comp. - Before CO2 removal 363 733 858 727 1,526 2,545

Cent. Comp. - After CO2 removal 92 187 219 185 389 649

Vented

AGR Vents 270,228 797,059 739,201 2,291,963 304,342 5,274,304

Kimray Pumps 17 56 57 70 11 150

Dehydrator Vents 188 347 309 397 51 964

Pneumatic Devices 20 38 46 42 15 68

Combusted 276,371 3,364,149 4,800,573 4,760,750 3,322,557 8,986,269

Routine Maintenance

Blowdowns/Venting 451 839 1,019 929 316 1,507

Indirect Electricity Emissions 2,028,167 4,004,022 2,699,069 5,014,772 353,947 7,336,273

Methane Emission Sources

Normal Fugitives Northeast Midcontinent Rocky Mountain Southwest West Coast Gulf Coast

Plants 3,442 6,403 7,780 7,091 2,410 11,498

Reciprocating Compressors 23,210 42,888 53,004 42,386 81,059 137,857

Centrifugal Compressors 6,882 13,914 16,273 13,785 28,943 48,269

Vented

AGR Vents 1,155 2,266 3,122 3,207 1,026 4,405

Kimray Pumps 180 597 613 755 117 1,615

Dehydrator Vents 2,014 3,727 3,317 4,258 550 10,353

Pneumatic Devices 197 365 444 405 138 656

Combusted 1,671 20,336 29,019 28,779 20,085 54,322

Routine Maintenance

Blowdowns/Venting 4,843 9,009 10,946 9,977 3,390 16,177

Indirect Electricity Emissions 17 33 22 42 3 61

N2O Emission Sources

Northeast Midcontinent Rocky Mountain Southwest West Coast Gulf Coast

Combusted 7 87 124 123 86 232

CH4 Emissions (Mg)

N2O Emissions (Mg)

CO2 Emissions (Mg)

 
 November 10, 2008 

46

Exhibit 35: Emissions Intensity for U.S. Natural Gas Processing by NEMS Supply Region, for 2006 

Northeast Midcontinent Rocky Mountain Southwest West Coast Gulf Coast

Fugitives (w/o Gas Star Reductions)

CO2 400,608 1,106,217 273,495 1,748,989 339,524 3,413,190

CH4 35,907 67,367 81,966 69,887 100,466 195,918

Combustion

CO2 1,875,578 6,133,326 6,318,221 8,153,611 3,150,913 13,682,854

CH4 1,454 17,564 25,043 24,851 17,322 46,893

N20 6 75 107 106 74 200

CO2e Total 2,864,749 8,614,196 8,530,139 11,373,593 5,567,082 20,966,813

Fugitives (w/ Gas Star) 956,720 2,088,767 1,652,820 2,665,193 2,029,420 6,237,051

Combustion 1,908,029 6,525,429 6,877,319 8,708,400 3,537,661 14,729,762

Fugitives 33% 24% 19% 23% 36% 30%

Combustion 67% 76% 81% 77% 64% 70%

Total Emissions (lb CO2e) 6,315,585,311 18,990,732,696 18,805,420,175 25,074,057,747 12,273,107,463 46,223,132,659

Gas Throughput (MMBtu) 928,336,255 1,883,124,425 2,204,933,829 1,845,224,833 3,758,691,160 6,304,954,721

Emissions Intensity (lb 

CO2e/MMBtu) 6.80 10.08 8.53 13.59 3.27 7.33

(All emissions in Mg unless otherwise indicated)
 November 10, 2008 

47

Exhibit 36: Emissions Intensity for U.S. Natural Gas Processing by NEMS Supply Region, for 2020 

(Mg) 

Northeast Midcontinent Rocky Mountain Southwest West Coast Gulf Coast

Fugitives (w/o Gas Star Reductions)

CO2 273,122 802,520 745,730 2,297,586 312,171 5,290,067

CH4 41,922 79,169 95,499 81,864 117,634 230,830

Combustion

CO2 2,304,538 7,368,171 7,499,643 9,775,522 3,676,504 16,322,542

CH4 1,687 20,369 29,042 28,820 20,088 54,383

N20 7 87 124 123 86 232

CO2e Total 2,820,068 8,844,148 9,287,808 12,083,006 5,277,736 21,736,467

Fugitives (w/ Gas Star) 477,876 1,021,239 1,139,788 1,664,078 1,152,743 4,199,819

Combustion 2,342,192 7,822,910 8,148,020 10,418,928 4,124,993 17,536,648

Fugitives 17% 12% 12% 14% 22% 19%

Combustion 83% 88% 88% 86% 78% 81%

Total Emissions (lb CO2e) 6,217,080,708 19,497,681,592 20,475,768,160 26,638,019,693 11,635,220,494 47,919,900,011

Gas Throughput (MMBtu) 1,149,989,003 2,332,745,670 2,731,391,391 2,285,797,041 4,656,129,150 7,810,347,330

Emissions Intensity (lb 

CO2e/MMBtu) 5.41 8.36 7.50 11.65 2.50 6.14

(All emissions in Mg unless otherwise indicated)
 November 10, 2008 

48

Exhibit 37: Emissions from Natural Gas Processing for U.S. LNG Markets, by Country of Origin, 

2006 

(Not Accounting for Natural Gas Star Program Reductions) 

