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GREENHOUSE GAS EMISSION ESTIMATIONMETHODOLOGIES, PROCEDURES, AND GUIDEL INES FOR

THE NATURAL GAS DISTRIBUTION SECTOR

Prepared for:

American Gas Association (AGA)10G Street, N.E., Suite 700Washington, D.C. 20002

Prepared by:

innovative environmental solutions, inc.P.O. Box 177

Cary, IL 60013

April 18, 2008

Copyright 2008 American Gas Association. All rights reserved. This work may not be reproduced ortransmitted in any form or by any means, electronic or mechanical, including photocopying, recording orby information storage and retrieval system without permission in writing from the American GasAssociation.


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AGA GHG GuidelinesApril 18, 2008

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TABLE OF CONTENTS

1. Introduction ................................................................................................................................11.1.Purpose and Objective ........................................................................................................11.2.Greenhouse Gases & Global Warming Potentials ..............................................................21.3.Natural Gas Distribution Sector Overview .........................................................................41.4.Considerations for Future GHG Guidelines Updates: Current Programs to Advance the

State-of-the-Art for Distribution Section GHG Emissions Estimates............6

2. Technical Elements ....................................................................................................................72.1.GHG Emissions Estimation Methodologies - Quantification Steps ...................................72.2.Tiered Approaches ..............................................................................................................72.3.Emission Factors .................................................................................................................82.4.Activity Data .....................................................................................................................102.5.Precision and Uncertainty Estimates ................................................................................112.6.Materiality Threshold .......................................................................................................132.7.Direct Emissions ...............................................................................................................14

2.7.1 Combustion Emissions...........................................................................................142.7.2 Vented Emissions...................................................................................................142.7.3 Fugitive Emissions .................................................................................................152.7.4 Mobile Source Emissions ......................................................................................15

2.8.Indirect Emissions ............................................................................................................152.9.Optional Emissions ...........................................................................................................15

3. Combustion Emissions.............................................................................................................163.1.Emission Estimation Methodologies Overview ...............................................................16

3.1.1 Emission Tiers for Combustion .............................................................................173.1.2 Data Conventions ...................................................................................................183.1.3 Emission Factor Selection Criteria ........................................................................19

3.2.Stationary Source CO2 Emission Estimation Methodologies ...........................................203.2.1 CO2 Emission Estimates Using Tier 1 Emission Factors ......................................233.2.2 CO2 Emission Estimates Using Tier 2 Emission Factors ......................................233.2.3 CO2 Emissions Estimates Determined from Fuel Consumption & Composition..24

3.3.Stationary Source CH4 and N2O Emission Estimation Methodologies ............................263.3.1 CH4 and N2O Emission Estimates Using Tier 1 Emission Factors .......................293.3.2 CH4 and N2O Emission Estimates Using Tier 2 Emission Factors .......................293.3.3 CH4 and N2O Emission Estimates Using Tier 3 Emission Factors .......................303.3.4 CH4 and N2O Emissions Estimates Tier 3+ ........................................................34

4. Vented Emissions ....................................................................................................................364.1.Calculation Methods and Conversion Factors ..................................................................364.2.Emissions Estimation Methods ........................................................................................36

4.2.1 Tier 3 Emissions Estimates ....................................................................................394.2.2 Tier 2 Emissions Estimates ....................................................................................424.2.3 Tier 1 Emissions Estimates ....................................................................................424.2.4 Event-Based and Equipment Specific Venting Emissions Estimates from

Engineering Data (Tier 3+) ....................................................................................43


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TABLE OF CONTENTS (continued)

4.3.Example Calculations for Vented Emissions ...................................................................454.3.1 Tier 1: Vented Emissions Calculation ...................................................................454.3.2 Tier 2 Vented Emissions Calculation ....................................................................464.3.3 Tier 3 Vented Emissions Calculation ....................................................................474.3.4 GHG Vented Emissions Estimate Example Conclusions ......................................47

5. Fugitive Emissions ...................................................................................................................495.1.Background on Fugitive Emission Sources and GHG Estimation ...................................505.2.Emission Estimation Methods ..........................................................................................51

5.2.1 Tier 3 Emissions Estimates ....................................................................................545.2.2 Tier 2 Emissions Estimates ....................................................................................575.2.3 Tier 3 Emissions Estimates ....................................................................................595.2.4 Tier 3+ Facility-Specific Estimates Screening-based Methodologies ................605.2.5 Other Tier 3+ Emission Estimation Approaches ...................................................62

5.3.Example Calculations for Fugitive Emissions ..................................................................645.3.1 Tier 1 Fugitive Emissions Calculation ...................................................................645.3.2 Tier 2 Fugitive Emissions Calculation ...................................................................655.3.3 Tier 3 Fugitive Emissions Calculation ...................................................................665.3.4 GHG Fugitives Emissions Estimate Example Conclusions...................................67

6. Mobile Source Emissions ........................................................................................................696.1.Mobile Sources and Fleet Vehicles ..................................................................................69

6.1.1 Automobiles, Trucks, and Motorcycles ................................................................696.1.2 Construction Equipment ........................................................................................71

7. Indirect Emissions ....................................................................................................................727.1.Indirect Emissions from Purchased Electricity.................................................................727.2.Methods for Calculating Indirect Emissions from Purchased Electricity ........................72

APPENDICES

APPENDIX A:A-1. Website ReferencesA-2. References

APPENDIX B: Unit Conversions

APPENDIX C: Support Information for Combustion EmissionsC-1. Energy Output to Input Conversions for Prime MoversC-2. Fuel Composition Conversions: Mole Percentage, Weight Percentage, Carbon Mole

Percentage, and Carbon Weight PercentageC-3. AP-42 Emission Factor Quality RatingsC-4. Gasoline and Diesel Vehicles Emissions Controls

APPENDIX D: Acronyms

APPENDIX E: Historical GHG Emissions Information for the Natural Gas Distribution Sector

APPENDIX F: Example GHG Calculations for Fictional Distribution Company andObservations on Inventory Development and Emission Factor Improvement


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LIST OF TABLES

Table 1-1. Global Warming Potentials (100 Year Time Horizon, IPCC 1995) ..............................3

Table 1-2. GWP (100-year) for CO2, Methane, and N2O from 1995 SAR and 2001 TAR ............3

Table 3-1. Densities, Heating Values, and Carbon Content for Select Liquid and GaseousFuels .............................................................................................................................19

Table 3-2. Tier 1 CO2 Emission Factors for Combustion ............................................................23

Table 3-3. Tier 2 CO2 Emission Factors for Combustion ............................................................24

Table 3-4. Fractional Carbon Oxidation Factors ...........................................................................25

Table 3-5. Tier 1 CH4 and N2O Emission Factors for Combustion .............................................29

Table 3-6. Tier 2 CH4 and N2O Emission Factors for Combustion .............................................30

Table 3-7. Tier 3 CH4 Emission Factors for Combustion ............................................................32

Table 3-8. Tier 3 N2O Emission Factors for Combustion ........................................................... 33

Table 3-9. Selected Tier 4 GHG Emission Factors for Waukesha ICEs Combustion ..................35

Table 4-1. Distribution Sector Vented Emissions Sources and Activity Data. .............................37

Table 4-2. Distribution Sector Tier 3 Emission Sources for Vented Emissions ...........................39

Table 4-3. Distribution Sector Tier 2 Emission Factors for Vented Emissions . ..........................42

Table 4-4. Distribution Sector Tier 1 Emission Factor for Vented Emissions..............................42

Table 4-5. ADC Tier 1 Vented Activity Data and GHG Emissions Calculations .......................46

Table 4-6. ADC Tier 1 Vented GHG Emissions Estimate for 2005 .............................................46


Table 4-8. ADC Tier 2 Vented CO2eq Emissions Estimate for 2005 ..........................................46


Table 4-10. ADC Tier 3 Vented CO2eq Emissions Estimate for 2005 ...........................................47

Table 4-11. Vented Emissions Estimate Example Summary for ADC in 2005..............................48

Table 5-1. Typical Fugitive Emissions Sources Associated with the Distribution Sector ...........51

Table 5-2. Distribution Sector Fugitive Emissions Sources and Activity Data ............................53

Table 5-3. Distribution Sector Tier 3 Emission Factors for Fugitive Emissions ..........................55

Table 5-4. Tier 3 Emission Factors for Distribution M&R and Pressure Regulating Stations

Fugitive Emissions .......................................................................................................55


Table 5-6. Comparison of 1996 and 2005 US Distribution System Main Pipelines ....................58


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LIST OF TABL ES (continued)

Table 5-7. Comparison of 1996 and 2005 US Distribution System Service Pipelines .................59


Table 5-9. ADC Tier 1 Activity Data and GHG Calculations .....................................................65

