# 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 SU MMARY ................................................................................................ 1 Conclu sions.................................................................................................................... ........................... 4
OVERVIEW OF INPUT DATA, ME THODOLOGY AND AS SUMPTIONS...................... 5 Background and Introduction .................................................................................................... ................ 5 Methodology Description – U.S. Natu ral 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 Natu ral 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 RE SULTS.......................................................... 33 Exploration a nd Develo pment .................................................................................................... ............. 33 Natural Gas Producti on ......................................................................................................... .................. 38 Natural Gas Proce ssing ......................................................................................................... ................. 42 Natural Gas Liquef action an d Loadi ng ........................................................................................... ......... 52 LNG Ship ping................................................................................................................... ....................... 52 LNG Storage and R egasification................................................................................................. ............ 53 Natural Gas Transmi ssion....................................................................................................... ................ 54 Natural Gas Di stribut ion ....................................................................................................... ................... 56 End Use Cons umption ............................................................................................................ ................ 56

EMISSIONS INTENSITY OF NATURAL GAS SUPPLIES FR OM CANADA ............... 58

APPENDIX A - Environmental Impact St atements and Supporting Documentation used in this Analysis

### November 10, 2008 ii 

# LIST OF EXHIBITS

Exhibit 1: 2006 GHG Emissions Intens ity from U.S. Natu ral Gas S upply ..................................................... 2 Exhibit 2: 2006 GHG Emissions Intensity fr om LNG Supply Servin g U.S. Ma rket......................................... 2

Exhibit 3: 2020 GHG Emissions Intensit y from U.S. Natu ral Gas S upply ...................................................... 3 Exhibit 4: 2020 GHG Emissions Intensity fr om LNG Supply Servin g U.S. Ma rket......................................... 3

Exhibit 5: Process for Estimating GH G Emi ssions................................................................................ ......... 7

Exhibit 6: EIA AEO Supply R egions.............................................................................................. ................. 8 Exhibit 7: Estimated Number of Production Wells, by Region and Resource Type, in 2006 and 2020........ 11 Exhibit 8: Average CO 2 

### Content (weighted by production), by Region and Resource Type, in 2006 and 2020............................................................................................................... .......................... 12 Exhibit 9: Ranges of CO 2 

### Content for Selected Regions by Basin and Res ource Ty pe.............................. 13

Exhibit 10: EIA AEO Demand R egions............................................................................................. ........... 16 Exhibit 11: Estimates of Key Activity Factors fo r Natural Gas Transmission, by Region, in 2006 and 2020............................................................................................................... .......................... 17 Exhibit 12: Estimates of Key Activity Factors for Na tural 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 term inals in 2004, 2005, and 2006........... 20 Exhibit 15: Existing and Proposed Nort h American LNG Impor t Termi nals ................................................. 21 Exhibit 16: Assumed Capacity Expansions for Existing LNG Import Facilities, Sizes for New Facilities, and Assumed Capacity Ut ilization in 2020........................................................................................... ............... 22 Exhibit 17: LNG Imports and Estimated Transpor t 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 Requirem ents for 2006 and 2020 ........................................................................................ ........ 24 Exhibit 19: Representative Emission Factors for Ex ploration and Development for Trinidad and Tobago for 2006 and 202 0.................................................................................................................. ........................... 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 F ugitive Emissions for Trinidad and Tobago in the Production Sector .............................................................................................................. .......................... 27 Exhibit 22: Key Activity Factors for Gas Li quefaction by Source Country for 2006 and 2020 ..................... 29 Exhibit 23: Key Activity Factor s for LNG Shipping, by Source C ountry and Delivery Point, for 2006.......... 30 Exhibit 24: Key Activity Factor s for LNG Shipping, by Source C ountry and Delivery Point, for 2020.......... 31

### November 10, 2008 iii 

### Exhibit 25: Comparison of GHG Emissions for Expl oration and Development for U.S. Natural Gas for 2006 and 2020

....................................................................................................................... ............................... 34 Exhibit 26: Comparison of GHG Emissions for Explor ation and Development for LNG Supplies Serving U.S. Markets for 2006 and 2020...................................................................................................... .................... 35 Exhibit 27: Exploration and Development Emissi ons Intensity by AEO Supply Region for 2006 and 2020

.............................................................................................................. ......................... 36 Exhibit 28: Explorat ion and Deve lopment ....................................................................................... ............ 37

Exhibit 29: Emissions from Production O perations by AEO S upply Region - 2006 .................................... 39

Exhibit 30: Emissions from Production O perations by AEO S upply 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 Intens ity for LNG, by Source Country, for 2006 and 2020

.............................................................................................................. ......................... 41