Carbon Dioxide Emission Sources

Normal Fugitives Algeria Egypt Nigeria Trinidad

Plants - Before CO2 removal 1.95 1.95 1.75 0.78

Plants - After CO2 removal 0.75 0.75 0.75 0.75

Reciprocating Compressors - Before CO2 removal 12.22 85.04 36.93 106.22

Reciprocating Compressors - After CO2 removal 4.69 32.60 15.73 101.81

Centrifugal Compressors - Before CO2 removal 4.66 32.43 14.08 40.50

Centrifugal Compressors - After CO2 removal 1.79 12.43 6.00 38.82

Vented

AGR Vents 10,082.40 70,324.56 27,061.91 176,273.25

Kimray Pumps 0.00 0.00 0.00 0.00

Dehydrator Vents 5.63 39.30 17.01 49.26

Pneumatic Devices 0.22 0.22 0.20 0.09

Combusted 26,038.65 175,045.01 87,989.26 523,932.63

Routine Maintenance

Blowdowns/Venting 4.84 4.84 4.36 1.94

Indirect Electricity Emissions 2,427.55 62,257.15 3,885.66 128,460.54

Methane Emission Sources

Normal Fugitives Algeria Egypt Nigeria Trinidad

Plants 55.58 55.58 55.58 55.58

Reciprocating Compressors 348.71 2,425.91 1,170.55 7,575.24

Centrifugal Compressors 132.97 925.01 446.34 2,888.47

Vented

AGR Vents 42.76 42.76 42.76 42.76

Kimray Pumps 0.00 0.00 0.00 0.00

Dehydrator Vents 90.97 634.55 305.23 1,988.17

Pneumatic Devices 3.17 3.17 3.17 3.17

Combusted 157.40 1,058.15 531.89 3,167.17

Routine Maintenance

Blowdowns/Venting 78.20 78.20 78.20 78.20

Indirect Electricity Emissions 0.02 0.52 0.03 1.07

Nitrous Oxide Emission Sources

Algeria Egypt Nigeria Trinidad

Combusted 0.67 4.53 2.28 12.79

CO2 Emissions (Mg)

CH4 Emissions (Mg)

N2O Emissions (Mg)
 

49

Exhibit 38: Emissions from Natural Gas Processing for U.S. LNG Markets, by Country of Origin, 2

(Not Accounting for Natural Gas Star Program Reductions) 

Carbon Dioxide Emission Sources

Normal Fugitives Algeria Egypt Nigeria Trinidad

Indonesia/ 

Papua New 

Guinea Russia Australia

Plants - Before CO2 removal 4.83 9.65 8.69 3.86 6.03 0.36 Plants - After CO2 removal 1.85 3.70 3.70 3.70 0.93 0.93 

Reciprocating Compressors - Before CO2 removal 247.00 353.22 427.32 193.54 142.38 20.60 3Reciprocating Compressors - After CO2 removal 94.70 135.43 182.04 185.51 21.84 52.65 

Centrifugal Compressors - Before CO2 removal 91.69 131.12 158.63 71.85 53.00 7.67 1

Centrifugal Compressors - After CO2 removal 35.16 50.27 67.58 68.87 8.13 19.60 

VentedAGR Vents 211,276.45 301,245.68 324,769.11 331,016.58 196,750.75 35,732.86 445,0

Kimray Pumps 0.00 0.00 0.00 0.00 0.00 0.00 

Dehydrator Vents 118.07 168.35 204.18 92.49 68.72 9.98 1Pneumatic Devices 0.54 1.07 0.97 0.43 0.67 0.04 

Combusted 597,147.06 895,205.44 1,155,125.18 1,173,626.82 120,696.73 274,593.92 181,7

Routine MaintenanceBlowdowns/Venting 12.00 24.00 21.60 9.60 15.00 0.90 Indirect Electricity Emissions 318,204.93 159,097.07 159,101.73 159,102.08 77,115.14 317,273.05 317,2

CO2 Emissions Sequestered 0 0 00 42,724 0 36

Methane Emission Sources

Normal Fugitives Algeria Egypt Nigeria Trinidad

Indonesia/ 

Papua New 

Guinea Russia Australia

Plants 137.70 275.39 275.39 275.39 68.85 68.85 

Reciprocating Compressors 7,046.23 10,076.31 13,544.54 13,802.49 1,624.70 3,916.97 2,4

Centrifugal Compressors 2,615.71 3,740.54 5,028.03 5,123.78 604.78 1,458.06 9

VentedAGR Vents 85.53 171.05 171.05 171.05 42.76 42.76 

Kimray Pumps 0.00 0.00 0.00 0.00 0.00 0.00 Dehydrator Vents 1,906.38 2,718.18 3,663.05 3,733.51 443.83 1,074.74 6

Pneumatic Devices 7.86 15.72 15.72 15.72 3.93 3.93 

Combusted 3,609.75 5,411.51 6,982.72 7,094.57 729.61 1,659.92 1,0

Routine MaintenanceBlowdowns/Venting 193.73 387.46 387.46 387.46 96.87 96.87 Indirect Electricity Emissions 2.64 5.28 5.28 5.28 0.64 2.63 

Nitrous Oxide Emission Sources

Algeria Egypt Nigeria Trinidad

Indonesia/ 

Papua New 

Guinea Russia Australia

Combusted 15.45 23.16 29.88 30.36 3.12 7.10 

CO2 Emissions (Mg)

CH4 Emissions (Mg)

N2O Emissions (Mg)
 

 November 10, 2008 50

Exhibit 39: Emissions Intensity for U.S. Natural Gas Processing by LNG Source Country, for 2006 

Algeria Egypt Nigeria Trinidad

Fugitives (w/o Gas Star Reductions)

