GREENHOUSE GAS EMISSION ESTIMATION METHODOLOGIES, PROCEDURES, AND GUIDELINES FOR THE NATURAL GAS DISTRIBUTION SECTOR

Transcription

1 GREENHOUSE GAS EMISSION ESTIMATION METHODOLOGIES, PROCEDURES, AND GUIDELINES FOR THE NATURAL GAS DISTRIBUTION SECTOR Prepared for: American Gas Association (AGA) 10G Street, N.E., Suite 700 Washington, D.C Prepared by: innovative environmental solutions, inc. P.O. Box 177 Cary, IL Copyright 2008 American Gas Association. All rights reserved. This work may not be reproduced or transmitted in any form or by any means, electronic or mechanical, including photocopying, recording or by information storage and retrieval system without permission in writing from the American Gas Association.

2 TABLE OF CONTENTS 1. Introduction Purpose and Objective Greenhouse Gases & Global Warming Potentials Natural Gas Distribution Sector Overview Considerations for Future GHG Guidelines Updates: Current Programs to Advance the State-of-the-Art for Distribution Section GHG Emissions Estimates Technical Elements GHG Emissions Estimation Methodologies - Quantification Steps Tiered Approaches Emission Factors Activity Data Precision and Uncertainty Estimates Materiality Threshold Direct Emissions Combustion Emissions Vented Emissions Fugitive Emissions Mobile Source Emissions Indirect Emissions Optional Emissions Combustion Emissions Emission Estimation Methodologies Overview Emission Tiers for Combustion Data Conventions Emission Factor Selection Criteria Stationary Source CO 2 Emission Estimation Methodologies CO 2 Emission Estimates Using Tier 1 Emission Factors CO 2 Emission Estimates Using Tier 2 Emission Factors CO 2 Emissions Estimates Determined from Fuel Consumption & Composition Stationary Source CH 4 and N 2 O Emission Estimation Methodologies CH 4 and N 2 O Emission Estimates Using Tier 1 Emission Factors CH 4 and N 2 O Emission Estimates Using Tier 2 Emission Factors CH 4 and N 2 O Emission Estimates Using Tier 3 Emission Factors CH 4 and N 2 O Emissions Estimates Tier Vented Emissions Calculation Methods and Conversion Factors Emissions Estimation Methods Tier 3 Emissions Estimates Tier 2 Emissions Estimates Tier 1 Emissions Estimates Event-Based and Equipment Specific Venting Emissions Estimates from Engineering Data (Tier 3+)...43 ii

3 TABLE OF CONTENTS (continued) 4.3. Example Calculations for Vented Emissions Tier 1: Vented Emissions Calculation Tier 2 Vented Emissions Calculation Tier 3 Vented Emissions Calculation GHG Vented Emissions Estimate Example Conclusions Fugitive Emissions Background on Fugitive Emission Sources and GHG Estimation Emission Estimation Methods Tier 3 Emissions Estimates Tier 2 Emissions Estimates Tier 3 Emissions Estimates Tier 3+ Facility-Specific Estimates Screening-based Methodologies Other Tier 3+ Emission Estimation Approaches Example Calculations for Fugitive Emissions Tier 1 Fugitive Emissions Calculation Tier 2 Fugitive Emissions Calculation Tier 3 Fugitive Emissions Calculation GHG Fugitives Emissions Estimate Example Conclusions Mobile Source Emissions Mobile Sources and Fleet Vehicles Automobiles, Trucks, and Motorcycles Construction Equipment Indirect Emissions Indirect Emissions from Purchased Electricity Methods for Calculating Indirect Emissions from Purchased Electricity...72 APPENDICES APPENDIX A: A-1. Website References A-2. References APPENDIX B: Unit Conversions APPENDIX C: Support Information for Combustion Emissions C-1. Energy Output to Input Conversions for Prime Movers C-2. Fuel Composition Conversions: Mole Percentage, Weight Percentage, Carbon Mole Percentage, and Carbon Weight Percentage C-3. AP-42 Emission Factor Quality Ratings C-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 and Observations on Inventory Development and Emission Factor Improvement iii