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

Exhibit 34: Emissions from Natural Gas Proc essing of U.S. Supplies, by Region for 2020 ........................ 45 Exhibit 35: Emissions Intensity for U.S. Natural Gas Processing by NE MS Supply Region, for 2006 (Mg). 46 Exhibit 36: Emissions Intensity for U.S. Natural Gas Processing by NE MS Supply Region, for 2020 (Mg). 47 Exhibit 37: Emissions from Natural Gas Processing fo r U.S. LNG Markets, by Country of Origin, 2006 .... 48 Exhibit 38: Emissions from Natural Gas Processing fo r U.S. LNG Markets, by Country of Origin, 2020 .... 49 Exhibit 39: Emissions Intensity fo r U.S. Natural Gas Processing by LNG Source Country, for 2006 (Mg) .. 50 Exhibit 40: Emissions Intensity fo r U.S. Natural Gas Processing by LNG Source Country, for 2020 (Mg) .. 51
Exhibit 41: Natural Gas Liquefaction Emissions Int ensity for LNG, by Source Country, for 2006 and 2020

.............................................................................................................. ......................... 52

Exhibit 42: Emissions fr om LNG Shippi ng in 2006............................................................................... ....... 53

Exhibit 43: Emissions fr om LNG Shippi ng in 2020............................................................................... ....... 53

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

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

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

Exhibit 47: Distribution Sector Emissions by AEO Demand Regi on for 2006 and 2020 (Mg) ..................... 56 Exhibit 48: Consumption Emissions by AEO Demand Region fo r 2006 (tonnes CO2e) ............................. 57 Exhibit 49: Consumption Emissions by AEO Demand Region fo r 2020 (tonnes CO2e) ............................. 57 Exhibit 50: Life Cycle Emissions Analysis of the Canadian Natural Gas System (1995) ............................ 59 Exhibit 51: Canadian Natural Gas Production, Expor t, and GHG Emission Trends in the Canadian National Inventory R eport ( 1990-2005)

................................................................................................... ................... 60

Exhibit 52: Canadian Natural Gas Production and Ex port 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 (CO 2 

### e) 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 CO 2 

### e 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 (CO 2 

### ), methane (CH 4 

### ), and nitrous oxide (N 2 

### O). 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 CO 2 

### e 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 dom estic 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 CO 2 

### e/MMBtu of natural gas in 2006, while imported LNG was estimated to have an intensity of 145.92 lb CO 2 

### e/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 CO 2 

### e/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 CO 2 

### e/MMBtu in 2020, compared to an estimated emissions intensity for imported LNG of 147.25 lb CO 2 

### e/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 Intens ity from U.S. Natural Gas Supply

145.78 0.50 13.10

6.64

5.49 2.98 117.06

0 20 40 60 80 100 120 140 160

Burner Tip Distribution Transmission Processing Production E&D Totallb CO2e/MMBtu



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

0.37 145.92 1.57 6.46
9.52

6.07 1.75 0.13 2.98 117.06

0 20 40 60 80 100 120 140 160

Burner Tip Distribution Transmission Regasification Shipping Liquefaction Processing Production E&D Totallb CO2e/MMBtu

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### Exhibit 3: 2020 GHG Emissions Intens ity 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 Totallb 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 1.80 0.02 1.37 117.06

0 20 40 60 80 100 120 140 160

Burner Tip Distribution Transmission Regasification Shipping Liquefaction Processing Production E&D Totallb CO2e/MMBtu

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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.


## ConclusionsOverall, 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 CO 2 

### 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 in tensity 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.

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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 (CO 2 

### e) 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 CO 2 

### e emissions associated with natural gas delivered to consum ers. 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 CO 2 

### e emissions associated with construction and/or decommissioning of pipelines, distribution systems, power plants, etc.
The comparison considered the GHG emissions associated with carbon dioxide (CO 2 

### ), methane (CH 4 

### ), and nitrous oxide (N 2 

### O). 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 CO 2 

### e 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 bot h 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 explorati on, 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.

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### • 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, em issions 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

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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 estimati on 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 Fa ctor * 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 Program 4 

### 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 CH 4 , CO 2 , and N 2 O Model Inputs (Activity Drivers)

Natural Gas STAR Reductions

Activity Factors

Emission Factors Emissions (for CH 4 , CO 2 , and N 2 O

### 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 ri gs, 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:

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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 ProductionNatural 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_f uel_combustion_for_petroleum_production.doc

### November 10, 2008

10 

### • Average gas/condensate production per well

• Average CO 2 

### 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, chem ical 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.