CO2 10,119 70,534 27,159 176,613

CH4 752 4,165 2,102 12,632

Combustion

CO2 28,466 237,302 91,875 652,393

CH4 157 1,059 532 3,168

N20 1 5 2 13

CO2e Total 53,457 391,855 162,826 1,089,018

Fugitives (w/ Gas Star) 21,476 130,917 59,075 366,127

Combustion 31,981 260,938 103,751 722,891

Fugitives 40% 33% 36% 34%

Combustion 60% 67% 64% 66%

Total Emissions (lb CO2e) 117,849,452 863,876,802 358,963,377 2,400,832,780

Gas Throughput (MMBtu) 20,151,268 140,371,186 67,565,841 439,705,984

Emissions Intensity (lb 

CO2e/MMBtu) 5.85 6.15 5.31 5.46

(All emissions in Mg unless otherwise indicated)
 

51

Exhibit 40: Emissions Intensity for U.S. Natural Gas Processing by LNG Source Country, for 20

Algeria Egypt Nigeria Trinidad

Indonesia/ 

Papua New 

Guinea Russia Australia

Fugitives (w/o Gas Star Reductions)

CO2 211,882 302,123 325,844 331,646 154,343 35,846 80,122 

CH4 11,993 17,385 23,085 23,509 2,886 6,662 4,243 

Combustion

CO2 915,352 1,054,303 1,314,227 1,332,729 197,812 591,867 498,989 

CH4 3,612 5,417 6,988 7,100 730 1,663 1,101 

N20 15 23 30 30 3 7 5 

CO2e Total 1,188,121 1,451,646 1,806,073 1,833,166 303,163 701,794 593,678 Fugitives (w/ Gas Star) 192,120 276,412 335,834 341,928 89,048 72,811 70,107 

Combustion 996,001 1,175,234 1,470,239 1,491,238 214,115 628,983 523,571 

Fugitives 16% 19% 19% 19% 29% 10% 12% 

Combustion 84% 81% 81% 81% 71% 90% 88% 

Total Emissions (lb CO2e) 2,619,314,662 3,200,277,674 3,981,641,944 4,041,371,288 668,348,974 1,547,164,766 1,308,814,425 3

Gas Throughput (MMBtu) 425,105,967 607,417,311 817,387,875 833,114,413 98,967,636 233,667,768 149,463,092 Emissions Intensity (lb CO2e/MMBtu) 6.16 5.27 4.87 4.85 6.75 6.62 8.76 

(All emissions in Mg unless otherwise indicated)
 November 10, 2008 

52

Natural Gas Liquefaction and Loading 

Total GHG emissions from the natural gas liquefaction and loading was slightly over 2.5 million 

tonnes CO2e in 2006, but is forecast to grow to almost 17.5 million tonnes in 2020 due to the 

increased requirements for LNG in the U.S. In this analysis, these emissions are exclusively 

due to fuel consumption. Total natural gas consumption as fuel for liquefaction and loading was 

estimated to be around 8% of the amount of gas liquefied and delivered to the U.S. Overall, this 

represents an emissions intensity of 9.52 lb CO2e/MMBtu for imported LNG in 2006 and 10.60 

lb CO2e /MMBtu in 2020. Emissions for both 2006 and 2020 are summarized by country of 

origin in Exhibit 41. 

Exhibit 41: Natural Gas Liquefaction 

Emissions Intensity for LNG, by Source Country, for 2006 and 2020 

Fuel 

Consumed for 

Refrigeration 

(MMcf/yr)

Fuel 

Consumed for 

Electricity 

Generation 

(MMcf/yr)

Fuel 

Consumed for 

Boil-off Gas 

Compressor 

(MMcf/yr)

CO2 

Emissions 

(tonnes)

CH4 

Emissions 

(tonnes)

N2O 

Emissions 

(tonnes)

CO2e 

Emissions 

(tonnes)

Natural Gas 

Delivered to 

US (BBtu)

Emissions 

Intensity (lb 

CO2e/MMBtu)

LNG Country of Origin

Algeria 1,393 53 2 76,180 16 2 78,747 19,722 8.80

Egypt 9,713 65 31 529,821 25 27 533,674 137,559 10.45

Nigeria 4,672 58 10 254,611 26 6 257,890 66,168 11.09

Trinidad & Tobago 30,595 94 178 1,671,434 42 55 1,679,390 431,002 3.64

2006

Fuel 

Consumed for 

Refrigeration 

(MMcf/yr)

Fuel 

Consumed 

for 

Electricity 

Generation 

(MMcf/yr)

Fuel 

Consumed 

for Boil-off 

Gas 

Compressor 

(MMcf/yr)

CO2 Emissions 

(tonnes)

CH4 

Emissions 

(tonnes)

N2O 

Emissions 

(tonnes)

CO2e Emissions 

(tonnes)

Natural Gas 

Delivered to 

US (BBtu)

Emissions 

Intensity (lb 

CO2e/MMBtu)

LNG Country of Origin

Algeria 30,869 415 48 1,688,671 124 43 1,704,692 413,270 9.09

Egypt 44,716 469 70 2,439,109 179 63 2,462,250 589,255 9.21

Nigeria 59,833 531 133 3,260,591 240 84 3,291,525 794,085 9.14

Trinidad & Tobago 58,851 537 266 3,215,119 236 82 3,245,621 809,361 8.84

Indonesia/PNG 7,370 319 6 414,735 30 11 418,670 96,194 9.60

Russia 16,983 361 38 936,831 69 24 945,719 227,505 9.16

Australia 11,166 335 11 620,438 46 16 626,325 145,262 9.51

Middle East/Qatar 46,997 476 78 2,562,827 188 66 2,587,141 610,414 9.34

Norway 39,324 454 115 2,150,102 158 55 2,170,501 529,749 9.03

2020

LNG Shipping 

Overall, total GHG emissions from the LNG shipping was slightly over 1.6 million tonnes CO2e 

in 2006, but is forecast to grow to over 9.2 million tonnes in 2020 due to the increased 

requirements for LNG in the U.S, and the longer distances LNG supplies serving this increased 

demand will need to travel.