4 LIST OF TABLES Table 1-1. Global Warming Potentials (100 Year Time Horizon, IPCC 1995)...3 Table 1-2. GWP (100-year) for CO 2, Methane, and N 2 O from 1995 SAR and 2001 TAR...3 Table 3-1. Densities, Heating Values, and Carbon Content for Select Liquid and Gaseous Fuels...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 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 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 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 Table 4-7. ADC Tier 2 Vented Activity Data and GHG Emissions Calculations...46 Table 4-8. ADC Tier 2 Vented CO 2 eq Emissions Estimate for Table 4-9. ADC Tier 3 Vented Activity Data and GHG Emissions Calculations...47 Table ADC Tier 3 Vented CO 2 eq Emissions Estimate for Table Vented Emissions Estimate Example Summary for ADC in 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 5-5. Distribution Sector Tier 2 Emission Factors for Fugitive Emissions...58 Table 5-6. Comparison of 1996 and 2005 US Distribution System Main Pipelines...58 iv

5 LIST OF TABLES (continued) Table 5-7. Comparison of 1996 and 2005 US Distribution System Service Pipelines...59 Table 5-8. Distribution Sector Tier 1 Emission Factors for Fugitive Emissions...60 Table 5-9. ADC Tier 1 Activity Data and GHG Calculations...65 Table ADC Tier 1 GHG Emissions Estimate for Table ADC Tier 2 Activity Data and GHG Calculations Table ADC Tier 2 Fugitive CO 2 eq Emissions Estimate for Table ADC Tier 3 Activity Data and GHG Calculations...66 Table ADC Tier 3 Estimate CO 2 eq Emissions for 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 CO 2 emissions estimation overview...21 Figure 3-2 CO 2 emissions estimation fuel consumption determination...22 Figure 3-3 ICE/Turbine CH 4 and N 2 O emissions estimation overview...26 Figure 3-4 CH 4 and N 2 O 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 v

6 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 member companies involved is gratefully acknowledged. Special thanks are given to Christina Sames from AGA and the members of the AGA Greenhouse Gas Task Group for review, comment, and technical direction on this document. vi

7 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 document presents a detailed compilation of the select methods for estimating carbon dioxide, methane, and nitrous oxide emissions from combustion and non-combustion sources for the natural gas industry distribution sector. These guidelines are intended to be a living document and are designed as a detailed reference for developing a GHG inventory for use by both practitioners and inventory managers. 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 strategy that considers a company's particular needs and circumstances; and Establish a consistent framework for estimating GHG emissions for the natural gas distribution sector to facilitate inter-company comparisons and ease data aggregation for future industry reporting initiatives. To inform the reader and enhance understanding of the GHG Guidelines, Appendix F provides example inventory calculations for a fictitious distribution company. The focus of Appendix F is to illustrate emission calculations for typical source types. This appendix also includes discussion on inventory objectives, data gathering challenges, emission estimate uncertainty, and current emission factor improvement efforts for the distribution sector. In this document, sections 1 and 2 present general information concerning GHG emissions, an emission-source classification scheme, and general procedures for designing and implementing a GHG emissions inventory. Sections 3 through 6 present the emission factors and emission estimation 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 of Energy (DOE) 1605b program consider the same emission sources and use similar, but slightly different terminology. For example, the DOE 1605b program uses the terms stationary combustion, fugitives, process (e.g., venting), mobile combustion, and indirect emissions. 1