CO 2 

### emissions from lease fuel consumption asso ciated with operating field equipment such as pumps, compressors, heaters, etc. are calculated for the production sector. Additional CO 2 

### emissions associated with fugitive leaks and venting of natural gas have also been calculated using the average regional CO 2 

### 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 CO 2 

### vented from processing (which is a function of the CO 2 

### 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

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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 (CO 2 

### ), methane (CH 4 

### ), and nitrous oxide (N 2 

### O) 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 CO 2 

### , CH 4 

### , and N 2 

### O emissions from individual gas

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12 

### processing facilities in the United States. These data were developed based on initial work for the Gas Research Institute (GRI). 9


### The average CO 2 

### 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 CO 2 

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



### Exhibit 8: Average CO 2 

### Content (weighted by production), by Region and Resource Type, in 2006 and 2020

2006 Gas Composition 2020 Gas Composition

Region Well Type CO 2 Content in Produced Gas Well Type CO 2 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 CO 2 

### 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 CO 2 

### Content for Selected Regions by Basin and Resource Type

Region Basin Name Formation No. of Reservoirs A vg. 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 CO 2 

### Content for Selected Regions by Basin and Resource Type (continued)

Region Basin Name Formation No. of Reservoirs A vg. 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

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## 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

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### Exhibit 10: EIA AEO Demand Regions

### November 10, 2008

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### Exhibit 11: Estimates of Key Activity Factors for Natural Gas Transmission, by Region, in 2006 and 2020

NATIONAL

TOTAL New England Middle Atlantic E ast North Central W est North Central South Atlantic E ast South Central W est South Central Mountain Pacific

2006 Gas Consumption: Residential Quad s 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 fac ilities 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 fac ilities 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 Quad s 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 fac ilities 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 fac ilities 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 deliver ed. 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 emission s 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 F actors 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 6.7 6 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 5,65 5 24,016 78,770 30,204 37,661 31,92 9 164,336 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 3.7 5 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

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## Methodology Description – Liquefied Natural Gas Imported LNG shares the same six supply chai n 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 th e 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 Energy 11 

### 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/in dus-act/terminals/ex ist-prop-lng.pdf

### November 10, 2008

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### 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 m any 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/in dus-act/terminals/ex ist-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, L A 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, L A 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, L A 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

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### Exhibit 15: Existing and Proposed No rth 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 reports 15 

### 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 im port 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/progr ams/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

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### • Expansions of existing LNG import termi nals 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

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### 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 Trans port Distance by Country of Origin in 2020

T & T Nigeria Egypt A lgeria Russia A ustralia 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 91 9 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 affect ing 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 producin g 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 expec ted 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. LN G Markets and Uses, June 2004 Update,”, June 2004

19 http://www.energy.ca.gov/lng/documents/200 5-08_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 Factor s Affecting Emissions from Expl oration and Development Activities to Serve U.S. LNG Requirements for 2006 and 2020

T&T Nigeria Egypt A lgeria 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 A lgeria 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 fr om 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 Emissi on Factors for Exploration and Development for Trinidad and Tobago for 2006 and 2020
Trinidad & Tobago

Carbon Dioxide Emissions

Emission Sources CO 2 Emissions Factor Activity Factor CO 2 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 CH 4 Emissions Factor Activity Factor CH 4 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 Fu gitive Emissions for Trinidad and Tobago in the Production Sector for 2006 and 2020

T&T Nigeria Egypt A lgeria 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 A lgeria 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 facilit y 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 CO 2 Emission

Factor CH 4 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 CO 2 

### vented from processing (which is a function of the CO 2 

### content of produced gas). The average CO 2 

### 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 countri es 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 processi ng 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 CO 2 

### and hydrogen sulfide (H 2 

### S) 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 CO 2 

### content of the gas were adjusted in the representative facili ty 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 CO 2 

### separated in nearby geologic formations. Such pl ants 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 A lgeria 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 Fact ors for Gas Liquefaction by Source Country for 2006 and 2020

T&T Nigeria Egypt A lgeria Amount LNG Delivered to US MMcf 389,269 57,292 119,528 17,449 Storage cap alloc to U.S. m 3 360,826 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. m 3 540,319 271,844 152,512 108,676 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 Optimi zed Cascade Process. ” March. 2006. http://lnglicensing.conocophillips.com/lng_tec h_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/aer o_turbines/en/downloads/lm2500plus.pdf Pluto LNG. “Emissions, Di scharges, and Wastes.” http://standupfortheburrup.de/ downloads/05emissionsd ischargesa ndwaste.pdf

### November 10, 2008

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## 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 m 3 

### . 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 m 3 

### 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 F actors 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/progr ams/oilgas/publications /lng/LNG_primerupd.pdf) 24 http://www.shell.com/static/shippin g-en/downloads/lngbrochure.pdf

### November 10, 2008

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### Exhibit 24: Key Activity F actors 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 CO 2 

### (and NO x 

### ) 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 m 3 303,000 425,000 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