Table 5-10. ADC Tier 1 GHG Emissions Estimate for 2005. .........................................................65

Table 5-11. ADC Tier 2 Activity Data and GHG Calculations. .....................................................65

Table 5-12. ADC Tier 2 Fugitive CO2eq Emissions Estimate for 2005 .........................................66

Table 5-13. ADC Tier 3 Activity Data and GHG Calculations ......................................................66

Table 5-14. ADC Tier 3 Estimate CO2eq Emissions for 2005. .......................................................67

Table 6-1. Mobile Source Highway Vehicles GHG Emission Factors .........................................70

Table 6-2. Mobile Source Construction Equipment GHG Emission Factors ...............................71

Table 6-3. Fuel Properties Used for Vehicle Emission Factor Conversion to Tonnes .................71

Table 7-1. Tier 1 National-Level Emission Factors for Purchased Electricity .............................73

Table 7-2. U.S. State-Level Emission Factors for Purchased Electricity ......................................74

Table 7-3. Canadian Province-Level Emission Factors for Purchased Electricity .......................75

Table 7-4. GHG Emission Factors Based on Generation Source ..................................................76

LIST OF FIGURES

Figure 1-1 Natural gas industry sector diagram ..............................................................................5

Figure 1-2 City Gate M&R station schematic .................................................................................5

Figure 3-1 CO2 emissions estimation overview ............................................................................21

Figure 3-2 CO2 emissions estimation fuel consumption determination ........................................22

Figure 3-3 ICE/Turbine CH4 and N2O emissions estimation overview ........................................26

Figure 3-4 CH4 and N2O combustion emissions estimation overview ..........................................27

Figure 5-1 Leak rate versus concentration and correlation equation estimate ..............................60

Figure 5-2 Methods for deriving component counts .....................................................................62


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ACKNOWLEDGEMENTS

The development of this guideline document has been sponsored by members of the

American Gas Association (AGA). The support and direction provided by AGA and the membercompanies involved is gratefully acknowledged. Special thanks are given to Christina Sames fromAGA and the members of the AGA Greenhouse Gas Task Group for review, comment, andtechnical direction on this document.


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1.0 Introduction

1.1 Purpose and Objective

This document presents the American Gas Association (AGA) Greenhouse Gas (GHG) Emissions

Estimation Guidelines for Natural Gas Distribution (GHG Guidelines). This guideline documentpresents a detailed compilation of the select methods for estimating carbon dioxide, methane, andnitrous oxide emissions from combustion and non-combustion sources for the natural gas industrydistribution sector. These guidelines are intended to be a living document and are designed as adetailed reference for developing a GHG inventory for use by both practitioners and inventorymanagers. The GHG Guidelines:

Identify and describe the different GHG emissions source types in the distribution sector; Where possible, identify the most appropriate emission factors and activity data for the

emissions sources;

Provide practical information for designing an overall GHG emissions assessment strategythat considers a company's particular needs and circumstances; and

Establish a consistent framework for estimating GHG emissions for the natural gasdistribution sector to facilitate inter-company comparisons and ease data aggregation forfuture industry reporting initiatives.

To inform the reader and enhance understanding of the GHG Guidelines, Appendix F providesexample inventory calculations for a fictitious distribution company. The focus of Appendix F isto illustrate emission calculations for typical source types. This appendix also includesdiscussion on inventory objectives, data gathering challenges, emission estimate uncertainty, andcurrent emission factor improvement efforts for the distribution sector.

In this document, sections 1 and 2 present general information concerning GHG emissions, anemission-source classification scheme, and general procedures for designing and implementing aGHG emissions inventory. Sections 3 through 6 present the emission factors and emissionestimation methods for the primary source types in the natural gas industry distribution sector.The source types include:

Fugitive emissions from equipment and piping leaks; Natural gas venting; Stationary combustion sources; Indirect sources; and Mobile sources.Reporting programs such as the California Climate Action Registry and U.S. Department ofEnergy (DOE) 1605b program consider the same emission sources and use similar, but slightlydifferent terminology. For example, the DOE 1605b program uses the terms stationarycombustion, fugitives, process (e.g., venting), mobile combustion, and indirect emissions.


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Following the body of the report, references cited are listed in Appendix A. Several primaryreferences are consistently used throughout this document, and the complete citations for theseprimary references are included in Appendix A, as well as other references used to prepare theGHG Guidelines. Common units and conversions for GHG calculations are provided inAppendix B. Support information related to combustion emissions is included in Appendix C

and a list of acronyms is provided in Appendix D. Appendix E includes estimated historicalGHG losses and associated costs for the distribution sector.

1.2 Greenhouse Gases & Global Warming Potentials

The greenhouse effect is the phenomenon where atmospheric gases absorb and trap theterrestrial radiation leaving the Earths surface thus causing a warming effect on earth. Thegreenhouse effect is primarily from carbon dioxide (CO2) and water vapor, along with other tracegases in the atmosphere. For emissions purposes, a number of gases are typically considered tobe GHGs, including CO2, methane (CH4), nitrous oxide (N2O), hydro fluorocarbons, perfluorocarbons (e.g., CnF2n+2 compounds), and sulfur hexafluoride (SF6). For emissions from oil

and natural gas systems, CO2, methane, and nitrous oxide are the gases of interest and the focusof this document. Methane and CO2 account for the vast majority of GHG emissions for naturalgas systems. While included herein, N2O comprises a very small percentage of distributionsystem GHG emissions, and emission factors and associated data are very limited. Currently,registries and voluntary reporting programs typically focus initially on reporting CO2 emissions,while encouraging or planning to eventually include other gases. For example, the CaliforniaClimate Action Registry requires that for the first three years Registry participants must report ata minimum their CO2 emissions in CA or in the U.S., depending on the geographic scope of theirinventory. Starting with the fourth year, participants must report the six GHGs included in theKyoto Protocol GHGs (CO2, CH4, N2O, hydrofluorocarbons (HFCs), perfluorocarbons (PFCs),and sulfur hexafluoride (SF6)).

Changes in the atmospheric concentration of GHGs may affect the energy balance between theland, the seas, the atmosphere, and space. A measure of such changes in the energy available tothe system caused by a gas is termed radiative forcing, and, holding everything else constant,atmospheric increase of a GHG produces positive radiative forcing. GHGs can contribute to thegreenhouse effect both directly and indirectly. A direct contribution is from a gas that is itself agreenhouse gas. Indirect radiative forcing occurs when the original gas undergoes chemicaltransformations in the atmosphere to produce other greenhouse gases, when a gas influences theatmospheric lifetimes of other gases, and/or when a gas affects processes that alter theatmospheric radiative balance of the earth. A relative scaling factor has been developed so thatdifferent gases can be reported in a common format.

Global Warming Potential (GWP) is the index that has been developed to compare different GHGson a common reporting basis. CO2 is used as the reference gas to compare the ability of aparticular gas to trap atmospheric heat relative to CO2. The Intergovernmental Panel on ClimateChange (IPCC) defines GWP as the ratio of the time-integrated radiative forcing from theinstantaneous release of 1 kg of a substance relative to 1 kg of the reference gas (i.e., GWP isweight-based, not volume-based). Thus, GHG emissions are commonly reported as CO2equivalents (e.g., tonnes of CO2eq, where a tonne is 1000 kg). As noted above, the GWP is a time-integrated factor; thus the GWP for a particular gas depends upon the time period selected. A 100-


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year GWP is the standard that has been broadly adopted for GHG reporting, and will serve as thebasis for the AGA GHG Guidelines. GWP values are listed in Table 1-1 for the three GHGsreported for natural gas systems along with some common hydro fluorocarbons and perfluorocarbons, and sulfur hexafluoride.

The GWPs in Table 1-1 are from the IPCC 1995 Second Assessment Report (SAR) [IPCC1995]. In 2001, the IPCC Third Assessment Report (TAR) was adopted [IPCC 2001]. The TARupdated the GWPs based on the most recent scientific data. This update included a revision tothe radiative forcing effect of CO2. Since CO2 is the reference gas, other GWPs were affected bythis change. Additional data and information based on a specific GHG could also affect itsGWP. The SAR and TAR GWPs for CO2, methane, and N2O are presented in Table 1-2.