8 Following the body of the report, references cited are listed in Appendix A. Several primary references are consistently used throughout this document, and the complete citations for these primary references are included in Appendix A, as well as other references used to prepare the GHG Guidelines. Common units and conversions for GHG calculations are provided in Appendix 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 historical GHG 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 the terrestrial radiation leaving the Earth s surface thus causing a warming effect on earth. The greenhouse effect is primarily from carbon dioxide (CO 2 ) and water vapor, along with other trace gases in the atmosphere. For emissions purposes, a number of gases are typically considered to be GHGs, including CO 2, methane (CH 4 ), nitrous oxide (N 2 O), hydro fluorocarbons, per fluorocarbons (e.g., C n F 2n+2 compounds), and sulfur hexafluoride (SF 6 ). For emissions from oil and natural gas systems, CO 2, methane, and nitrous oxide are the gases of interest and the focus of this document. Methane and CO 2 account for the vast majority of GHG emissions for natural gas systems. While included herein, N 2 O comprises a very small percentage of distribution system GHG emissions, and emission factors and associated data are very limited. Currently, registries and voluntary reporting programs typically focus initially on reporting CO 2 emissions, while encouraging or planning to eventually include other gases. For example, the California Climate Action Registry requires that for the first three years Registry participants must report at a minimum their CO 2 emissions in CA or in the U.S., depending on the geographic scope of their inventory. Starting with the fourth year, participants must report the six GHGs included in the Kyoto Protocol GHGs (CO 2, CH 4, N 2 O, hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and sulfur hexafluoride (SF 6 )). Changes in the atmospheric concentration of GHGs may affect the energy balance between the land, the seas, the atmosphere, and space. A measure of such changes in the energy available to the 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 the greenhouse effect both directly and indirectly. A direct contribution is from a gas that is itself a greenhouse gas. Indirect radiative forcing occurs when the original gas undergoes chemical transformations in the atmosphere to produce other greenhouse gases, when a gas influences the atmospheric lifetimes of other gases, and/or when a gas affects processes that alter the atmospheric radiative balance of the earth. A relative scaling factor has been developed so that different gases can be reported in a common format. Global Warming Potential (GWP) is the index that has been developed to compare different GHGs on a common reporting basis. CO 2 is used as the reference gas to compare the ability of a particular gas to trap atmospheric heat relative to CO 2. The Intergovernmental Panel on Climate Change (IPCC) defines GWP as the ratio of the time-integrated radiative forcing from the instantaneous release of 1 kg of a substance relative to 1 kg of the reference gas (i.e., GWP is weight-based, not volume-based). Thus, GHG emissions are commonly reported as CO 2 equivalents (e.g., tonnes of CO 2 eq, where a tonne is 1000 kg). As noted above, the GWP is a timeintegrated factor; thus the GWP for a particular gas depends upon the time period selected. A 100-2

9 year GWP is the standard that has been broadly adopted for GHG reporting, and will serve as the basis for the AGA GHG Guidelines. GWP values are listed in Table 1-1 for the three GHGs reported for natural gas systems along with some common hydro fluorocarbons and per fluorocarbons, and sulfur hexafluoride. The GWPs in Table 1-1 are from the IPCC 1995 Second Assessment Report (SAR) [IPCC 1995]. In 2001, the IPCC Third Assessment Report (TAR) was adopted [IPCC 2001]. The TAR updated the GWPs based on the most recent scientific data. This update included a revision to the radiative forcing effect of CO 2. Since CO 2 is the reference gas, other GWPs were affected by this change. Additional data and information based on a specific GHG could also affect its GWP. The SAR and TAR GWPs for CO 2, methane, and N 2 O 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 HFC-125 2,800 HFC-134a 1,300 HFC-143a 3,800 HFC-236fa 6,300 CF 4 6,500 C 2 F 6 9,200 C 4 F 10 7,000 C 6 F 14 7,400 SF 6 23,900 Table 1-2. GWP (100-year) for CO 2, Methane, and N 2 O from 1995 SAR and 2001 TAR Greenhouse Gas GWP (SAR) GWP (TAR) Carbon Dioxide 1 1 Methane Nitrous Oxide The updated (TAR) GWPs have not been commonly applied in inventories and reporting protocols to date, and international convention and typical U.S. voluntary programs rely on the 3

10 SAR values for GHG reporting. The DOE 1605b program is one example that uses the updated TAR values. For the purposes of this document, the GWPs from the original 1995 SAR will be used. If the reporting convention changes, this can be readily addressed in an inventory by updating the methane and N 2 O GWP conversion factors. Regarding the contribution of gases considered for natural gas systems, carbon dioxide is a direct emission from combustion sources, and from natural gas leaks because a small fraction of natural gas is CO 2. Carbon dioxide also results from the soil oxidation of methane from underground pipe leaks. An inventory may also include indirect CO 2 emissions, from fuel combustion to generate electricity used by the company The primary challenge in developing a GHG inventory for the natural gas distribution sector is estimating methane emissions, which are especially important due to the methane GWP and the fact that natural gas is primarily composed of 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 TAR indicates that CO 2 currently accounts for 55 percent of the atmospheric radiative forcing attributed to GHGs. Gases other than CO 2 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 CO 2 produced by the oxidation of non methane volatile organic compounds (NMVOC) in the atmosphere has not been included in many estimation methodologies and is not contained within this document. If reporting related to NMVOCs advances, this can be addressed in future updates to the AGA GHG Guidelines. NMVOCs represent a very small portion of the natural gas distribution sector emissions. In addition, NMVOCs do not represent a single molecular species, but are a wide range of volatile hydrocarbon species with varying molecular weights and carbon contents. Therefore, an accurate estimate of indirect emissions of CO 2 from atmospheric NMVOC oxidation requires a gas stream chemical speciation profile. The latest IPCC documentation seeks to include other hydrocarbon emissions by accounting for the carbon content by species profile (percent carbon in NMVOC by mass) multiplied by the carbon dioxide to carbon molecular weight ratio. 1.3 Natural Gas Distribution Sector Overview Figure 1-1 shows the four primary sectors for the natural gas industry production, processing, transmission and storage, and distribution. The distribution sector receives, from transmission pipelines, processed natural gas that has a high methane content, low heavier hydrocarbons concentrations, and very low levels of impurities. Custody transfer from the transmission company 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 gas flow rate and reduces the gas pressure. Heaters are often employed at M&R stations to compensate for temperature decreases caused by pressure reductions. In addition, methyl mercaptans are typically added to the gas as an odorant at the M&R station so that downstream gas leaks are more readily detected due to the pungent smell. The gas then flows through a series of pipeline mains, additional M&R stations and pressure regulating stations, and finally lower pressure service pipelines that connect the mains to industrial, commercial, and residential customers. Customer s gas use is measured by individual customer meters. 4