Emissions intensity for LNG shipping was estimated as 6.07 lb CO2e/MMBtu in 2006 and 5.59 lb 

CO2e/MMBtu in 2020 as efficiencies improve, primarily by the use of much larger tankers, 

reducing the number of trips required to serve the same amount of LNG demand. 

Total emissions from LNG shipping by country of origin are summarized in Exhibit 42 for 2006, 

and in Exhibit 43 for 2020. 
 November 10, 2008 

53

Exhibit 42: Emissions from LNG Shipping in 2006 

Origin Destination Trip 

Duration

One-way Boiloff (m3

 LNG)

LNG heel left 

(m3 LNG)

Amount 

Unloaded (m3 

LNG)

Total Volume 

Delivered (MMcf 

gas)

# of Trips Emissions 

(tonnes CO2)

Country 

Specific 

Emissions 

Intensity (lbs 

CO2e/MMBtu)

Algeria Cove Point, MD 147 hr 735 1,471 77,794 17,449 10 52,178 6.30

Egypt Cove Point, MD 223 hr 1,114 2,228 76,658 14,575 8 63,246

Egypt Elba Island, GA 223 hr 1,114 2,228 76,658 42,411 23 181,834

Egypt Lake Charles, LA 290 hr 1,448 2,897 75,655 62,542 35 359,714 10.45

Nigeria Lake Charles, LA 272 hr 1,359 2,718 75,922 57,292 32 308,643 11.09

Trinidad & Tobago Cove Point, MD 89 hr 446 891 78,663 84,590 45 142,305

Trinidad & Tobago Elba Island, GA 89 hr 446 891 78,663 104,356 55 173,928

Trinidad & Tobago Everett, MA 89 hr 446 891 78,663 176,097 93 294,096

Trinidad & Tobago Gulf Gateway, LA 98 hr 490 980 78,529 453 1 3,479

Trinidad & Tobago Lake Charles, LA 98 hr 490 980 78,529 23,773 13 45,221 3.64

Exhibit 43: Emissions from LNG Shipping in 2020 

Origin Destination Trip 

Duration

Ship Size 

(m3 LNG)

One-way Boiloff (m3 LNG)LNG heel left 

(m3 LNG)

Amount 

Unloaded (m3 

LNG)

Total Volume 

Delivered 

(MMcf gas)

# of Trips Emissions 

(tonnes CO2)

Country Specific 

Emissions 

Intensity (lbs 

CO2e/MMBtu)

Algeria New Gulf 209 hr 150,000 1,964 3,927 144,109 361,000 104 801,694 4.63

Egypt Cove Point, MD 223 hr 150,000 2,089 4,178 143,733 147,000 43 352,627

Egypt Lake Charles, LA 290 hr 150,000 2,716 5,431 141,853 214,000 63 671,632

Egypt Gulf Gateway, LA 290 hr 150,000 2,716 5,431 141,853 137,000 40 426,433

Egypt New East Coast 223 hr 150,000 2,089 4,178 143,733 10,000 3 24,602 5.99

Nigeria Cove Point, MD 223 hr 150,000 2,089 4,178 143,733 147,000 43 352,627

Nigeria Elba Island, GA 201 hr 150,000 1,880 3,760 144,360 207,000 60 442,834

Nigeria New Gulf 272 hr 150,000 2,548 5,097 142,355 335,000 98 980,468 5.34

Trinidad & Tobago Elba Island, GA 89 hr 150,000 836 1,671 147,493 368,000 104 341,146

Trinidad & Tobago Lake Charles, LA 98 hr 150,000 919 1,838 147,243 361,000 102 368,045 2.09

Indonesia/Papua New Guinea Baja California 312 hr 150,000 2,924 5,849 141,227 82,000 24 275,541 6.87

Russia Baja California 178 hr 150,000 1,671 3,342 144,987 205,000 59 387,070 4.07

Australia Baja California 334 hr 150,000 3,133 6,267 140,600 123,000 37 455,135 7.51

Middle East/Qatar Everett, MA 357 hr 150,000 3,342 6,684 139,973 268,000 80 1,049,682

Middle East/Qatar Cove Point, MD 432 hr 150,000 4,052 8,105 137,843 199,000 60 954,554

Middle East/Qatar New East Coast 432 hr 150,000 4,052 8,105 137,843 48,000 15 238,639 8.80

Norway New East Coast 178 hr 150,000 1,671 3,342 144,987 79,000 23 150,892

Norway New Gulf 223 hr 150,000 2,089 4,178 143,733 396,000 114 934,873 4.89

LNG Storage and Regasification 

GHG emission from the LNG storage and regasification was almost 470,000 tonnes CO2e in 

2006, but is forecast to grow to almost 3 million tonnes by 2020 due to the increased 

requirements for LNG in the U.S. Emissions intensity for regasification operations is estimated 

to be 1.75 lb CO2e/MMBtu, growing slightly to 1.80 lb CO2e/MMBtu in 2020. 

Total emissions from LNG storage and regasification by U.S. destination are summarized in 

Exhibit 44 for 2006 and in Exhibit 45 for 2020. 