Table 1-1. Global Warming Potentials(100 Year Time Horizon, IPCC 1995)

Greenhouse Gas GWP

Carbon Dioxide 1

Methane 21

Nitrous Oxide 310

HFC-23 11,700

HFC-32 650

HFC-125 2,800

HFC-134a 1,300

HFC-143a 3,800

HFC-236fa 6,300CF4 6,500

C2F6 9,200

C4F10 7,000

C6F14 7,400

SF6 23,900

Table 1-2. GWP (100-year) for CO2, Methane, and N2O from 1995 SAR and 2001 TAR

Greenhouse Gas GWP (SAR) GWP (TAR)

Carbon Dioxide 1 1

Methane 21 23

Nitrous Oxide 310 296

The updated (TAR) GWPs have not been commonly applied in inventories and reportingprotocols to date, and international convention and typical U.S. voluntary programs rely on the


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SAR values for GHG reporting. The DOE 1605b program is one example that uses the updatedTAR values. For the purposes of this document, the GWPs from the original 1995 SAR will beused. If the reporting convention changes, this can be readily addressed in an inventory byupdating the methane and N2O GWP conversion factors.

Regarding the contribution of gases considered for natural gas systems, carbon dioxide is a directemission from combustion sources, and from natural gas leaks because a small fraction of naturalgas is CO2. Carbon dioxide also results from the soil oxidation of methane from undergroundpipe leaks. An inventory may also include indirect CO2 emissions, from fuel combustion togenerate electricity used by the company The primary challenge in developing a GHGinventory for the natural gas distribution sector is estimating methane emissions, which areespecially important due to the methane GWP and the fact that natural gas is primarily composedof methane (i.e., typically 90% (by volume) or higher for distribution systems).

Carbon dioxide is the principal contributor to human-induced atmospheric effects. The IPCC TARindicates that CO2 currently accounts for 55 percent of the atmospheric radiative forcing attributed

to GHGs. Gases other than CO2 are currently responsible for 45 percent of GHG radiative forcing,and the relative contribution of these other gases is expected to increase in the future.

The indirect CO2 produced by the oxidation of non methane volatile organic compounds(NMVOC) in the atmosphere has not been included in many estimation methodologies and is notcontained within this document. If reporting related to NMVOCs advances, this can beaddressed in future updates to the AGA GHG Guidelines. NMVOCs represent a very smallportion of the natural gas distribution sector emissions. In addition, NMVOCs do not represent asingle molecular species, but are a wide range of volatile hydrocarbon species with varyingmolecular weights and carbon contents. Therefore, an accurate estimate of indirect emissions ofCO2 from atmospheric NMVOC oxidation requires a gas stream chemical speciation profile. Thelatest IPCC documentation seeks to include other hydrocarbon emissions by accounting for thecarbon content by species profile (percent carbon in NMVOC by mass) multiplied by the carbondioxide to carbon molecular weight ratio.

1.3 Natural Gas Distribution Sector OverviewFigure 1-1 shows the four primary sectors for the natural gas industry production, processing,transmission and storage, and distribution. The distribution sector receives, from transmissionpipelines, processed natural gas that has a high methane content, low heavier hydrocarbonsconcentrations, and very low levels of impurities. Custody transfer from the transmissioncompany to the distribution company typically occurs at a City Gate metering and regulating(M&R) station shown schematically in Figure 1-2. The M&R station measures the natural gasflow rate and reduces the gas pressure. Heaters are often employed at M&R stations tocompensate for temperature decreases caused by pressure reductions. In addition, methylmercaptans are typically added to the gas as an odorant at the M&R station so that downstreamgas leaks are more readily detected due to the pungent smell. The gas then flows through aseries of pipeline mains, additional M&R stations and pressure regulating stations, and finallylower pressure service pipelines that connect the mains to industrial, commercial, and residentialcustomers. Customers gas use is measured by individual customer meters.


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Figure 1-1. Natural gas industry sector diagram.

Figure 1-2. City Gate M&R station schematic.

Production ProcessingTransmission/

StorageDistribution

M

Surface Facilities Gas Plant

Pipelines

UndergroundStorage

Reservoir

CompressorStations

Liquids

Liquids

Gas

Pipelines

Storage

Direct

Sales M&R

Stations

Main and

Service Pipelines

Customer

Meters

Compressor

Meter

PressureRegulator

C

C

C

C

Production ProcessingTransmission/

StorageDistribution

M

Surface Facilities Gas Plant

Pipelines

UndergroundStorage

Reservoir

CompressorStations

Liquids

Liquids

Gas

Pipelines

Storage

Direct

Sales M&R

Stations

Main and

Service Pipelines

Customer

Meters

Compressor

Meter

PressureRegulator

C

C

C

C


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1.4 Considerations for Future GHG Guidelines Updates: Current Programs to Advance theState-of-the-Art for Distribution Section GHG Emissions Estimates

As discussed in the following sections, the distribution sector greenhouse gas emissions sources

are categorized based on the Gas Research (GRI) GHGCalc program and include emissionsources from the City Gate M&R stations to the customer meters. The GHG Guidelines do notconsider liquefied natural gas (LNG) systems and associated equipment such as vaporizers.LNG operations have typically been associated with natural gas transmission and storagesystems. The U.S. Environmental Protection Agency (EPA), in conjunction with industryassociations (i.e. AGA, American Petroleum Institute, Interstate Natural Gas Association ofAmerica), is currently planning a program to develop emission characterization procedures forLNG operations. These procedures could be incorporated into future versions of the AGA GHGGuidelines for use by distribution companies with operational control over LNG systems.

Another consideration for future GHG Guidelines versions is the relevance of literature emission

factors to current distribution sector operations and equipment i.e., issues with the currentstate of the art for GHG estimates from distribution systems. In general, the primary referencefor GHG emission factors from the distribution sector is a 1996 GRI/EPA study titled MethaneEmissions from the Natural Gas Industry [GRI/EPA 1996]. This study is dated and may nolonger be representative of standard distribution sector practices, operations, or industryaverages. In addition, based on emission factor groupings, very limited data for some emissionfactors and data assimilation into the factors, the estimated methane losses from this sector arebelieved to be significantly overestimated. A separate project is currently evaluating andprioritizing emission sources and factors for distribution and is expected to culminate in 2008 inimproved emission factors with reduced uncertainty for key distribution sector GHG sources.

As the GHG inventory process continues to grow and mature, documentation to supportassumptions & preferred methodologies, data sources, quality assurance and quality controlpractices, audit procedures and requirements, emission trading elements, and policy and issueconsiderations are likely to become more standardized. A standardized process will enhanceconsistency, comparability, and conformance of future inventories for this sector. Review andupdates to this guideline consistent with industry practices and standards should be conductedconsistent with this programmatic evolution.


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2.0 Technical Elements

2.1 GHG Emissions Estimation Methodologies Quantification Steps

Most GHG emission estimates for inventory development are based on an emission factor

approach, as follows:Emission Rate = Emission Factor (EF) x Activity Data (AD)

Depending upon the tier for the estimate, the activity data can be quite general (e.g., miles ofmain pipeline, number of M&R stations), or more specific (e.g., number of plastic pipelineservices, number of gas-driven pneumatic control loops in an M&R station). Some emissionsestimates may be based on engineering data and/or a mass balance approach. These approachesare typically more accurate than an emission factor approach, but usually require a level of effortand cost that exceeds current accepted practices. These approaches can be used at the operatorsdiscretion, but should not be considered a required or recommended approach. For example,vented gas volumes can be measured or accurately estimated based on equipment and process

parameters. Select examples of these more advanced approaches are discussed in Sections 3 and 4.

In the Sections 3 through 6, emission factors and associated activity data are provided for thevarious distribution sector emission sources. Practitioners and inventory managers will need toidentify the methodology appropriate to meet their inventory objectives considering theavailability of activity data and information for engineering estimates. Emission rates are thendetermined for the array of sources and breadth of facilities that comprise the complete inventory.

To report a complete company inventory, emission estimates from individual processes,equipment, and facilities must be aggregated. A company will need to decide theimplementation approach for preparing a rolled up inventory, and define responsibilities for

compiling and inputting activity data, documenting the data sources and assumptions, calculatingemissions, and rolling the equipment and facility-level emissions up into a corporate report.

Each company should determine whether the emission calculations are to be completed at thefacility-level (i.e., a decentralized approach) or corporate-level (centralized approach). Ifcompany-wide activity data cannot be collected at a corporate level, data from individualbusiness units, operating units, facilities, and field locations may be required to populate theactivity data input fields. In such a case, a common input template should be developed toensure consistency. Either is acceptable and proper quality control of input data and emissionaggregations should be instituted in either case.

In addition, a plan should be developed for recordkeeping and supporting documentation for boththe activity data and assumptions and methodologies relied upon in the current year inventory.These data and documentation will facilitate future audits and ensure continuity if staff change.