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# 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 chai n emissions. Overall, total emissions from exploration and development from U.S. supply sources were 4.4 million tonnes of CO 2 

### e in 2006, declining to 3.5 million tonnes of CO 2 

### e 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 CO 2 

### e in 2006, growing to over 980,000 tonnes of CO 2 

### e by 2020.
Emissions from exploration and development are c haracterized 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 asso ciated 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. CO 2 

### 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 explorati on and development associated U.S.-sources natural gas supplies was 0.50 lb CO 2 

### e/MMBtu in 2006 and 0.37 lb CO 2 

### e/MMBtu in 2020, though it can range considerably by AEO supply region, as show n 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 CO 2 

### e/MMBtu in 2006 and 0.60 lb CO 2 

### e/MMBtu in 2020. The emissions intensity by supply region in 2020 for LNG is shown in Exhibit 28.

### November 10, 2008

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### Exhibit 25: Comparison of GHG Emissions for Ex ploration and Development for U.S. Natural Gas for 2006 and 2020 (Not Accounting for Natural Gas Star Program Reductions)



### Emission Sources CO 2 

### Emissions (Mg) CH 4 

### 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

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### Exhibit 26: Comparison of GHG Emissions fo r Exploration and Development for LNG Supplies Serving U.S. Markets for 2006 and 2020 (Not Accounting for Natural Gas Star Program Reductions)



### CO 2 

### Emissions (Mg) # 

### CH 4 

### 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: Explora tion and Development Emissions Intensity by AEO Supply Region for 2006 and 2020 Exploration and Development



### Total Emissions (1,000 lbs CO 2 

### e) 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. CO 2 

### e/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

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### Exhibit 28: Explora tion and Development Emissions Intensity for LNG, by Source Country, for 2006 and 2020

Total Emissions (1000 lbs CO 2 

### e) 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. CO 2 

### e/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

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## 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 pr oduction from U.S. supply sources were 116 million tonnes of CO 2 

### e in 2006, decreasing to 105 million tonnes of CO 2 

### e 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 CO 2 

### e in 2006, growing to over 3.4 million tonnes of CO 2 

### e by 2020. In 2006, GHG emissions intensity from U.S. production was 13.10 lb CO 2 

### e/MMBtu as compared to 1.57 lb CO 2 

### e/MMBtu for countries exporting LNG. In 2020, GHG emissions intensity from U.S. production decreases to 11.19 lb CO 2 

### e/MMBtu, while increasing to 2.08 lb CO 2 

### e/MMBtu for countries exporting LNG to the U.S. However, the emissions and emissions intensity can range considerably by supply region. Total U.S. emissi ons 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, v apor recovery or other emissions controlswould 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 CO 2 

### Emissions (Mg) CH 4 

### Emissions (Mg) N 2 

### O 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 CO 2 

### Emissions (Mg) CH 4 

### Emissions (Mg) N 2 

### O 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 St ar Program Reductions)

Total Emissions (1,000 lbs CO 2 

### e)
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. CO 2 

### e/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 St ar Program Reductions)

Total Emissions (1,000 lbs CO 2 

### e)
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. CO 2 

### e/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 proc essing from U.S. supply sources were 59 million tonnes of CO 2 

### e in 2006, increasing to 64 million tonnes of CO 2 

### e 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 CO 2 

### e in 2006, growing to over 13 million tonnes of CO 2 

### e by 2020. Emissions intensity from gas processing was 6.64 lb CO 2 

### e /MMBtu for U.S. natural gas supply and 6.46 lb CO 2 

### e /MMBtu for imported LNG in 2006. Gas processing emissions intensity is projected to increase slightly to 6.80 lb CO 2 

### e /MMBtu for U.S. natural gas supply, while increasing to 8.14 lb CO 2 

### e/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 CO 2 

### 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 CO 2 

### content. Only a relatively small portion of the CO 2 

### produced from planned projects is currently planned to be sequestered. If more of the CO 2 

### 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 CO 2 

### emissions intensity in the Rocky Mountain region, the ICF gas processing model includes consideration of some CO 2 

### capture and injection for EOR operations in the Rockies, which reduced the CO 2 

### that would otherwise be emitted to the atmosphere. Emissi ons 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 de stined 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 summa rized in Exhibit 39 for 2006 and Exhibit 40 for 2020. As discussed above, a number of large LNG pr ojects overseas plan to permanently sequester the CO 2 

### 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 CO 2 

### 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 CO 2 Sequestration Vented CO 2 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 CO 2 

### 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 CO 2 

### otherwise vented from processing gas servi ng LNG exports is sequestered, this impact could be greater. (The same also applies to the CO 2 