Exhibit 44: Emissions from LNG Storage and Regasification in 2006 

Region

Fuel for 

Vaporization 

(MMcf/year)

CO2 

Emissions 

(tonnes)

CH4 Emissions 

(tonnes)

N2O Emissions 

(tonnes)

CO2e 

Emissions 

(tonnes)

LNG Imports 

(MMcf)

Emissions 

Intensity (lbs 

CO2e/MMBtu)

East Coast 6,516.81 351,233 7 7 353,392 439,478 1.75

Gulf Coast 2,136.20 115,134 2 2 115,841 144,060 1.75

West Coast 0.00 00 0 0 0
 November 10, 2008 

54

Exhibit 45: Emissions from LNG Storage and Regasification in 2020 

Region

Fuel for Vaporization 

(MMcf/year)

CO2 

Emissions 

(tonnes)

CH4 Emissions 

(tonnes)

N2O 

Emissions 

(tonnes)

CO2e 

Emissions 

(tonnes)

LNG 

Imports 

(MMcf)

Emissions 

Intensity (lbs 

CO2e/MMBtu)

East Coast 21,842.41 1,177,229 23 22 1,184,465 1,473,000 1.75

Gulf Coast 26,750.65 1,441,766 28 27 1,450,628 1,804,000 1.75

West Coast 6,079.69 327,674 6 6 329,688 410,000 1.75

Natural Gas Transmission 

As described above, LNG imports were assumed to enter the domestic transmission system 

and travel only a short distance to the nearest market of sufficient size to consume the total 

imports to a particular region. Because LNG imports make up a small portion of the overall 

transmission system throughput and travel much shorter distances compared to U.S. natural 

gas supplies, transmission sector emissions for imported LNG are relatively small, as are the 

corresponding emissions intensity. 

Overall, total GHG emission from natural gas transmission in the U.S. was nearly 49 million 

tonnes in 2006, decreasing to 36 million tonnes in 2020 due to increased efforts at reducing 

emissions in the transmission sector. The vast majority of emissions in this sector are due to 

U.S.-sourced supplies in both 2006 and 2020. The incremental LNG-related emissions intensity 

for imported LNG in 2006 was 0.13 lb CO2e/MMBtu, while the emissions intensity for the 

transmission system for U.S natural gas supply was 5.49 lb CO2e/MMBtu. In 2020, the 

incremental emissions intensity for imported LNG was estimated to be 0.02 lb CO2e/MMBtu, 

while that for the U.S. transmission associated with U.S. natural gas supply was estimated to be 

3.82 lb CO2e/MMBtu. 

It should be noted that transmission emissions were estimated taking into consideration pipeline 

fuel use for both LNG and U.S. sources gas supplies. LNG emissions are estimated by 

applying a factor for emissions intensity per mile of pipeline, and the estimated the distance 

between the LNG regasification terminal and the nearest major market demand center in the 

appropriate in each region. Thus, the LNG sourced supply was assumed to travel a short 

distance within the transmission system, and therefore emissions are relatively small. These 

emissions are subtracted out of the total U.S. transmission system, and factor only into the 

transmission-related intensity for LNG sourced supply. The emissions associated with U.S. 

sourced supply are estimated by deducting the LNG emissions from the U.S. transmission 

system total, and then intensity is calculated using the total end user consumption of U.S. 

sourced supply only. 

The breakdown of emissions by AEO demand region for both CO2 and methane is show in 

Exhibit 46 for the U.S. natural gas supply scenario, with the emissions intensity defined in terms 

of gas throughput through the natural gas transmission system.
 

55

Exhibit 46: Transmission Sector Emissions by AEO Demand Region for 2006 and 2020 

AEO Demand Region CO2(Mg)

CH4 (Mg) -- w/ 

Natural Gas 

STAR Adj. CO2e (Mg)

Gas 

Throughput 

(Quads)

Intensity (lb 

CO2e/MMBtu) CO2(Mg)

CH4 (Mg) -- w/ 

Natural Gas 

STAR Adj. CO2e (

New England 430,614 70,291 1,906,721 0.56 7.43 575,930 43,659 1,492,7Middle Atlantic 1,279,817 239,494 6,309,200 2.56 5.42 1,494,756 132,265 4,272,3East North Central 2,123,719 379,194 10,086,788 4.57 4.87 2,490,303 220,457 7,119,9West North Central 718,615 135,163 3,557,047 1.63 4.80 938,040 86,079 2,745,7South Atlantic 1,170,769 161,463 4,561,487 1.93 5.20 1,470,257 98,382 3,536,2East South Central 542,620 89,443 2,420,930 1.14 4.67 748,581 50,762 1,814,5 West South Central 2,862,680 322,153 9,627,898 4.46 4.76 3,465,535 201,739 7,702,0Mountain 941,056 109,536 3,241,313 1.29 5.54 1,109,818 66,559 2,507,5Pacific 1,715,180 240,710 6,770,081 2.97 5.03 1,903,498 131,069 4,655,9

CH4 (Mg) -- 

No Natural 

Gas Star Adj.

CH4 (Mg) -- 

No Natural 

Gas Star Adj.

92,691 115,145

315,817 348,831500,036 581,425178,237 227,022212,918 259,468117,947 133,878424,817 532,060144,443 175,540317,419 345,675

Natural Gas STAR Reductions 24.2% 62.1%
 

 November 10, 2008 56

Natural Gas Distribution 

Overall, total GHG emission from the distribution sector was 27 million tonnes in 2006, declining 

to 15 million tonnes in 2020 due to the replacement of older less efficient distribution piping, 

mains, and services with lower emissions technology over time. In 2006, emissions intensity 

was estimated as 2.98 lb CO2e/MMBtu for U.S. natural gas supply and imported LNG. In 2020, 

emissions intensity for imported LNG and U.S. natural gas supply was 1.37 lb CO2e/MMBtu. 