2.2 Tiered Approaches

As methods for GHG inventory development continue to evolve, a tiered emission calculationapproach has been commonly applied based on varying levels of detail associated with user input


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data on equipment and processes. Higher tier emission estimates require more detailed activitydata and generate emission estimates with better accuracy and precision. Tier 1 represents themost broad emissions estimate and requires the least input information. Tier 2 and Tier 3 requireprogressively more data, but result in a higher quality GHG inventory and typically a lessconservative estimate. The Tier rating scheme is not an absolute indicator of the fidelity of an

estimate, but rather an indicator of an improved (and less conservative) estimate within anindividual source category for a specific GHG. Emission factors provided in Tiers 1 through 3are general/average factors, with higher accuracy achieved as the input data becomes moredetailed. The Tier-based hierarchy can be described as follows:

Tier 1: General estimate with minimal inputs required (e.g., emission factor based on milesof pipeline used to estimate the GHG inventory).

Tier 2: Data requirements and emission factors based on facility level data or the largestemission sources at a site.

Tier 3: Data requirements and emissions based on process operation or equipment levelinformation at a site.

Additional Tiers (e.g., Tier 3+, Tier 4, and beyond) involve emission determinations thatrequire additional data and higher costs for inventory development. Migration beyond Tier3 estimates will occur over time as improvements in measurements and estimate accuracyprogresses. These estimates will require detailed process and equipment input data inconjunction with site-specific emission factor data. These approaches are usually beyond thecurrent practices for inventory development and are typically founded on equipment-specificmeasurements rather than more generic source-type emission factors. The approaches alsorequire thorough documentation to ensure that an external reviewer/auditor can understandand validate the estimation.

In developing an emission estimate, the user must consider the intended use of the estimate and

inventory, along with the availability and cost associated with collecting the necessary processinputs to complete a calculation. In general, Tier 1 estimates are very qualitative and have littlepractical application in development of a comprehensive GHG inventory. They are onlyintended for a relative magnitude estimate (e.g. national inventories prepared by third parties inthe absence of activity data) and are not considered robust estimates. Tier 2 estimates also arenot considered to be robust estimates, but rather indicators. In summary, Tier 1 and 2 offer thelowest fidelity estimates with the largest uncertainties, and in most cases provide moreconservative estimates than inventories developed using Tier 3 or higher emission estimations;thus, Tier 1 and 2 estimates should only be used in the absence of alternative, higher fidelity,estimation techniques.

2.3 Emission Factors

Emissions factors present the mass of GHG emissions (carbon dioxide, methane, or nitrousoxide) per unit of activity data, where the activity data are typically a process rate or equipmentcount (e.g. lb of CO2 per MMBtu of natural gas combusted, kg of methane leaked per mile ofcast iron main pipeline.) The emission factors presented in Sections 3 through 6 are acompilation of the most current factors in the literature. The emission factors review wasconducted in a recent joint Interstate Natural Gas Association of America (INGAA), American


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Petroleum Institute (API), and AGA study [INGAA/API/AGA 2005]. The primary projectobjectives were to:

1. Identify and compare current published GHG emission factors for natural gas systems;

2. Where possible, identify the emission estimate approaches that can most benefit from animproved methodology or factor, or reduction in emission factor uncertainty;

3. Identify data gaps that currently exist for natural gas systems; and

4. Determine the reliance of published emission factors on data from the mid-1990s data(e.g., EPA/GRI 1996) and the prevalence and quality of newer data.

The project

t reviewed and categorized approximately 1,700 emission factors from 25 documents. Thesedocuments in turn referenced over 60 other publications. Emission factors for natural gassystems were compiled and compared for like/common sources to determine, if possible, thebasis for any differences and to recommend preferred emission factors and identify situationswhere use of alternative factors may be appropriate. Emission factor alternatives were found to

be more abundant for combustion than for the other emission categories characteristic of gasdistribution because combustion sources are common to a wide range of industries andapplications. Published data and emission factors for vented and fugitive emission sourcesspecific to the natural gas industry distribution sector were limited to the 1996 EPA/GRI Studyand similar vintage Canadian studies; thus, as noted above, all the vented and fugitive emissionfactors in sections 4 and 5 may not be representative of current operations and equipment.

The emission factors present a typical or average emission rate based on the industry norm.These are often referred to as default emission factors. The uncertainty associated with thefactor depends upon both the application and the technical limitations associated with the datasetthat forms the basis of the factor. The uncertainty also depends on the accuracy of the

measurement methods associated with the emissions and activity data. For example, combustionCO2 emission factors have a relatively high accuracy due to the relative simplicity and directactivity data basis for combustion CO2 emissions determination, while fugitive methaneemissions have a higher uncertainty due to the complexity of directly measuring fugitiveemissions and relating to an appropriate activity data basis. In these cases, combustion emissionscan be related directly to more precise data such as facility or equipment fuel use, while fugitiveemission factors are presented relative to typical types of equipment in terms of emissions perequipment count.

The GHG Guidelines are not intended to limit the ability of a company to use emission factors oremission estimation methods alternative to those included in this document. A particular

company or site may have actual emissions that vary from the norm represented by theemission factor. If circumstances indicate an issue with available emission factors (or estimationmethod) for a particular application, the company can choose to use an alternative to thepublished emission factors such as site-specific data. In this circumstance, the inventoryshould document the estimate basis and include a qualitative assessment that explains therationale for using an alternative to the default emission factors.


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2.4 Activity Data

The level of effort required for a company to compile an inventory will be most significantlyaffected by the desired estimate fidelity and quality and the availability of activity data

associated with company processes and equipment. Multiple estimation methods are providedfor all processes in the GHG Guidelines. For example, multiple tiers are available, and someprocesses provide more than one estimation methodology for a Tier 2 or Tier 3 estimate. Basedon available activity data and the data quality, a company can decide which estimationapproach most effectively meets its needs.

Regardless of the tier or estimation method selected, a certain amount of source and activity datamust be collected to support inventory development. Activity data compilation may be aidedthrough the creative use of company resources and information such as asset management tools,insurance records, safety audits, purchase records (labor and materials), permits, etc. A reliableand efficient means of developing accurate facility equipment counts, pipeline length and

material, throughput, operating hours, etc. should be developed and memorialized to ensureconsistency in year-to-year inventory management.

Data collection concerns include inventory completeness, accuracy (i.e., eliminate doublecounting and transcription errors), emission factor and activity data matching, anddocumentation and recordkeeping. This generally requires the active engagement of personnelwith a good working knowledge of the equipment and facilities involved, and of the associatedoperations and engineering terminology.

Examples of supporting data and information that may be used for activity data include:

Process operating conditions (e.g., gas compositions, temperatures, pressures and flows); Maintenance records; Supply medium used for gas-operated pneumatic devices (e.g. natural gas versus compressed

air);

Piping materials and age; Nominal pipeline size and/or site rating; Operating and maintenance practices and schedules (e.g., pipeline depressurization for

maintenance); and

Annual updates of equipment and pipelines installed and decommissioned.The specific activity data for the distribution sector GHG estimates are identified in the sectionsthat follow. In compiling activity data for inventory development, a company should considernot only the current inventory (e.g., the initial inventory), but also the procedures that arenecessary to ensure efficient collection of the same data in subsequent years. In developinginitial inventories, activity data deficiencies or gaps should be identified so that processimprovements can be considered for subsequent or updated inventories.


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2.5 Precision and Uncertainty Estimates

Uncertainty estimates and confidence intervals exist for most emission factors and activity data,and the overall uncertainty associated with the majority of emission inventories is typically quite

large. This is largely due to uncertainty being introduced throughout each step in the estimationprocess, including:

Inherent uncertainties of the selected estimation techniques and (default) emission factor; Missing or incomplete information regarding the source population and activity levels; Measurement errors; Poor understanding of the cause of temporal and seasonal variations in the sources; Data entry and calculation errors; Uncertainty in the emission factor;

Uncertainty in representativeness of the source relative to the emission sources used todevelop the emission factor; and

Uncertainty in the GWP (based on IPCC (2001), uncertainty for GWP values with a 100 yearbasis is 35% on a global average basis).

The first two items are likely to be the greatest sources of error, although all are potentiallynoteworthy.

Within the GHG literature, some emission factor tables present "precision" values, which are notreported in this document. Typically, the precision reported is a statistical evaluation from thedataset used to derive the emission factor (usually based on a 90% confidence interval). This

reported number does not indicate the dataset size or reflect additional uncertainties in theemissions factor associated with:

Error in the measurement (e.g. meter accuracy); Representativeness of the dataset relative to the "average" source, or characterization relative

to a companys similar source; and

GWP uncertainty.In addition, this uncertainty is only associated with the emission factor and does not consideractivity data uncertainty. In general, default emission factors for key natural gas industry sources(vented and fugitive emissions) are relatively imprecise and attempts to characterize estimate

accuracy is difficult due to the paucity of data behind most of the initial emission factorsavailable in the literature. As GHG programs mature and additional data is available, the abilityto include uncertainty estimates will progress, and at some future point in time uncertaintyestimates are likely to become a standardized component of the inventory process. However, thecurrent immaturity of GHG emissions reporting does not warrant such consideration.

