Technical Support Document (TSD)

Preparation of Emissions Inventories for the Version 6.2, 

2011 Emissions Modeling Platform

August, 2015

U.S. Environmental Protection Agency

Office of Air and Radiation

Office of Air Quality Planning and Standards

Air Quality Assessment Division

Contacts: 

Alison Eyth, Jeff Vukovich 
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TABLE OF CONTENTS

LIST OF TABLES ...........................................................................................................................................................IV

LIST OF FIGURES..........................................................................................................................................................VI

LIST OF APPENDICES ................................................................................................................................................ VII

ACRONYMS.................................................................................................................................................................. VII

1 INTRODUCTION.....................................................................................................................................................1

2 2011 EMISSION INVENTORIES AND APPROACHES........................................................................................5

2.1 2011 NEI POINT SOURCES (PTEGU, PT_OILGAS AND PTNONIPM).................................................................................9

2.1.1 EGU sector (ptegu)........................................................................................................................................9

2.1.2 Point source oil and gas sector (pt_oilgas)................................................................................................... 12

2.1.3 Non-IPM sector (ptnonipm)......................................................................................................................... 12

2.2 2011 NONPOINT SOURCES (AFDUST, AG, AGFIRE, NP_OILGAS, RWC, NONPT).............................................................. 13

2.2.1 Area fugitive dust sector (afdust).................................................................................................................. 14

2.2.2 Agricultural ammonia sector (ag) ................................................................................................................ 18

2.2.3 Agricultural fires (agfire)............................................................................................................................. 19

2.2.4 Nonpoint source oil and gas sector (np_oilgas)............................................................................................ 19

2.2.5 Residential wood combustion sector (rwc) ................................................................................................... 20

2.2.6 Other nonpoint sources sector (nonpt) ......................................................................................................... 20

2.3 2011 ONROAD MOBILE SOURCES (ONROAD) ............................................................................................................ 21

2.3.1 Onroad (onroad) ......................................................................................................................................... 21

2.4 2011 NONROAD MOBILE SOURCES (C1C2RAIL, C3MARINE, NONROAD)...................................................................... 24

2.4.1 Category 1/Category 2 Commercial Marine Vessels and Locomotives and (c1c2rail) ................................... 24

2.4.2 Category 3 commercial marine vessels (c3marine)....................................................................................... 25

2.4.3 Nonroad mobile equipment sources: (nonroad)............................................................................................ 27

2.5 “OTHER EMISSIONS”: OFFSHORE CATEGORY 3 COMMERCIAL MARINE VESSELS AND DRILLING PLATFORMS AND NON-U.S.

SOURCES ........................................................................................................................................................................ 28

2.5.1 Point sources from offshore C3 CMV, drilling platforms, Canada and Mexico (othpt) .................................. 28

2.5.2 Area and nonroad mobile sources from Canada and Mexico (othar, othafdust) ............................................ 28

2.5.3 Onroad mobile sources from Canada and Mexico (othon)............................................................................ 29

2.6 FIRES (PTWILDFIRE, PTPRESCFIRE).......................................................................................................................... 29

2.7 BIOGENIC SOURCES (BEIS) ..................................................................................................................................... 31

2.8 SMOKE-READY NON-ANTHROPOGENIC INVENTORIES FOR CHLORINE...................................................................... 33

3 EMISSIONS MODELING SUMMARY ................................................................................................................ 34

3.1 EMISSIONS MODELING OVERVIEW.......................................................................................................................... 34

3.2 CHEMICAL SPECIATION ......................................................................................................................................... 38

3.2.1 VOC speciation ........................................................................................................................................... 41

3.2.1.1 The combination of HAP BAFM (benzene, acetaldehyde, formaldehyde and methanol) and VOC for VOC speciation42

3.2.1.2 County specific profile combinations (GSPRO_COMBO).........................................................................................44

3.2.1.3 Additional sector specific details ..............................................................................................................................45

3.2.1.4 Future year speciation ..............................................................................................................................................49

3.2.2 PM speciation ............................................................................................................................................. 53

3.2.3 NOX speciation............................................................................................................................................ 55

3.3 TEMPORAL ALLOCATION ....................................................................................................................................... 55

3.3.1 Use of FF10 format for finer than annual emissions..................................................................................... 57

3.3.2 Electric Generating Utility temporalization (ptegu)...................................................................................... 57