### 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)

CO 2 Emission Sources Normal Fugitives Northeast Midcontinent Rocky Mountain Southwest West Coast Gulf Coast Plants - Before CO 2 removal 155 289 351 320 109 519
Plants - After CO 2 removal 37 69 84 77 26 125 Recip. Comp. - Before CO 2 removal 1,138 2,087 2,588 2,057 3,861 6,598 Recip. Comp. After CO 2 removal 274 502 623 495 929 1,587 Cent. Comp. - Before CO 2 removal 333 662 786 660 1,402 2,328 Cent. Comp. - After CO 2 removal 80 159 189 159 337 560 V ented 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 Electricit y Emissions 1,637,251 3,232,273 2,178,476 4,048,208 285,726 5,933,601

Methane Emission Sources

Normal Fu g itives 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
V ented 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

N 2 O Emission Sources
Northeast Midcontinent Rocky Mountain Southwest West Coast Gulf Coast Combusted 6 75 107 106 74 200 CO 2 Emissions (Mg)

CH 4 Emissions (Mg)

N 2 O 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)

CO 2 Emission Sources Normal Fugitives Northeast Midcontinent Rocky Mountain Southwest West Coast Gulf Coast Plants - Before CO 2 removal 181 338 410 374 127 606
Plants - After CO 2 removal 46 86 105 95 32 155 Recip. Comp. - Before CO 2 removal 1,224 2,261 2,794 2,234 4,273 7,267 Recip. Comp. After CO 2 removal 312 576 712 570 1,089 1,853 Cent. Comp. - Before CO 2 removal 363 733 858 727 1,526 2,545 Cent. Comp. - After CO 2 removal 92 187 219 18 5 389 649 V ented 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 Electricit y Emissions 2,028,167 4,004,022 2,699,069 5,014,772 353,947 7,336,273

Methane Emission Sources

Normal Fu g itives 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
V ented 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

N 2 O Emission Sources
Northeast Midcontinent Rocky Mountain Southwest West Coast Gulf Coast Combusted 7 87 124 123 86 232 CH 4 Emissions (Mg)

N 2 O Emissions (Mg) CO 2 Emissions (Mg)

### November 10, 2008

46 

### Exhibit 35: Emissions Intensity for U.S. Natura l Gas Processing by NEMS Supply Region, for 2006

Northeast Midcontinent Rocky Mountain Southwest West Coast Gulf Coast
Fu g itives ( 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

Fu g itives 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. Natura l Gas Processing by NEMS Supply Region, for 2020 (Mg)

Northeast Midcontinent Rocky Mountain Southwest West Coast Gulf Coast
Fu g itives ( 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

Fu g itives 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 Natu ral Gas Processing for U.S. LNG Ma rkets, 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 CO 2 removal 1.95 1.95 1.75 0.78
Plants - After CO 2 removal 0.75 0.75 0.75 0.75 Reciprocating Compressors - Before CO 2 removal 12.22 85.04 36.93 106.22 Reciprocating Compressors - After CO 2 removal 4.69 32.60 15.73 101.81 Centrifugal Compressors - Before CO 2 removal 4.66 32.43 14.08 40.50 Centrifugal Compressors - After CO 2 removal 1.79 12.43 6.00 38.82 V ented 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 Emission s 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 V ented 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 Emission s 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 CO 2 Emissions (Mg)

CH 4 Emissions (Mg)