The API Compendium [API 2004] (see Appendix B.4 of that document) provides a discussionon calculating precision values associated with emission factors and also discusses the


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uncertainties associated with activity factors. Readers are referred to that document for specificequations and derivations of precision calculations.

The 1996 GRI/EPA Study remains the cornerstone for U.S. natural gas industry methaneemissions quantification. Therefore, most of the information regarding problematic sources,

emissions data, and emission factors has no equal in published reports. However, the purpose ofthe GRI/EPA Study was identification of sources and quantification of U.S. national methaneemissions. These data were not intended to be used to develop default emission factors orindustry averages for the gas industry. This issue is similar to the concept of applying an EPAAP-42 emission factor for NOx to a piece of equipment such as an internal combustion (IC)engine. Typically a company would not consider using the AP-42 emission factor for a NOxemission limit because of the factors average nature, and the potential for the generic emissionfactor to not be representative of the specific equipment of interest.

However, this does not imply that precision or uncertainty should not be considered. Indeveloping emission estimates, operators should attempt to characterize the accuracy or precision

associated with the company's activity data (e.g., measured fuel flow, make and model ofequipment) even if only qualitative estimates are available. GHG inventory development isstill a relatively new field of endeavor, and estimation of emission factor precision or uncertaintywill mature as datasets grow. Thus, while uncertainty estimates have limited utility for thecurrent state of the science for GHG estimation, this will become a fundamental part of GHGdevelopment and reporting in the future. Currently, where available, the activity data precisioncan be identified and documented during inventory compilation. This will ensure that acompanys documentation is complete, and this precision value will likely be important infuture-year inventories when it can be used with improved emission factor precision statisticsto characterize an estimate uncertainty.

The following should be considered when assessing the origins of emission estimate uncertainty:

Identifying the various uncertainty sources (i.e., inputs to the emissions estimate); Published precision values may contain a subjectivecomponent (e.g., precision in a default

emission factor may reflect an attempt to address whether the dataset is representative of theat-large source category based on a qualitative judgment);

Two types of error in uncertainty estimation can be considered:1. Bias, introduced from:

Use of factors that are poorly researched and uncertain (e.g. CH4 and N2O fromcombustion);

Use of average factors not well matched to specific and varied operations (e.g. CO 2per kWh generated);

Deliberate estimation or interpolation to compensate for missing data; and Assumptions that simplify highly complex and variable processes.

2. Imprecision, introduced from: Calculation errors and omissions;


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Insufficient frequency of measurements to account for natural variability; and Imprecise measurement of activity data (e.g. mile of pipeline, line size, hours of

operation, etc.).

Error propagation; and Inventory credibility (design, implementation, and verification issues).The relative contribution of a particular source type and the uncertainty associated with emissionestimates are both important factors to consider when developing a strategy for inventoryimprovement. In general, the procedures documented in this guideline document represent arange of simple (or first-order) thought on best-available measurement and estimation techniques,and implications regarding accuracy or uncertainty of the estimate associated with a methodology.

2.6 Materiality Threshold

The concept of materiality considers the point at which a discrepancy due to an error or

reporting of minimal emission source becomes material to the total inventory i.e., themateriality threshold. This document does not present a position regarding appropriate

thresholds, but rather introduces the concept, which is an important component of inventory

development and specifically defined by some registries.

The intent of a materiality threshold is to identify the level at which information inclusion or

exclusion influences decisions or actions of the information users (where users is broadly

defined). Defining this threshold requires a value judgment. The threshold may be pre-defined

for a particular reporting regime. An example threshold that has been applied is 5 percent of the

total inventory for the organization section being scrutinized.

There is not a consensus position regarding the materiality issue. For example, the WorldResources Institute/World Business Council on Sustainable Development (WRI/WBCSD) GHGProtocol [WRI/WBCSD 2004] (hereafter referred to as the WRI/WBCSD GHG Protocol) offersthis perspective on materiality thresholds:

Sometimes it is tempting to define a minimum emissions accounting threshold (oftenreferred to as a materiality threshold) stating that a source not exceeding a certain size can beomitted from the inventory. Technically, such a threshold is simply a predefined andaccepted negative bias in estimates (i.e., an underestimate). Although it appears useful intheory, the practical implementation of such a threshold is not compatible with thecompleteness principle of the WRI/WBCSD GHG Protocol Corporate Standard. In order to

utilize a materiality specification, the emissions from a particular source or activity wouldhave to be quantified to ensure they were under the threshold. However, once emissions arequantified, most of the benefit of having a threshold is lost.

A threshold is often used to determine whether an error or omission is a material discrepancyor not. This is not the same as a de minimis for defining a complete inventory. Insteadcompanies need to make a good faith effort to provide a complete, accurate, and consistentaccounting of their GHG emissions. For cases where emissions have not been estimated, or


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estimated at an insufficient level of quality, it is important that this is transparentlydocumented and justified. Verifiers can determine the potential impact and relevance of theexclusion, or lack of quality, on the overall inventory report.

Additional points for consideration include:

A reasonable materiality threshold simplifies reporting by not requiring companies to reportsmaller emissions sources;

Once a calculation is competed and compared to a threshold, the burden in adding theemissions to the reported inventory is extremely small;

Depending upon the threshold basis, it will likely establish varying significance levels forlarger and smaller companies; and

For any mandated reporting, a materiality threshold may be a necessity to identify the need toreport: for a small source; for a discovered inventory error; or, to define a significance levelfor activities or equipment that are established as trivial.

The AGA GHG Guidelines do not identify a pre-established materiality threshold, as this valuejudgment is best addressed within the context of the inventory goals and intended use. Inaddition, if the inventory is to be used for a particular reporting program or registry, that programmay include either a pre-defined threshold or ground rules associated with both de minimisemissions and minor errors.

2.7 Direct Emissions

The majority of GHG emissions from natural gas distribution equipment and processes are directemissions. Direct emissions include combustion, vented, fugitive, and mobile source emissionsdirectly associated with company operations. All direct emissions should be accounted for in the

inventory other than emissions that are less than a defined significance threshold, as discussedabove. Direct emission sources are discussed in the subsections below.

2.7.1 Combustion Emissions

Emissions of CO2, methane, and N2O from combustion sources, including:

Pipeline heaters; IC engine and gas turbine generators and compressors; and Facility boilers.2.7.2 Vented Emissions

Vented methane emissions come from a variety of process equipment and operational practices.Note that process venting and maintenance venting (e.g., purge/blowdown) are included underfugitives for IPCC and some other reporting guidelines. These emissions comprise a significantportion of GHG emissions from distribution. Potential emission sources include:

Pneumatic devices (isolation valves and control loops); and


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Purge or blowdown from routine operations or upsets, including: Pipeline venting; M&R station venting; and Maintenance and inspection.

2.7.3 Fugitive Emissions

Fugitive GHG emissions are methane leaks from pipelines and system components such as valvepacking, flanges, and other piping connectors. The emission sources and activity factor basis forfugitive emissions are based upon primary equipment that includes subcomponents, such as:

Piping and associated components; M&R stations; and Customer meters.2.7.4 Mobile Source EmissionsMobile sources combustion emissions of CO2, methane, and N2O include:

Gasoline and diesel powered fleet vehicles autos and trucks; and Construction equipment.2.8 Indirect Emissions

Indirect emissions are reported from power consumed at a facility that is produced by a thirdparty. This requirement is common for many reporting programs. Reporting protocols such

as the WRI/WBCSD GHG Protocol and International Petroleum Industry EnvironmentalConservation Association (IPIECA), Petroleum Industry Guidelines for ReportingGreenhouse Gas Emissions [IPIECA 2003] (hereafter referred to as the IPIECA Guidelines)include additional background on indirect emissions from purchased power. Indirectemissions should be reported separately from direct emissions in company reports. Section6.1 includes methods for estimating indirect emissions.

While indirect emissions can be a substantial emission source for some industrial sectors, thisis typically not the case for gas distribution. In general, reporting indirect emissions fromelectricity helps provide a more complete picture of company emissions, provides anunderstanding of opportunities available for GHG reductions from energy efficiency, and

assists in the understanding of tradeoffs between onsite power generation and purchasedelectricity. In addition, indirect purchased power emissions are typically required for currentvoluntary reporting programs.

2.9 Optional Emissions

Another type of emissions, which are typically comprised of additional indirect emissionsources, is optional emissions. These are referred to as Scope 3 emissions in the


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WRI/WBCSD GHG Protocol. Examples include: transportation related activities such asemployee business travel, employee commuting, and waste transportation; outsourced activities;and, waste disposal. Reporting on these activities and thus delineation of estimation methods has been limited to date and is not discussed further herein.