11 Production Processing Transmission/ Storage Compressor Stations Direct Sales Distribution Main and M&R Service Pipelines Stations Surface Facilities Gas Plant C Pipelines Gas Liquids C Pipelines Liquids Storage C Customer Meters Underground Storage Reservoir C Compressor M Meter Pressure Regulator Figure 1-1. Natural gas industry sector diagram. Figure 1-2. City Gate M&R station schematic. 5

12 1.4 Considerations for Future GHG Guidelines Updates: Current Programs to Advance the State-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 emission sources from the City Gate M&R stations to the customer meters. The GHG Guidelines do not consider liquefied natural gas (LNG) systems and associated equipment such as vaporizers. LNG operations have typically been associated with natural gas transmission and storage systems. The U.S. Environmental Protection Agency (EPA), in conjunction with industry associations (i.e. AGA, American Petroleum Institute, Interstate Natural Gas Association of America), is currently planning a program to develop emission characterization procedures for LNG operations. These procedures could be incorporated into future versions of the AGA GHG Guidelines 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 current state of the art for GHG estimates from distribution systems. In general, the primary reference for GHG emission factors from the distribution sector is a 1996 GRI/EPA study titled Methane Emissions from the Natural Gas Industry [GRI/EPA 1996]. This study is dated and may no longer be representative of standard distribution sector practices, operations, or industry averages. In addition, based on emission factor groupings, very limited data for some emission factors and data assimilation into the factors, the estimated methane losses from this sector are believed to be significantly overestimated. A separate project is currently evaluating and prioritizing emission sources and factors for distribution and is expected to culminate in 2008 in improved emission factors with reduced uncertainty for key distribution sector GHG sources. As the GHG inventory process continues to grow and mature, documentation to support assumptions & preferred methodologies, data sources, quality assurance and quality control practices, audit procedures and requirements, emission trading elements, and policy and issue considerations are likely to become more standardized. A standardized process will enhance consistency, comparability, and conformance of future inventories for this sector. Review and updates to this guideline consistent with industry practices and standards should be conducted consistent with this programmatic evolution. 6

13 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 of main pipeline, number of M&R stations), or more specific (e.g., number of plastic pipeline services, number of gas-driven pneumatic control loops in an M&R station). Some emissions estimates may be based on engineering data and/or a mass balance approach. These approaches are typically more accurate than an emission factor approach, but usually require a level of effort and cost that exceeds current accepted practices. These approaches can be used at the operator s discretion, 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 the various distribution sector emission sources. Practitioners and inventory managers will need to identify the methodology appropriate to meet their inventory objectives considering the availability of activity data and information for engineering estimates. Emission rates are then determined 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 the implementation approach for preparing a rolled up inventory, and define responsibilities for compiling and inputting activity data, documenting the data sources and assumptions, calculating emissions, 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 the facility-level (i.e., a decentralized approach) or corporate-level (centralized approach). If company-wide activity data cannot be collected at a corporate level, data from individual business units, operating units, facilities, and field locations may be required to populate the activity data input fields. In such a case, a common input template should be developed to ensure consistency. Either is acceptable and proper quality control of input data and emission aggregations should be instituted in either case. In addition, a plan should be developed for recordkeeping and supporting documentation for both the 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 calculation approach has been commonly applied based on varying levels of detail associated with user input 7