N 2 O Emissions (Mg)November 10, 200849Exhibit 38: Emissions from Natural Gas Processing for U.S. LNG Markets, by Country of Origin, 2020(Not Accounting for Natural Gas Star Program Reductions)Carbon Dioxide Emission SourcesNormal FugitivesAlgeria Egypt Nigeria TrinidadIndonesia/Papua NewGuineaRussia AustraliaMiddle East/QatarNorwayPlants - Before CO2 removal 4.83 9.65 8.69 3.86 6.03 0.36 8.45 7.24 28.96Plants - After CO2 removal1.85 3.70 3.70 3.70 0.93 0.93 0.93 2.78 2.78Reciprocating Compressors - Before CO2 removal247.00 353.22 427.32 193.54 142.3820.60 300.54 358.17 1,267.40Reciprocating Compressors - After CO2 removal94.70 135.43 182.04 185.51 21.84 52.65 32.92 137.33 121.48Centrifugal Compressors - Before CO2 removal91.69 131.12 158.63 71.85 53.00 7.67 111.87 132.96 471.78Centrifugal Compressors - After CO2 removal35.16 50.27 67.58 68.87 8.13 19.60 12.26 50.98 45.22VentedAGR Vents211,276.45 301,245.68 324,769.11 331,016.58 196,750.75 35,732.86 445,001.83 306,260.66 1,918,884.00Kimray Pumps0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00Dehydrator Vents118.07 168.35 204.18 92.49 68.72 9.98 145.07 171.15 612.78Pneumatic Devices0.54 1.07 0.97 0.43 0.67 0.04 0.94 0.81 3.22Combusted597,147.06 895,205.44 1,155,125.181,173,626.82 120,696.73 274,593.92181,724.30 870,593.13 655,890.04Routine MaintenanceBlowdowns/Venting 12.00 24.00 21.60 9.60 15.00 0.90 21.00 18.00 71.99Indirect Electricity Emissions318,204.93 159,097.07 159,101.73 159,102.08 77,115.14 317,273.05 317,265.05 159,101.83 317,268.11CO2 Emissions Sequestered0 0 0042,7240365,5140495,517Methane Emission SourcesNormal FugitivesAlgeria Egypt Nigeria TrinidadIndonesia/Papua NewGuineaRussia AustraliaMiddle East/QatarNorwayPlants137.70 275.39 275.39275.3968.85 68.85 68.85 206.55 206.55Reciprocating Compressors7,046.23 10,076.31 13,544.5413,802.491,624.70 3,916.97 2,449.54 10,217.53 9,038.73Centrifugal Compressors2,615.71 3,740.54 5,028.035,123.78604.78 1,458.06 911.82 3,792.97 3,364.58VentedAGR Vents85.53 171.05 171.05171.0542.76 42.76 42.76 128.29 128.29Kimray Pumps0.00 0.00 0.000.000.00 0.00 0.00 0.00 0.00Dehydrator Vents1,906.38 2,718.18 3,663.053,733.51443.83 1,074.74 669.22 2,763.43 2,473.48Pneumatic Devices7.86 15.72 15.7215.723.93 3.93 3.93 11.79 11.79Combusted3,609.75 5,411.51 6,982.727,094.57729.61 1,659.92 1,098.52 5,262.73 3,964.85Routine MaintenanceBlowdowns/Venting 193.73 387.46 387.46387.4696.87 96.87 96.87 290.60 290.60Indirect Electricity Emissions2.64 5.28 5.285.280.64 2.63 2.63 3.96 7.90Nitrous Oxide Emission SourcesAlgeria Egypt Nigeria TrinidadIndonesia/Papua NewGuineaRussia AustraliaMiddle East/QatarNorwayCombusted 15.45 23.16 29.88 30.36 3.12 7.10 4.70 22.52 16.97CO2Emissions (Mg)CH4Emissions (Mg)N2O Emissions (Mg)

### November 10, 2008 50 

### Exhibit 39: Emissions Intensity for U.S. Natura l 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)November 10, 200851Exhibit 40: Emissions Intensity for U.S. Natural Gas Processing by LNG Source Country, for 2020AlgeriaEgyptNigeriaTrinidadIndonesia/Papua NewGuineaRussiaAustraliaMiddle East/QatarNorwayFugitives (w/o Gas Star Reductions)CO2211,882 302,123 325,844 331,646 154,343 35,846 80,122307,140 1,425,993CH411,993 17,385 23,085 23,509 2,886 6,662 4,243 17,411 15,514CombustionCO2915,352 1,054,303 1,314,227 1,332,729 197,812 591,867 498,989 1,029,695 973,158CH43,6125,417 6,988 7,100 730 1,663 1,101 5,267 3,973N2015 23 30 30 3 7 5 23 17CO2e Total1,188,121 1,451,646 1,806,073 1,833,166 303,163 701,794 593,678 1,425,998 1,787,586Fugitives (w/ Gas Star)192,120 276,412 335,834 341,928 89,048 72,811 70,107 278,721 725,740Combustion996,001 1,175,234 1,470,239 1,491,238 214,115 628,983523,571 1,147,277 1,061,846Fugitives16% 19% 19% 19% 29% 10% 12% 20% 41%Combustion84% 81% 81% 81% 71% 90% 88% 80% 59%Total Emissions (lb CO2e)2,619,314,6623,200,277,674 3,981,641,944 4,041,371,288 668,348,974 1,547,164,766 1,308,814,425 3,143,734,6953,940,886,628Gas Throughput (MMBtu)425,105,967 607,417,311 817,387,875 833,114,413 98,967,636 233,667,768 149,463,092 627,932,599 544,707,921Emissions Intensity (lbCO2e/MMBtu) 6.16 5.27 4.87 4.85 6.75 6.62 8.76 5.01 7.23(All emissions in Mg unless otherwise indicated)

### November 10, 2008

52 

## Natural Gas Liquefaction and Loading Total GHG emissions from the natural gas lique faction and loading was slightly over 2.5 million tonnes CO 2 