3.0 Combustion Emissions

Greenhouse gases are emitted from combustion equipment used at natural gas facilities, andcombustion emissions include CO2, CH4, and N2O. CO2 is formed from fuel carbon oxidation,CH4 is a product of incomplete combustion typically CH4 in the fuel escapes oxidation, andN2O is formed by oxygen-nitrogen reactions that are promoted by cooler flame temperatures.The combustion equipment typically employed at distribution facilities includes:

Stationary sources firing natural gas (processed/pipeline quality), diesel fuel, and gasoline: External combustion sources (i.e. line heaters); and Emergency generators;

Less prevalent and not common throughout the distribution sector, other potential combustionsources may include:

Gas/combustion turbines: simple- and combined-cycle; Reciprocating internal combustion (IC) engines: Natural gas-fired 2-stroke lean burn, 4-

stroke lean burn, and 4-stroke rich burn; gasoline-fired; and diesel fired; and

Gas-fired heaters and boilers.Natural gas-fired reciprocating internal combustion engines and gas turbines are the mostprevalent combustion sources throughout the natural gas industry, primarily used for gas

compression. In the distribution sector, most companies do not further compress the gas aftercustody transfer from the transmission pipeline; however, gas turbines and IC engines may beused by distribution companies for power generation. Pipeline heaters are often the mostcommon combustion emissions source. For other combustion sources not listed or presentedhere, and cannot follow the calculation methodologies outlined below, the reader is referred toeither the API Compendium or the INGAA Greenhouse Gas Emission Estimation Guidelines ForNatural Gas Transmission And Storage; Volume 1 Emissions Estimation Methodologies AndProcedures. Note that mobile source emissions from combustion (i.e., fleet vehicles andconstruction equipment) are included in Section 6.

3.1 Combustion Emissions Estimation Methodologies Overview

GHG emissions from a single combustion source or group of sources (facility) can be directlymeasured (e.g. CO2 emissions can be determined from the fuel carbon content and mass flowrate) or they can be estimated from a source-specific emission factor (EF) and correspondingactivity data (AD). The general equation for this estimation is:

EmissionsGHG (mass/unit time) = AD * EF Eqn. 3-1


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These AD are equipment, process, or facility data per unit time and the EF is GHG mass orvolume per equipment, process, or facility data increment. Increased emissions estimationaccuracy requires more detailed AD and calculations. For combustion, available GHG literatureincludes considerably more data and detailed methods for estimating emissions as theapproaches are common across industrial sectors. For example, while leading reporting and

accounting documents such as the WRI/WBCSD GHG Protocol do not offer methods for naturalgas system estimates of vented or fugitive emissions, supplements are available that specificallyaddress combustion emissions.

3.1.1 Emission Tiers for Combustion

A general hierarchy of emissions estimation approaches, in order of increasing accuracy (i.e.decreasing uncertainty), consistent with the discussion of tiers in Section 2.2 is as follows:

Tier 1. Emissions estimated using system or facility-level Tier 1 EFs based on GHGemissions per unit production or other facility data (e.g., for natural gas distribution, pipelinelength) and a corresponding AD. There is a unique EF for each GHG. The EF * AD

calculation estimates the GHG emissions from combustion for an entire facility, company, orindustry;

Tier 2. Emissions estimated using facility-level Tier 2 EFs based on total fuel combusted ina facility and corresponding AD. There is a unique EF for each GHG and fuel type. The EF* AD calculation estimates the GHG emissions from combustion of the fuel type for an entirefacility; and

Tier 3. Emissions estimated using equipment-level Tier 3 EFs based on total fuel combustedin a piece of equipment and a corresponding AD. There is a unique EF for each GHG, fueltype, and combustion technology category (e.g. 2-stroke lean burn ICEs, externalcombustion/heaters). The EF * AD calculation estimates the GHG emissions from

combustion of the fuel type in an equipment type (or bank of similar equipment).

For Tiers 1 through 3, the emission factor is a published default factor based on typical facility,equipment, and/or fuel characteristics. For combustion, activity data and operating informationmay be available to conduct a more refined emission estimate. Examples of Tier 3+ levelestimates follow:

CH4 and N2O emissions are estimated using equipment-level EFs based on total fuelcombusted in specific equipment and corresponding AD. There is a unique EF for eachGHG, fuel type, and equipment make and model. The EF is derived from combustionequipment manufacturer data or emissions monitoring/testing of the specific equipmentmodel. The EF * AD calculation provides a GHG emissions estimate from combustion of the

fuel type in the defined make and model equipment.

For CO2, emissions are estimated using facility or equipment-level (or equipment bank) fuelusage and fuel composition data from a facility fuel (e.g. natural gas) analysis. The meteredfuel consumption and fuel carbon content provide the means to accurately estimate CO2emissions.

In this scenario, methane and N2O would be estimated based on fuel usage (Activity Data) andan emission factor. The fidelity of the available emission factor would indicate the relative


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Tier of this estimate e.g., a Tier 3 estimate based on an average default emission factorwould be most likely. The CO2 estimate approach above is one of several that are recommendedin available literature. The CO2 estimation hierarchy is discussed further below. In general,because fuel consumption and fuel composition data are more accessible, CO2 estimates fromcombustion can be completed with a higher degree of certainty than fugitive and venting GHG

emissions.

In the future, improved operational data access (i.e., individual fuel meter volumes and fuelanalysis) and emission measurements associated with specific combustion equipment mayprovide the opportunity for very refined combustion equipment estimates of CH4 and N2Oemissions. However, CO2 emissions are the primary emission source from combustion.

Calculation procedures and recommended EFs and AD for Tiers 1 and 2 are detailed below,along with a discussion of estimation approaches that address Tier 3 level estimates and beyond.

3.1.2 Data Conventions

Combustion emission factors in the literature are typically reported in tonnes/MMBtu, tonnes/TJ,and the original units reported in the referenced source. In the Tables below, the followingconventions are used to convert the emission factors from the referenced source units totonnes/MMBtu and tonnes/TJ.

Fuel Heating Value Emission factors are reported based on the fuels higher heating value(HHV). Fuel heating values listed in Table 3-1 were used unless otherwise noted. A factorof 0.9 was used to convert lower heating value (LHV) based EFs to HHV-based EFs fornatural gas unless otherwise noted:

EFHHV = 0.9 * EFLHV Eqn. 3-2

A factor of 1.05 was used to convert LHV-based EFs to HHV based EFs for liquid fuels diesel fuel and gasoline - unless otherwise noted:

EFHHV = EFLHV/1.05 Eqn. 3-3

Standard Gas Conditions - The ideal gas law:PV = nRT Eqn. 3-4

Where: P = pressure (in atm, psia, or kPa)V = volume (ft3, cm3)

n = number of gmoles or lbmolesR = 10.73 psi ft3/lbmole R, 0.73 atm ft

3/lbmole R, 82.06 atm cm

3/gmole K

T = temperature (R, K)

Equation 3-4 was used to convert gas volumes to a mass or weight basis. Standard gasconditions are a temperature of 60 F/15.6 C and a pressure of 1 atm /14.696 psia/101.325kPa These conditions give a standard volume of 379.3 standard cubic feet (scf)/lbmole or23.69 liters/gmole.


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Fuel Properties Default fuel heating values, densities, and carbon contents are listed inTable 3-1. These values were used for EF conversions and calculations unless values werespecified in the referenced source. In these instances, the referenced fuel properties werenoted and used for calculations.

Table 3-1. Densities, Heating Values, and Carbon Content for Select Liquid and Gaseous Fuels

Fuel Density HHV LHVCarbon, %by Weight

Ref

Diesel 7.05 lb/gal5.75*10

6

Btu/bbl5.46*10

6

Btu/bbl87.3 A

Gasoline/ Petrol 6.17 lb/gal5.46*10

6

Btu/bbl5.19*10

6

Btu/bbl85.5 A, B

Kerosene 6.76 lb/gal5.67*10

6

Btu/bbl5.39*10

6

Btu/bbl87 A, B

Natural Gas

(processed/pipeline) 1 lb/23.7 scf 1020 Btu/scf 918 Btu/scf 76 CNatural Gas(raw/unprocessed)

~1 lb/19 scf 1240 Btu/scf 1110 Btu/scf ~77 D

HHV Higher Heating ValueLHV Lower Heating ValueA. EPA AP-42, Volume 1, Table 1.3-12, 1998.B. North American Combustion Handbook, Volume I: Combustion Fuels, Stoichiometry, Heat Transfer,

Fluid Flow, 3rd Ed., 1986.C. EPA AP-42, Section 1.4, Natural Gas Combustion, 1998D. Canadian Association of Petroleum Producers (CAPP), Calculating Greenhouse Gas Emissions,

CAPP Publication No. 2003-03, April 2003.