14 data on equipment and processes. Higher tier emission estimates require more detailed activity data and generate emission estimates with better accuracy and precision. Tier 1 represents the most broad emissions estimate and requires the least input information. Tier 2 and Tier 3 require progressively more data, but result in a higher quality GHG inventory and typically a less conservative 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 an individual source category for a specific GHG. Emission factors provided in Tiers 1 through 3 are general/average factors, with higher accuracy achieved as the input data becomes more detailed. The Tier-based hierarchy can be described as follows: Tier 1: General estimate with minimal inputs required (e.g., emission factor based on miles of pipeline used to estimate the GHG inventory). Tier 2: Data requirements and emission factors based on facility level data or the largest emission sources at a site. Tier 3: Data requirements and emissions based on process operation or equipment level information at a site. Additional Tiers (e.g., Tier 3+, Tier 4, and beyond) involve emission determinations that require additional data and higher costs for inventory development. Migration beyond Tier 3 estimates will occur over time as improvements in measurements and estimate accuracy progresses. These estimates will require detailed process and equipment input data in conjunction with site-specific emission factor data. These approaches are usually beyond the current practices for inventory development and are typically founded on equipment-specific measurements rather than more generic source-type emission factors. The approaches also require thorough documentation to ensure that an external reviewer/auditor can understand and 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 process inputs to complete a calculation. In general, Tier 1 estimates are very qualitative and have little practical application in development of a comprehensive GHG inventory. They are only intended for a relative magnitude estimate (e.g. national inventories prepared by third parties in the absence of activity data) and are not considered robust estimates. Tier 2 estimates also are not considered to be robust estimates, but rather indicators. In summary, Tier 1 and 2 offer the lowest fidelity estimates with the largest uncertainties, and in most cases provide more conservative 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 nitrous oxide) per unit of activity data, where the activity data are typically a process rate or equipment count (e.g. lb of CO 2 per MMBtu of natural gas combusted, kg of methane leaked per mile of cast iron main pipeline.) The emission factors presented in Sections 3 through 6 are a compilation of the most current factors in the literature. The emission factors review was conducted in a recent joint Interstate Natural Gas Association of America (INGAA), American 8

15 Petroleum Institute (API), and AGA study [INGAA/API/AGA 2005]. The primary project objectives 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 an improved 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-1990 s 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. These documents in turn referenced over 60 other publications. Emission factors for natural gas systems were compiled and compared for like/common sources to determine, if possible, the basis for any differences and to recommend preferred emission factors and identify situations where 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 gas distribution because combustion sources are common to a wide range of industries and applications. Published data and emission factors for vented and fugitive emission sources specific to the natural gas industry distribution sector were limited to the 1996 EPA/GRI Study and similar vintage Canadian studies; thus, as noted above, all the vented and fugitive emission factors 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 the factor depends upon both the application and the technical limitations associated with the dataset that 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, combustion CO 2 emission factors have a relatively high accuracy due to the relative simplicity and direct activity data basis for combustion CO 2 emissions determination, while fugitive methane emissions have a higher uncertainty due to the complexity of directly measuring fugitive emissions and relating to an appropriate activity data basis. In these cases, combustion emissions can be related directly to more precise data such as facility or equipment fuel use, while fugitive emission factors are presented relative to typical types of equipment in terms of emissions per equipment count. The GHG Guidelines are not intended to limit the ability of a company to use emission factors or emission 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 the emission factor. If circumstances indicate an issue with available emission factors (or estimation method) for a particular application, the company can choose to use an alternative to the published emission factors such as site-specific data. In this circumstance, the inventory should document the estimate basis and include a qualitative assessment that explains the rationale for using an alternative to the default emission factors. 9