### e 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 CO 2 

### e/MMBtu for imported LNG in 2006 and 10.60 lb CO 2 

### e /MMBtu in 2020. Emissions for both 2006 and 2020 are summarized by country of origin in Exhibit 41.



### Exhibit 41: Natura l 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) CO 2 Emissions (tonnes) CH 4 Emissions (tonnes) N 2 O
Emissions (tonnes) CO 2 e Emissions (tonnes) Natural Gas Delivered to US (BBtu) Emissions Intensity (lb CO 2 e/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) CO 2 Emissions (tonnes) CH 4 Emissions (tonnes) N 2 O
Emissions (tonnes) CO 2 e Emissions (tonnes) Natural Gas Delivered to US (BBtu) Emissions Intensity (lb
CO 2 e/MMBtu) LNG Countr y of Ori g in 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 sh ipping was slightly over 1.6 million tonnes CO 2 

### e 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 CO 2 

### e/MMBtu in 2006 and 5.59 lb CO 2 

### e/MMBtu in 2020 as efficiencies improve, prim arily 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 (m 3 LNG) LNG heel left (m 3 LNG) Amount Unloaded (m 3 LNG) Total Volume Delivered (MMcf gas) # of Trips Emissions (tonnes CO 2 ) Country Specific Emissions Intensity (lbs CO 2 e/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 CO 2 e/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 CO 2 

### e 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 int ensity for regasification operations is estimated to be 1.75 lb CO 2 

### e/MMBtu, growing slightly to 1.80 lb CO 2 

### e/MMBtu in 2020. Total emissions from LNG storage and regasificat ion 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/ y ear ) CO 2 Emissions ( tonnes ) CH 4 Emissions ( tonnes ) N 2 O Emissions ( tonnes ) CO 2 e Emissions ( tonnes ) LNG Imports ( MMcf ) Emissions Intensity (lbs CO 2 e/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

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### Exhibit 45: Emissions from LNG Storage and Regasification in 2020

Region Fuel for Vaporization (MMcf/year) CO 2 Emissions (tonnes) CH4 Emissions (tonnes) N 2 O
Emissions (tonnes) CO 2 e Emissions (tonnes) LNG Imports (MMcf) Emissions Intensity (lbs CO 2 e/MMBtu)

East Coast 21,842.41 1,177,229 23 22 1,184,46 5 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 assum ed 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 CO 2 

### e/MMBtu, while the emissions intensity for the transmission system for U.S natural gas supply was 5.49 lb CO 2 

### e/MMBtu. In 2020, the incremental emissions intensity for imported LNG was estimated to be 0.02 lb CO 2 

### e/MMBtu, while that for the U.S. transmission associated with U.S. natural gas supply was estimated to be 3.82 lb CO 2 

### e/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 ther efore 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 t he 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 CO 2 

### 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.November 10, 200855Exhibit 46: Transmission Sector Emissions by AEO Demand Region for 2006 and 2020AEO Demand RegionCO2(Mg)CH4(Mg) -- w/Natural GasSTAR Adj.CO2e (Mg)GasThroughput(Quads)Intensity (lbCO2e/MMBtu) CO2(Mg)CH4(Mg) -- w/Natural GasSTAR Adj.CO2e (Mg)GasThroughput(Quads)Intensity (lbCO2e/MMBtu)New England430,614 70,291 1,906,721 0.56 7.43 575,930 43,659 1,492,774 0.65 5.05Middle Atlantic1,279,817 239,494 6,309,200 2.56 5.42 1,494,756 132,265 4,272,325 2.56 3.68East North Central2,123,719 379,194 10,086,788 4.57 4.87 2,490,303 220,457 7,119,903 4.87 3.23West North Central718,615 135,163 3,557,047 1.63 4.80 938,040 86,079 2,745,705 1.93 3.14South Atlantic1,170,769 161,463 4,561,487 1.93 5.20 1,470,257 98,382 3,536,270 2.10 3.73East South Central542,620 89,443 2,420,930 1.14 4.67 748,581 50,762 1,814,588 1.14 3.53West South Central2,862,680 322,153 9,627,898 4.46 4.76 3,465,535 201,739 7,702,059 5.14 3.31Mountain941,056 109,536 3,241,313 1.29 5.54 1,109,818 66,559 2,507,559 1.43 3.88Pacific1,715,180 240,710 6,770,081 2.97 5.03 1,903,498 131,069 4,655,937 2.87 3.59CH4(Mg) --No NaturalGas Star Adj.CH4(Mg) --No NaturalGas Star Adj.92,691115,145315,817 348,831500,036 581,425178,237 227,022212,918 259,468117,947 133,878424,817 532,060144,443 175,540317,419 345,675Natural Gas STAR Reductions24.2%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 CO 2 

### e/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 CO 2 

### e/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 CO 2 

### 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) CO 2 ( Mg) CH 4 (Mg)
w/o Natural Gas STAR Reductions CH 4 (Mg) w/
Natural Gas