3.1.3 Emission Factor Selection Criteria

Emission factor alternatives are more abundant for combustion than for the other emissioncategories characteristic of gas distribution. A three step process was used to identify the mostappropriate EFs for estimating GHG emissions from natural gas distribution combustion systems:

1. Documents with GHG EF and emissions estimation methodologies were reviewed. Emissionestimation methodologies were documented and EFs tabulated for CO2, CH4, and N2O.Entries also included fuel type and heating value, combustor type and specifications (design,applicable operating conditions (e.g. load range), etc.), air pollution controls (APCs), EFrating and uncertainty, reference (if EF originated from another document), and otherapplicable information.

2. All EFs were converted to common activity factors of tonne/MMBtu or tonne/TJ based onHHV for comparison purposes. If insufficient data (e.g. HHV) were provided to perform theconversion calculations, default values from Table 3-1 were applied.


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3. Common EFs (based on GHG, fuel, combustion technology, etc.) were compared todetermine the factor most applicable to natural gas distribution facilities. Quite often EFswere redundant, i.e., EFs in a recent report had been referenced from a previous report. Inthese instances, the original reference was cited. Selection of the most applicable EFs wasbased on the following criteria, generally in the order presented:

Quality rating. For example, AP-42 EF quality ratings or reported uncertainties. TheAP-42 ratings methodology is presented in Appendix C-3;

Specificity to natural gas distribution facilities; Specificity to the United States and/or North America. It was generally assumed that US

and North American based EFs are more pertinent to natural gas distribution facilitiesthan foreign based EFs, particularly for fuel sensitive EFs such as CO2;

EF development methodology. For example, GHG directly measured or estimated fromanother measurement (e.g. N2O assumed to be 1.5% of NOx);

Age. It was generally assumed that newer EFs are based on more recent and morereliable data;

Activity Data availability and expected accuracy; and, Consistency with other reported EFs (is it an outlier and why?).

Numerous references in the available literature include emission factors and estimation methodsfor combustion. Thus, the emission factors presented in this section include identification of thespecific reference. For later sections (e.g., venting and fugitives), the available emission factorsare very limited and based on a few key studies or reports. Thus, the literature reference isidentified in the sections that address GHG from sources other than stationary combustion, butless reference detail is provided in the emission factor tables.

3.2. Stationary Source CO2 Emission Estimation MethodologiesFuel carbon is almost completely oxidized to CO2 during combustion, irrespective of thecombustor type. The complete combustion equation for a hydrocarbon is:

CxHyOz + (x + y/4 z/2) O2 = xCO2 + y/2 H2O Eqn. 3-5

Therefore, if the fuel consumption for a facility, equipment bank (e.g., compressor building), orindividual unit is known or can be reasonably estimated, CO2 emissions can be estimated fromthe fuel consumption, known or estimated fuel composition (carbon content), and a carbon

oxidation factor. As indicated in Table 3-4, using carbon oxidation factors is optional, and themost recent IPCC inventory guidelines no longer apply this correction. If the activity data are atthe facility level and a default fuel analysis is used, this is the Tier 2 approach for CO2 emissionsestimation. If equipment specific fuel use and fuel analysis are used, the CO2 emissionsestimate would be a direct Tier 3+ calculation.

Figures 3-1 and 3-2 outline the methodology for estimating CO2 emissions from combustion at anatural gas distribution facility, including the approach for determining which Tier to use for


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estimating a facilitys fuel consumption and CO2 emissions. The total consumption of each fuelfired at a facility must be determined (diesel fuel, natural gas, and/or gasoline). If differentcompositions of a fuel type, e.g. natural gas, are fired during a reporting period, thesecompositions should be considered separately. The Figures 3-1 and 3-2 hierarchy recommendsfuel consumption estimation methods consistent with different emissions estimates Tiers. This

approach is based on the hierarchy provided in the IPIECA Guidelines. Preferred approaches areindicated in the figures, based on measured/known values for fuel composition or heating value.

Yes*

No

No

* Preferred approach.

Figure 3-1. CO2 emissions estimation overview.

Can the annual facilityconsumption of a fuel beestimated? Refer to

Figure 3-2.

Is the fuel composition(Carbon content & MW(gas) or density (liquid))known or accuratelyestimable?

Is the fuel HHV known or

accurately estimable?

Determine CO2 emissions from Eqn 3-10 or 3-11. Apply fractional carbonoxidation optional (Table 3-4).

Yes*

Estimate CO2 emissions with Eqn 3-7 or3-8. Use Tier 2 EFs from Table 3-3 for

diesel and gasoline/petrol. Use HHV-based EFs in Table 3-3 for natural gas.Apply fractional carbon oxidation o tional Table 3-4 .

Yes*

Estimate CO2 emissions from Tier 1EFs (Table 6-2), correspondingActivity Data, and Eqn 3-6.

No

Estimate CO2 emissions with Eqn 3-7 or3-8. Use default HHVs in Table 3-1. UseTier 2 EFs from Table 3-3 for diesel andgasoline/petrol. Use default Tier 2 EFs inTable 3-3 for natural gas. Applyfractional carbon oxidation optional

(Table 3-4).


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*

.

* Preferred approach

Figure 3-2. CO2 emissions estimation fuel consumption determination.

Can total facility consumption of eachfuel type be determined from a singlepoint metering and integrated massflow (e.g. natural gas), and/or tank

measurements or purchase records forcommodity fuels (e.g. diesel, gasoline)?

Can fuel consumption by individualcombustion equipment be determined?e.g. from fuel flow meters andintegrated mass flow and/or purchaserecords or tank measurements?

Can fuel consumption by individualcombustion equipment be determinedfrom ratings and measured operationhours & loads for ICEs & turbines (AppA-1); and measured energy balance forboilers & heaters (vendor data)?

Total facility consumption of eachfuel type by summing fuelconsumption by individualcombustors. Use total to determineCO2 emissions estimate refer to

Fig. 3-1.

Yes*

Use total facility fuel consumptionfor CO2 emission estimates refer to

Fig. 3-1.

Can fuel consumption by individualcombustion equipment be determinedfrom ratings and estimated operationhours & loads for ICEs & turbines(App A-1); or measured energy balancefor boilers & heaters (vendor data)?

Yes*

Total facility consumption of eachfuel type by summing fuelconsumption by individualcombustors. Use total to determineCO2 emissions estimate refer toFig. 3-1.

Total facility consumption of eachfuel type by summing fuelconsumptions by individualcombustors. Use total to determineCO2 emissions estimate refer toFig. 3-1.

Are there alternative methods forestimating fuels consumption, e.g. fuel

consumption at a similar facility?

Yes*

Yes*

Estimate CO2 emissions from Tier 1EFs (Table 3-2), correspondingActivity Data, and Eqn 3-6.

Use total facility fuel consumptionfor CO2 emission estimates refer

to Fig. 3-1.

Yes*

No

No

No

No

No


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3.2.1 CO2 Emissions Estimates Using Tier 1 Emission Factors

Tier 1 CO2 emissions are estimated from a Tier 1 CO2 emission factor and corresponding activitydata as shown in equation 3-6. Table 3-2 lists the Tier 1 CO2 emission factor. This emissionfactor is from GRI-GHGCalcTM. It should be noted that this emission factor is based on pipeline

heater emissions. If a distribution system operates compressors or other combustion equipment,a higher tier estimation approach is recommended.

tonne CO2 = Activity Data * EF Eqn 3-6

where: tonne CO2 = estimated annual CO2 emissions from combustion (tonne/yr)Activity data = transmission pipeline length or storage stations

Table 3-2. Tier 1 CO2 Emission Factors for Combustion

Segment Activity Data GHG EF EF Units ReferenceDistribution pipeline length CO2 5.7*10

-1 Tonne/mile-yr GRI 2001

GRI 2001 - GRI GHGCalc Version 1.0 Emission Factor Documentation, July 2001

3.2.2 CO2 Emissions Estimates Using Tier 2 Emission Factors

If the annual fuel consumption can be estimated, fuel composition (carbon content and molecularweight/density) is not known and the fuel heating value is known or can be reasonably estimated,the annual CO2 emissions are estimated using an EF from Table 3-3 and equation 3-7 for naturalgas and equation 3-8 for liquid fuels. If the fuel is natural gas, a heating value based EF fromTable 3-3 is recommended. If more than one fuel is fired, CO2 emissions from each fuel areestimated and total emissions are then determined by summing the individual fuels emissionsusing equation 3-9.

tonneCO2j = Activity Data * EF* COX Eqn. 3-7 (natural gas)

where: tonneCO2j = estimated annual facility CO2 emissions from combustion of fuel j(tonne/yr)Activity Data = QGFj * HHVGj * 10