16 2.4 Activity Data The level of effort required for a company to compile an inventory will be most significantly affected by the desired estimate fidelity and quality and the availability of activity data associated with company processes and equipment. Multiple estimation methods are provided for all processes in the GHG Guidelines. For example, multiple tiers are available, and some processes provide more than one estimation methodology for a Tier 2 or Tier 3 estimate. Based on available activity data and the data quality, a company can decide which estimation approach most effectively meets its needs. Regardless of the tier or estimation method selected, a certain amount of source and activity data must be collected to support inventory development. Activity data compilation may be aided through 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 reliable and efficient means of developing accurate facility equipment counts, pipeline length and material, throughput, operating hours, etc. should be developed and memorialized to ensure consistency in year-to-year inventory management. Data collection concerns include inventory completeness, accuracy (i.e., eliminate double counting and transcription errors), emission factor and activity data matching, and documentation and recordkeeping. This generally requires the active engagement of personnel with a good working knowledge of the equipment and facilities involved, and of the associated operations 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 sections that follow. In compiling activity data for inventory development, a company should consider not only the current inventory (e.g., the initial inventory), but also the procedures that are necessary to ensure efficient collection of the same data in subsequent years. In developing initial inventories, activity data deficiencies or gaps should be identified so that process improvements can be considered for subsequent or updated inventories. 10

17 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 estimation process, 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 to develop the emission factor; and Uncertainty in the GWP (based on IPCC (2001), uncertainty for GWP values with a 100 year basis is ± 35% on a global average basis). The first two items are likely to be the greatest sources of error, although all are potentially noteworthy. Within the GHG literature, some emission factor tables present "precision" values, which are not reported in this document. Typically, the precision reported is a statistical evaluation from the dataset 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 the emissions 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 company s similar source; and GWP uncertainty. In addition, this uncertainty is only associated with the emission factor and does not consider activity 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 factors available in the literature. As GHG programs mature and additional data is available, the ability to include uncertainty estimates will progress, and at some future point in time uncertainty estimates are likely to become a standardized component of the inventory process. However, the current immaturity of GHG emissions reporting does not warrant such consideration. The API Compendium [API 2004] (see Appendix B.4 of that document) provides a discussion on calculating precision values associated with emission factors and also discusses the 11

18 uncertainties associated with activity factors. Readers are referred to that document for specific equations and derivations of precision calculations. The 1996 GRI/EPA Study remains the cornerstone for U.S. natural gas industry methane emissions quantification. Therefore, most of the information regarding problematic sources, emissions data, and emission factors has no equal in published reports. However, the purpose of the GRI/EPA Study was identification of sources and quantification of U.S. national methane emissions. These data were not intended to be used to develop default emission factors or industry averages for the gas industry. This issue is similar to the concept of applying an EPA AP-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 NOx emission limit because of the factor s average nature, and the potential for the generic emission factor to not be representative of the specific equipment of interest. However, this does not imply that precision or uncertainty should not be considered. In developing 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 of equipment) even if only qualitative estimates are available. GHG inventory development is still a relatively new field of endeavor, and estimation of emission factor precision or uncertainty will mature as datasets grow. Thus, while uncertainty estimates have limited utility for the current state of the science for GHG estimation, this will become a fundamental part of GHG development and reporting in the future. Currently, where available, the activity data precision can be identified and documented during inventory compilation. This will ensure that a company s documentation is complete, and this precision value will likely be important in future-year inventories when it can be used with improved emission factor precision statistics to 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 subjective component (e.g., precision in a default emission factor may reflect an attempt to address whether the dataset is representative of the at-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. CH 4 and N 2 O from combustion); Use of average factors not well matched to specific and varied operations (e.g. CO 2 per 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; 12

19 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 emission estimates are both important factors to consider when developing a strategy for inventory improvement. In general, the procedures documented in this guideline document represent a range 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., the materiality 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 World Resources Institute/World Business Council on Sustainable Development (WRI/WBCSD) GHG Protocol [WRI/WBCSD 2004] (hereafter referred to as the WRI/WBCSD GHG Protocol) offers this perspective on materiality thresholds: Sometimes it is tempting to define a minimum emissions accounting threshold (often referred to as a materiality threshold) stating that a source not exceeding a certain size can be omitted from the inventory. Technically, such a threshold is simply a predefined and accepted negative bias in estimates (i.e., an underestimate). Although it appears useful in theory, the practical implementation of such a threshold is not compatible with the completeness principle of the WRI/WBCSD GHG Protocol Corporate Standard. In order to utilize a materiality specification, the emissions from a particular source or activity would have to be quantified to ensure they were under the threshold. However, once emissions are quantified, 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 discrepancy or not. This is not the same as a de minimis for defining a complete inventory. Instead companies need to make a good faith effort to provide a complete, accurate, and consistent accounting of their GHG emissions. For cases where emissions have not been estimated, or 13