Emissions for the distribution sector are the same for both the U.S. natural gas supply and LNG 

scenarios. The breakdown of emissions by AEO demand region for both CO2 and methane is 

shown in Exhibit 47. 

Exhibit 47: Distribution Sector Emissions by AEO Demand Region for 2006 and 2020 

NEMS Demand Region

Gas 

Throughput 

(Quads) CO2( Mg)

CH4 (Mg) 

w/o Natural 

Gas STAR 

Reductions

CH4 (Mg) w/ 

Natural Gas 

STAR 

Reductions

Emissions 

Intensity (2020) 

(lb CO2e/MMBtu)

Gas 

Throughput 

(Quads) CO2( Mg)

CH4 (Mg) 

w/o Natural 

Gas STAR 

Reductions

CH4 (Mg) w/ 

Natural Gas 

STAR 

Reductions

Emissions 

Intensity (2020) 

(lb CO2e/MMBtu)

New England 0.48 1,500 51,933 50,449 4.91 0.52 1,694 58,661 28,493 2.52

Middle Atlantic 2.18 6,789 235,068 228,351 4.85 1.96 7,017 242,946 118,003 2.79

East North Central 4.09 10,348 358,245 348,009 3.95 4.33 11,144 385,838 187,407 2.01

West North Central 1.54 3,331 115,326 112,031 3.37 1.86 3,762 130,236 63,258 1.58

South Atlantic 1.91 3,617 125,180 121,603 2.96 1.91 4,407 152,558 74,100 1.80

East South Central 1.22 1,525 52,784 51,276 1.95 1.21 1,720 59,515 28,907 1.11

 West South Central 5.29 2,985 103,166 100,218 0.88 6.56 3,407 117,715 57,176 0.40

Mountain 1.18 2,844 98,473 95,660 3.75 1.23 3,391 117,415 57,030 2.16

Pacific 2.87 5,484 189,824 184,401 2.98 2.67 6,093 210,923 102,448 1.78

Natural Gas STAR Reductions 2.9% 51.4%

2006 2020

End Use Consumption 

Overall, total GHG emission from end use consumption was 1.04 billion tonnes in 2006, growing 

to 1.10 billion tonnes in 2020 due to increased consumption of natural gas. The breakdown of 

end use consumption emissions by AEO demand region is shown in Exhibits 48 and 49 for 

2006 and 2020, respectively. The emissions intensity of end use consumption is 117.06 lb 

CO2/MMBtu for both imported LNG and U.S. natural gas supply and makes up over threefourths of total well-to-burner tip emissions. Emissions for the end use consumption sector are 

the same for both the U.S. natural gas supply and LNG scenarios. 
 

57 

Exhibit 48: Consumption Emissions by AEO Demand Region for 2006 (tonnes CO2e) 

New 

England

Middle 

Atlantic

East North 

Central

West North 

Central

South 

Atlantic

East South 

Central

 West South 

Central Moun

Residental 9,437,887 42,151,106 66,899,328 20,659,006 21,511,721 9,011,542 15,116,504 17,75Commercial 6,270,956 30,483,527 34,490,258 13,896,735 17,999,869 6,812,781 15,851,641 11,76Industrial 4,396,990 18,672,643 61,243,898 23,484,123 29,281,303 24,825,027 127,772,014 16,30Electric Power Generation 21,202,881 22,692,591 28,669,330 2,746,491 43,069,974 8,831,733 110,070,487 28,89Transportation 142,435 318,668 339,540 167,095 407,612 147,685 250,419 16

Exhibit 49: Consumption Emissions by AEO Demand Region for 2020 (tonnes CO2e) 

New 

England

Middle 

Atlantic

East North 

Central

West North 

Central

South 

Atlantic

East South 

Central

West South 

Central Moun

Residental 11,345,211 46,679,477 76,219,032 24,702,768 27,663,991 10,751,627 17,910,068 22,738Commercial 8,086,770 35,610,097 42,944,323 17,951,343 27,789,480 9,522,677 20,827,549 15,472Industrial 6,626,197 19,996,754 75,072,932 34,328,368 28,268,554 25,013,554 166,298,235 18,716Electric Power Generation 29,704,961 31,945,805 31,250,415 4,412,241 56,014,420 25,538,310 126,376,234 32,964Transportation 374,513 598,808 611,696 396,351 834,548 372,871 566,694 456
 November 10, 2008 

58

EMISSIONS INTENSITY OF NATURAL GAS SUPPLIES FROM 

CANADA 

In this study, the GHG emissions intensity associated with natural gas supplies from Canada, 

delivered across the border to serve the U.S. market, was not specifically assessed. The 

primary reason was that ICF’s proprietary set of data, models, and analytical procedures, for the 

most part developed to support EPA in their GHG emission inventory work for the U.S. 

petroleum and natural gas sector26 did not have the capability of performing a comparable 

assessment for the Canadian supply chain. 

Moreover, to our knowledge, the only comparable supply chain assessment performed on the 

Canadian natural gas supply chain was performed based on estimates of industry emissions in 

1995.27 The results of this study are summarized in Exhibit 50. As shown, this shows overall 

emissions intensity of the Canadian natural gas supply chain (production, transmission, and 

storage) of 13.71 lb CO2e/MMBtu. 

Some insight can also be gained from the Canadian national inventory of GHG emissions.28

This report does look specifically at the emissions characteristics of natural gas exports (the 

vast majority of which are imports to the U.S.) A review of the results of this inventory, 

summarized in Exhibit 51, shows that the overall natural gas supply sector can be characterized 

by an overall emissions intensity of 16.66 to 16.98 lb CO2e/MMBtu over the 2003 to 2006 time 

period. 