-6= MMBtu/yr

QGFj = scf fuel j combusted at facility/yrHHVGj = Btu/scf fuel j10

-6= MMBtu/10

6Btu

EF = tonnes CO2/MMBtuCOX = COX is the fractional carbon oxidation factor. The use of COX is

optional, a conservative approach is to assume 100% carbon oxidation to CO2 (i.e.COX = 1.0). Recommended COXs are listed in Table 3-4.

tonneCO2j = Activity Data * EF* COX Eqn. 3-8 (liquid fuels)

where: Activity Data = QLFj * HHVLj * 10-6

= MMBtu/yrQLFj = gal fuel j combusted/yrHHVLj = Btu/gal fuel j


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tonnes CO2= tonneCO2j Eqn. 3-9

where: j = number of different fuels combusted at facilitytonne CO2 = estimated annual facility CO2 emissions (tonne/yr)

If the annual fuel consumption can be estimated, but the fuel composition (carbon content andmolecular weight) is not known, and the fuel heating value is not known or cannot be reasonablyestimated, CO2 emissions are estimated using a default EF from Table 3-3, a default heatingvalue from Table 3-1, and equation 3-7 for natural gas and equation 3-8 for liquid fuels. Table 3-3 includes default EFs for both pipeline and raw natural gas.

Table 3-3. Tier 2 CO2 Emission Factors for Combustion.

FuelActivity

DataGHG EF EF Units

Reported EF(Units)

Reference

DieselMMBtu/

yrCO2 7.4*10

-2 tonne/MMBtu*

Calculation Table 3-1

Gasoline/Petrol MMBtu/yr

CO2 6.8*10-2 tonne/

MMBtu*Calculation Table 3-1

NG: Default Pipeline/Processed

MMBtu/yr

CO2 5.3*10-2 tonne/

MMBtu*52.91 (tonne/

109 Btu)EIA 2004

NG: HHV = 975 1000 Btu/scf

MMBtu/yr

CO2 5.4*10-2 tonne/

MMBtu*54.01 (tonne/

109 Btu)EIA 2004


MMBtu/yr

CO2 5.3*10-2 tonne/

MMBtu*52.91 (tonne/

109

Btu)EIA 2004


MMBtu/yr

CO2 5.3*10-2 tonne/

MMBtu*53.06 (tonne/

109

Btu)EIA 2004

NG: HHV = 1050

1075 Btu/scf

MMBtu/

yr CO2 5.3*10

-2 tonne/

MMBtu*

53.46 (tonne/

109 Btu) EIA 2004NG: HHV = 1075 1100 Btu/scf

MMBtu/yr

CO2 5.4*10-2 tonne/

MMBtu*53.72 (tonne/

109 Btu)EIA 2004

NG: HHV > 1100Btu/scf; Default Raw/Unprocessed

MMBtu/yr

CO2 5.5*10-2 tonne/

MMBtu*14.92 (MMTC/

1015

Btu)EIA 2002

* HHVEIA 2004 - Energy Information Administration (EIA). Documentation for Emissions of GreenhouseGases in the United States 2002, (Washington, DC, January 2004).EIA 2002 - Energy Information Administration (EIA). Emissions of Greenhouse Gases in the UnitedStates 2001, DOE/EIA-0573(2001), December 2002.

3.2.3 CO2 Emissions Estimates Determined from Fuel Consumption and Composition

If the annual fuel consumption can be estimated and the fuel composition (carbon content andmolecular weight/density) is known, CO2 emissions are estimated using a mass balance approachshown with equation 3-10 for natural gas and equation 3-11 for liquid fuels. Variability in fuelcomposition is typically very low for combustion sources in distribution, and changes in fuelcomposition are unlikely to materially affect the CO2 emissions estimate. Fuel analysis sample


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frequency is not well-defined for current GHG inventory practices. Depending upon thereporting objectives (e.g., registry materiality threshold), it may be reasonable to occasionallyreview the fuel composition to ensure reporting objectives are being met. For example, fornatural gas-fired sources, quarterly or semiannual review of a fuel analysis relative to the originalcomposition used in the calculation is reasonable. If the analysis does not indicate variability

above the target threshold, then less frequent fuel composition review (e.g, annual) is warranted.If variability exceeds desired targets (e.g., a registry materiality threshold), then the carboncontent in the calculation may need to be updated and more frequent (e.g., monthly) gas analysismay be warranted to better characterize variability. For liquid fuels, composition is typicallyprovided with fuel delivery and this can be reviewed. For natural gas, analysis at the receiptpoint from transmission should be considered, and experience indicates that variability istypically less than any reasonable materiality threshold. If more than one fuel is fired, then CO2emissions from each fuel are estimated and total emissions are then determined by summing theindividual fuels emissions using equation 3-9.

tonneCO2j = 4.38 * 10-6 * QGFj * MWFj * Cj wt%/100 * COX Eqn. 3-10 (natural gas)

Where: tonneCO2j = estimated annual CO2 emissions from combustion of fuel j (tonne/yr)QGFj = scf fuel j combusted/yrMWFj = fuel molecular weight = lb fuel j/lbmole fuel jCj wt%/100 = carbon weight percent/100 = lb C/lb fuel j4.38 * 10-6 = Mol Vol (lbmole fuel/379.3 scf fuel) * 1/MWC (lbmole C/12 lb C) *lbmole CO2/lbmole C * MWCO2 (44 lb CO2/lbmole CO2) * tonne/2204.6 lb

Procedures for calculating fuel molecular weight and carbon weight percent are in Appendix C-2.

tonneCO2j = 1.66 * 10-3

* QLFj * LFj* Cj wt%/100 * COX Eqn. 3-11 (liquid fuels)

Where: QFLj = gal fuel j combusted/yrLFj = fuel density = lb fuel j/gal fuel j1.66 * 10

-3= 1/MWC (lbmole C/12 lb C) * lbmole CO2/lbmole C * MWCO2 (44 lb

CO2/lbmole CO2) * tonne/2204.6 lb

Table 3-4. Fractional Carbon Oxidation Factors*.

Fuel Fraction of Fuel C Oxidized (COX) ReferenceDiesel 0.99 EIIP 1999, IPPC 1996

Gasoline 0.99 EIIP 1999, IPPC 1996

Natural Gas 0.995 EIIP 1999, IPPC 1996

EIIP 1999 - EIIP, Guidance for Emissions Inventory Development, Volume II: Estimating GreenhouseGas Emissions, EIIP Greenhouse Gas Committee, October 1999.IPPC 1996 - Intergovernmental Panel on Climate Change (IPCC). Greenhouse Gas Inventory ReferenceManual: IPCC Guidelines for National Greenhouse Gas Inventories, Volume 3, 1996*Use of carbon oxidation factors is optional; the most recent IPCC inventory guidelines no longer applythis correction.


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3.3 Stationary Source CH4 and N2O Emission Estimation Methodologies

While CO2 emissions are primarily determined by fuel consumption and carbon content and areirrespective of combustor type, CH4 and N2O emissions are impacted by combustor type, design,air pollution control(s), operation, age, and maintenance, as well as fuel properties. Therefore,

more detailed, equipment-specific emissions estimation methodologies are needed for CH4 andN2O if precision is desired. However, N2O emissions are typically minimal from combustion.Post-combustion catalytic NOx control may increase N2O in some cases, but data is very limited.Methane emissions are minimal from combustion sources other than natural gas-fired ICengines.

Methane emissions from IC engines and gas turbines can be estimated using either annual energyoutput measured as horsepower hours (hp-hrs) or fuel consumption measured as MMBtu as theactivity data. Provided a reasonable energy output estimate can be made, hp-hrs are thepreferred activity data for IC engines and gas turbines. Figure 3-3 outlines the methodology forestimating CH4 emissions from ICEs and turbinesusing hp-hrs as the activity data.This

approach does not apply for N2O because hp-hrs based emission factors have not been developedfor N2O. Figure 3-4 outlines the methodology for estimating CH4 and N2O emissions from allother combustion equipment and for estimating N2O emissions from IC engines and turbines.Tier 3 emissions estimates are used if energy output and/or fuel consumption by individualcombustion equipment can be estimated. If detailed information about combustion equipmentsmake, model, and operation are available, it may be possible to apply a Tier 3+ emission factor.If fuel consumption by individual combustors cannot be estimated and total facility fuelcombustion by fuel type can be estimated, then a Tier 2 emissions estimate can be used;however, if the facility fuel consumption cannot be reasonably estimated, then a Tier 1methodology should be used.


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Figure 3-3. ICE/Turbine CH4 and N2O emissions estimation overview.

For individual ICEs & t