20 estimated at an insufficient level of quality, it is important that this is transparently documented and justified. Verifiers can determine the potential impact and relevance of the exclusion, 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 report smaller emissions sources; Once a calculation is competed and compared to a threshold, the burden in adding the emissions to the reported inventory is extremely small; Depending upon the threshold basis, it will likely establish varying significance levels for larger and smaller companies; and For any mandated reporting, a materiality threshold may be a necessity to identify the need to report: for a small source; for a discovered inventory error; or, to define a significance level for activities or equipment that are established as trivial. The AGA GHG Guidelines do not identify a pre-established materiality threshold, as this value judgment is best addressed within the context of the inventory goals and intended use. In addition, if the inventory is to be used for a particular reporting program or registry, that program may include either a pre-defined threshold or ground rules associated with both de minimis emissions and minor errors. 2.7 Direct Emissions The majority of GHG emissions from natural gas distribution equipment and processes are direct emissions. Direct emissions include combustion, vented, fugitive, and mobile source emissions directly 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 discussed above. Direct emission sources are discussed in the subsections below Combustion Emissions Emissions of CO 2, methane, and N 2 O from combustion sources, including: Pipeline heaters; IC engine and gas turbine generators and compressors; and Facility boilers 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 under fugitives for IPCC and some other reporting guidelines. These emissions comprise a significant portion of GHG emissions from distribution. Potential emission sources include: Pneumatic devices (isolation valves and control loops); and 14

21 Purge or blowdown from routine operations or upsets, including: Pipeline venting; M&R station venting; and Maintenance and inspection Fugitive Emissions Fugitive GHG emissions are methane leaks from pipelines and system components such as valve packing, flanges, and other piping connectors. The emission sources and activity factor basis for fugitive emissions are based upon primary equipment that includes subcomponents, such as: Piping and associated components; M&R stations; and Customer meters Mobile Source Emissions Mobile sources combustion emissions of CO 2, methane, and N 2 O 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 third party. This requirement is common for many reporting programs. Reporting protocols such as the WRI/WBCSD GHG Protocol and International Petroleum Industry Environmental Conservation Association (IPIECA), Petroleum Industry Guidelines for Reporting Greenhouse Gas Emissions [IPIECA 2003] (hereafter referred to as the IPIECA Guidelines) include additional background on indirect emissions from purchased power. Indirect emissions should be reported separately from direct emissions in company reports. Section 6.1 includes methods for estimating indirect emissions. While indirect emissions can be a substantial emission source for some industrial sectors, this is typically not the case for gas distribution. In general, reporting indirect emissions from electricity helps provide a more complete picture of company emissions, provides an understanding of opportunities available for GHG reductions from energy efficiency, and assists in the understanding of tradeoffs between onsite power generation and purchased electricity. In addition, indirect purchased power emissions are typically required for current voluntary reporting programs. 2.9 Optional Emissions Another type of emissions, which are typically comprised of additional indirect emission sources, is optional emissions. These are referred to as Scope 3 emissions in the 15

22 WRI/WBCSD GHG Protocol. Examples include: transportation related activities such as employee 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, and combustion emissions include CO 2, CH 4, and N 2 O. CO 2 is formed from fuel carbon oxidation, CH 4 is a product of incomplete combustion typically CH 4 in the fuel escapes oxidation, and N 2 O 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 combustion sources 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 most prevalent combustion sources throughout the natural gas industry, primarily used for gas compression. In the distribution sector, most companies do not further compress the gas after custody transfer from the transmission pipeline; however, gas turbines and IC engines may be used by distribution companies for power generation. Pipeline heaters are often the most common combustion emissions source. For other combustion sources not listed or presented here, and cannot follow the calculation methodologies outlined below, the reader is referred to either the API Compendium or the INGAA Greenhouse Gas Emission Estimation Guidelines For Natural Gas Transmission And Storage; Volume 1 Emissions Estimation Methodologies And Procedures. Note that mobile source emissions from combustion (i.e., fleet vehicles and construction equipment) are included in Section Combustion Emissions Estimation Methodologies Overview GHG emissions from a single combustion source or group of sources (facility) can be directly measured (e.g. CO 2 emissions can be determined from the fuel carbon content and mass flow rate) or they can be estimated from a source-specific emission factor (EF) and corresponding activity data (AD). The general equation for this estimation is: Emissions GHG (mass/unit time) = AD * EF Eqn