STAR Reductions Emissions Intensity (2020) (lb CO 2 e/MMBtu) Gas Throughput

(Quads) CO 2 ( Mg) CH 4 (Mg)
w/o Natural Gas STAR Reductions CH 4 (Mg) w/
Natural Gas

STAR Reductions Emissions Intensity (2020) (lb CO 2 e/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 Pacifi c 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 c onsumption 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 CO 2 

### /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.November 10, 200857Exhibit 48: Consumption Emissionsby AEO Demand Region for 2006 (tonnes CO2e)NewEnglandMiddleAtlanticEast NorthCentralWest NorthCentralSouthAtlanticEast SouthCentralWest SouthCentral Mountain Pacific TOTALResidental 9,437,887 42,151,106 66,899,328 20,659,006 21,511,721 9,011,542 15,116,504 17,751,910 35,174,387 237,713,390Commercial 6,270,956 30,483,527 34,490,258 13,896,735 17,999,869 6,812,781 15,851,641 11,767,579 17,632,295 155,205,642Industrial 4,396,990 18,672,643 61,243,898 23,484,123 29,281,303 24,825,027 127,772,014 16,306,858 52,804,610 358,787,466Electric Power Generation 21,202,881 22,692,591 28,669,330 2,746,491 43,069,974 8,831,733 110,070,487 28,896,656 46,229,882 312,410,024Transportation 142,435 318,668 339,540 167,095 407,612 147,685 250,419 165,536 350,248 2,289,237Exhibit 49: Consumption Emissionsby AEO Demand Region for 2020 (tonnes CO2e)NewEnglandMiddleAtlanticEast NorthCentralWest NorthCentralSouthAtlanticEast SouthCentralWest SouthCentral Mountain Pacific TOTALResidental 11,345,211 46,679,477 76,219,032 24,702,768 27,663,991 10,751,627 17,910,068 22,738,949 41,996,824 280,007,947Commercial 8,086,770 35,610,097 42,944,323 17,951,343 27,789,480 9,522,677 20,827,549 15,472,420 20,942,483 199,147,143Industrial 6,626,197 19,996,754 75,072,932 34,328,368 28,268,554 25,013,554 166,298,235 18,716,169 51,414,988 425,735,751Electric Power Generation 29,704,961 31,945,805 31,250,415 4,412,241 56,014,420 25,538,310 126,376,234 32,964,145 43,703,114 381,909,645Transportation 374,513 598,808 611,696 396,351 834,548 372,871 566,694 456,497 729,573 4,941,550

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# 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 sector 26 

### did not have the capability of performing a comparable assessment for the Canadian supply chain.
Moreover, to our knowledge, the only compar able 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 CO 2 

### e/MMBtu. Some insight can also be gained from the Canadian national inventory of GHG emissions. 28 

### This report does look specifically at the emissi ons 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 CO 2 

### e/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. Hu mphreys, “A life cycle analys is of the Canadian natural gas system,” Gasunie Engineering and Technology, paper presented at the 39 th 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 )

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

Emissions (kilotonnes)
CO 2 CH 4 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 m 3 )
CO 2 CH 4 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. CO 2 e/MMBtu)
CO 2 CH 4 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

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### Exhibit 51: Canadian Natural Gas Production, Export, and GHG Emi ssion 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 CO 2 e 13.9 26.5 33.1 33.4 34.6 34.9
Mt CO 2 e/Quad 9,520 9,264 9,059 9,071 9,055 9,035
lb. CO 2 e/MMBtu 20.99 20.42 19.97 20.00 19.96 19.92 Emissions Associated with Net Exports
Mt CO 2 e 12.7 25.1 31.1 25.6 25.9 27.0
Mt CO 2 e/Quad 8,836 8,851 8,651 7,686 7,558 7,700
lb. CO 2 e/MMBtu 19.48 19.51 19.07 16.94 16.66 16.98

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### Exhibit 52: Canadian Natura l 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 c ubic 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 c ubic 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

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### Exhibit 53: U.S. Natural Gas S upply and Import Forecasts by the En ergy 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

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# 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/E nvironmental 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/E nvironmental 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 2 nd 

### document. http://www.snohvit.com/STATOILCOM/snohvit/s vg02699.nsf/Attachments/Utslippssoknad.pdf/$ FILE/Utslippssoknad.pdf http://www.snohvit.com/STATOILCOM/snohvit/s vg02699.nsf/Attachments/konsekvensutredning .pdf/$FILE/konsekvensutredning.pdf

Environmental and Technology Webpage http://www.snohvit.com/STATOILCOM/s nohvit/svg02699.nsf?OpenDatabase&lang=en

Pluto LNG Project (Liquefaction)

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### 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/scienc e?_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