Again, the emissions intensity of the Canadian gas supply system appears to be lower than that 

in the U.S., though it is difficult to ascertain whether either of these comparisons are truly 

“apples-to-apples.” 

When considering the relative role of Canadian natural gas in the overall emissions profile of the 

U.S. natural gas market, it is also important to realize that most forecasts call for a significant 

reduction in natural gas imports of Canadian gas into the U.S. between now and 2020. For 

example, the Canadian National Energy Board (NEB), in its most recent Reference Case 

outlook for Canada natural gas, forecasts that Canadian exports to the U.S. will drop from 7.3 

Bcf per day in 2005 to 2.5 Bcf per day by 2020, a two-thirds reduction.29 Under some scenarios 

considered by the NEB, Canada could become a net importer of gas by 2020. These results are 

summarized in Exhibit 52. 

Similarly, EIA’s 2007 AEO forecasts U.S. imports from Canada to decline from 8.24 Bcf per day 

in 2005 to 4.53 Bcf per day by 2020, a 45% decrease. (In the more recent 2008 AEO, imports 

from Canada are forecast to fall even further, to 3.24 Bcf per day, a 61% decline relative to the 

2008 AEO estimate for Canadian imports in 2005.) These results are summarized in Exhibit 53. 

 

26 http://www.epa.gov/climatechange/emissions/usinventoryreport.html 27 Whittaker, S.M., G. McGuire, T, Irwin, and K. Humphreys, “A life cycle analysis of the Canadian natural 

gas system,” Gasunie Engineering and Technology, paper presented at the 39th Annual Conference of 

Metallurgists of CIM, Ottawa, ON (Canada), August 8, 2000 

(http://gasunie.eldoc.ub.rug.nl/root/2000/2042764/) 

28 Environment Canada, National Inventory Report: Greenhouse Gas Sources and Sinks in Canada 

(1990-2005), April 2007 (http://www.ec.gc.ca/pdb/ghg/inventory_e.cfm) 29 National Energy Board of Canada, Canada’s Energy Future: Reference Case and Scenarios to 2030, 

An Energy Market Assessment, November 2007 (http://www.neb.gc.ca/clfnsi/rthnb/nwsrls/2007/nwsrls38-eng.html) 
 November 10, 2008 

59

Exhibit 50: Life Cycle Emissions Analysis of the Canadian Natural Gas System (1995) 

Emissions (kilotonnes)

CO2 CH4 Total

Upstream 25,500 735 26,235 

Transmission 5,295 280 5,575 

Storage 62 6 68

Supply Total 30,857 1,021 31,878 

Distribution 81 58 139 

End Use 119,515 3 119,518 

 

TOTAL 150,453 1,082 151,535 

 

Emissions (tonnes/million m3

)

CO2 CH4 Total

Upstream 146.70 4.12 150.82 

Transmission 31.90 1.69 33.59 

Storage 1.00 0.10 1.10

Supply Total 179.60 5.91 185.51 

Distribution 1.30 0.90 2.20 

End Use 1851.20 0.05 1851.25 

 

TOTAL 2032.10 6.86 2038.96 

 

Emissions (lb. CO2e/MMBtu)

CO2 CH4 Total

Upstream 10.84 0.30 11.14 

Transmission 2.36 0.12 2.48 

Storage 0.07 0.01 0.08 

Supply Total 13.27 0.44 13.71 

Distribution 0.10 0.07 0.16 

End Use 136.78 0.00 136.79 

 

TOTAL 150.15 0.51 150.66 
 November 10, 2008 

60

Exhibit 51: Canadian Natural Gas Production, Export, and GHG Emission Trends in the Canadian 

National Inventory Report (1990-2005) 

1990 1995 2000 2003 2004 2005

Production 

PJ 4,184 6,129 7,060 7,064 7,096 7,250

Quads 3,975 5,823 6,707 6,711 6,741 6,888

Imports 

PJ 24 26 62 370 415 375

Quads 23 25 59 352 394 356

Exports 

PJ 1,537 3,011 3,846 3,876 4,022 4,066

Quads 1,460 2,860 3,654 3,682 3,821 3,863

Consumption 

PJ 2,671 3,144 3,276 3,557 3,489 3,558

Quads 2,537 2,987 3,112 3,379 3,315 3,380

Emissions Associated with Gross 

Exports 

Mt CO2e 13.9 26.5 33.1 33.4 34.6 34.9

Mt CO2e/Quad 9,520 9,264 9,059 9,071 9,055 9,035

lb. CO2e/MMBtu 20.99 20.42 19.97 20.00 19.96 19.92

Emissions Associated with Net Exports 

Mt CO2e 12.7 25.1 31.1 25.6 25.9 27.0

Mt CO2e/Quad 8,836 8,851 8,651 7,686 7,558 7,700

lb. CO2e/MMBtu 19.48 19.51 19.07 16.94 16.66 16.98
 November 10, 2008 

61

Exhibit 52: Canadian Natural Gas Production and Export Forecasts of the Canadian National 

Energy Board 

2000 2005 2010 2015 2020

Fortified Islands 478 528 567 

Triple E 470 351 199 

Continuing Trends 434 387 

Reference Case 484 485 450 434 

 

Canadian Natural Gas Export Outlook (million cubic meters per day) 

 2000 2005 2010 2015 2020

Fortified Islands 243 275 307 

Triple E 237 111 -42 

Continuing Trends 154 87 

Reference Case 268 258 197 154 

 

Canadian Natural Gas Production Outlook (billion cubic feet per day) 

2000 2005 2010 2015 2020

Fortified Islands 13.55 14.97 16.07 

Triple E 13.32 9.95 5.64 

Continuing Trends 12.30 10.97 

Reference Case 13.72 13.75 12.76 12.30 

 

Canadian Natural Gas Export Outlook (billion cubic feet per day) 

 2000 2005 2010 2015 2020

Fortified Islands 6.89 7.79 8.70 

Triple E 6.72 3.15 -1.19 

Continuing Trends 4.37 2.47 

Reference Case 7.60 7.31 5.58 4.37 
 November 10, 2008 

62

Exhibit 53: U.S. Natural Gas Supply and Import Forecasts by the Energy Information Administration 

(AEO 2007 vs. AEO 2008) 

(Trillion cubic feet) 

AEO 2007

2005 2010 2015 2020

U.S. Dry Gas Production 18.23 19.35 19.60 20.79 

Net Imports 3.57 4.55 5.62 5.35

Canadian Imports 3.01 2.74 2.63 1.65 

Canadian Imports (Bcf/day) 8.24 7.50 7.21 4.53 

LNG Imports 0.57 1.81 2.99 3.69 

LNG Imports (Bcf/day) 1.55 4.97 8.19 10.11 

AEO 2008

2005 2010 2015 2020

U.S. Dry Gas Production 18.07 19.29 19.52 19.67 

Net Imports 3.61 3.85 4.03 3.55

Canadian Imports 3.05 2.64 1.91 1.18 

Canadian Imports (Bcf/day) 8.35 7.24 5.24 3.24 

LNG Imports 0.57 1.20 2.12 2.37 

LNG Imports (Bcf/day) 1.55 3.29 5.80 6.50 
 November 10, 2008 

63

APPENDIX A 

Environmental Impact Statements and Supporting 

Documentation used in this Analysis 

Darwin LNG Project (Liquefaction)

Environmental Management Plan for 3.24 MMTPA LNG Plant (Built) 

Table 5-3 on Page 5-10 of the following document: 

http://www.darwinlng.com/NR/rdonlyres/29AF4F2F-5F81-4AB7-A10FE7668F462826/0/DLNGHSEPLN001_s05_r1.pdf

Original Public Environmental Report for 10 MMTPA LNG Plant (Not Built) 

Table 2.4.1 on Page 2-23 of the following document: 

http://www.darwinlng.com/NR/rdonlyres/58532319-5951-480A-AAD1-

732999333024/0/PER_Section_2.pdf

Table 4.4 on Page 4-8 of the following document: 

http://www.darwinlng.com/NR/rdonlyres/FDFA46BA-9116-4E96-ADF3-

F7F2E4ED77E7/0/PER_Section_4.pdf

General Environmental Information: 

http://www.darwinlng.com/Environment/Index.htm

Gorgon LNG Project (Liquefaction)

Draft Environmental Impact Statement/Environmental Review and Management Plan 

Chapter 1, Page 11, Table 1-2 

Chapter 6, Page 96, Table 6-1 

Chapter 13 (especially Table 13-6) 

http://www.gorgon.com.au/03moe_eis.html#frames(content=03moe_eis_body.html)

http://www.gorgon.com.au/03-man_environment/EIS/gorgon_ch01_LR.pdf

http://www.gorgon.com.au/03-man_environment/EIS/gorgon_ch06_LR.pdf

http://www.gorgon.com.au/03-man_environment/EIS/gorgon_ch13_LR.pdf

Final Environmental Impact Statement/Environmental Review and Management Plan 

http://www.gorgon.com.au/03moe_finaleis.html#frames(content=03moe_finaleis_body.html)

Snohvit LNG Project (Liquefaction)

The following two documents are in Norwegian but may be of some use. See Table 5-8 on 

Page 88 of the 2nd document. 

http://www.snohvit.com/STATOILCOM/snohvit/svg02699.nsf/Attachments/Utslippssoknad.pdf/$

FILE/Utslippssoknad.pdf

http://www.snohvit.com/STATOILCOM/snohvit/svg02699.nsf/Attachments/konsekvensutredning

.pdf/$FILE/konsekvensutredning.pdf

Environmental and Technology Webpage 

http://www.snohvit.com/STATOILCOM/snohvit/svg02699.nsf?OpenDatabase&lang=en

Pluto LNG Project (Liquefaction)
 November 10, 2008 

64

Draft Public Environmental Report/Public Environmental Review, Chapter 5 (Attached) 

Table 5-2, 5-3 & 5-4 

Chapters 1 and 4 also attached for generally background 

Tangguh LNG Project (Liquefaction

BP statement regarding CO2 content: 

http://www.bp.com/sectiongenericarticle.do?categoryId=9004748&contentId=7008786

Summary Environmental Impact Statement (limited information) 

http://www.adb.org/Documents/Environment/Ino/ino-tangguh-lng-project.pdf

Life cycle CO2 analysis of LNG and city gas 

Itaru Tamura, Toshihide Tanaka, Toshimasa Kagajo, Shigeru Kuwabara, Tomoyuki Yoshioka, 

Takahiro Nagata, Kazuhiro Kurahashi, Hisashi Ishitani. Applied Energy 68 (2001) 301±31 

Article contains some information but must be purchased at the following website: 

http://www.sciencedirect.com/science?_ob=ArticleURL&_udi=B6V1T-423480C6&_user=10&_rdoc=1&_fmt=&_orig=search&_sort=d&view=c&_acct=C000050221&_version=1

&_urlVersion=0&_userid=10&md5=b92483f5a07fa8c315db500191722226

Canaport LNG Terminal

Environmental Impact Statement, Chapter 5 

http://www.ceaa-acee.gc.ca/010/0003/0012/5a_e.pdf