3.3.2.1 Base year temporal allocation of EGUs.....................................................................................................................57

3.3.2.2 Future year temporal allocation of EGUs..................................................................................................................60

3.3.3 Residential Wood Combustion Temporalization (rwc) .................................................................................. 66

3.3.4 Agricultural Ammonia Temporal Profiles (ag) ............................................................................................. 70

3.3.5 Onroad mobile temporalization (onroad)..................................................................................................... 71

3.3.6 Additional sector specific details (afdust, beis, c1c2rail, c3marine, nonpt, ptnonipm, ptfire, np_oilgas)......... 77
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3.4 SPATIAL ALLOCATION........................................................................................................................................... 79

3.4.1 Spatial Surrogates for U.S. emissions........................................................................................................... 79

3.4.2 Allocation method for airport-related sources in the U.S. ............................................................................. 85

3.4.3 Surrogates for Canada and Mexico emission inventories.............................................................................. 85

4 DEVELOPMENT OF 2017 AND 2025 BASE-CASE EMISSIONS....................................................................... 89

4.1 EGU SECTOR PROJECTIONS: PTEGU ........................................................................................................................ 94

4.2 NON-EGU POINT AND NEI NONPOINT SECTOR PROJECTIONS: AFDUST, AG, C1C2RAIL, C3MARINE, NONPT, NP_OILGAS,

PTNONIPM, PT_OILGAS, RWC ........................................................................................................................................... 95

4.2.1 CoST Background: Used for NEI non-EGU Point and Nonpoint sectors....................................................... 96

4.2.2 CoST Plant CLOSURE packet (ptnonipm, pt_oilgas).................................................................................. 100

4.2.3 CoST PROJECTION packets (afdust, ag, c1c2rail, c3marine, nonpt, np_oilgas, ptnonipm, pt_oilgas, rwc) . 101

4.2.3.1 Paved and unpaved roads VMT growth (afdust)......................................................................................................101

4.2.3.2 Livestock population growth (ag) ...........................................................................................................................101

4.2.3.3 Locomotives and Category 1 & 2 commercial marine vessels (c1c2rail, ptnonipm) ..................................................102

4.2.3.4 Category 3 commercial marine vessels (c3marine, othpt) ........................................................................................104

4.2.3.5 Upstream distribution, pipelines and refineries (nonpt, ptnonipm, pt_oilgas)............................................................106

4.2.3.6 Oil and gas and industrial source growth from 2011v6.0 NODA (nonpt, np_oilgas, ptnonipm, pt_oilgas) .................108

Natural Gas Consumption and Crude Oil Production.............................................................................................................114

Other Fuels...........................................................................................................................................................................114

Oil/Gas Plays .......................................................................................................................................................................115

Remaining Areas...................................................................................................................................................................116

4.2.3.7 Data from comments on previous platforms (nonpt, ptnonipm, pt_oilgas)................................................................119

4.2.3.8 Aircraft (ptnonipm)................................................................................................................................................121

4.2.3.9 Cement manufacturing (ptnonipm) .........................................................................................................................123

4.2.3.10 Corn ethanol plants (ptnonipm) ..............................................................................................................................125

4.2.3.11 Residential wood combustion (rwc)........................................................................................................................126

4.2.4 CoST CONTROL packets (nonpt, np_oilgas, ptnonipm, pt_oilgas).............................................................. 129

4.2.4.1 Oil and gas NSPS (np_oilgas, pt_oilgas).................................................................................................................130

4.2.4.2 RICE NESHAP (nonpt, np_oilgas, ptnonipm, pt_oilgas).........................................................................................131

4.2.4.3 RICE NSPS (nonpt, np_oilgas, ptnonipm, pt_oilgas)...............................................................................................133

4.2.4.4 ICI Boilers (nonpt, ptnonipm, pt_oilgas).................................................................................................................135

4.2.4.5 Fuel sulfur rules (nonpt, ptnonipm, pt_oilgas).........................................................................................................139

4.2.4.6 Natural gas turbines NOX NSPS (ptnonipm, pt_oilgas)............................................................................................140

4.2.4.7 Process heaters NOX NSPS (ptnonipm, pt_oilgas)...................................................................................................142

4.2.4.8 Arizona Regional Haze controls (ptnonipm)............................................................................................................143

4.2.4.9 CISWI (ptnonipm).................................................................................................................................................144

4.2.4.10 Data from comments on previous platforms (nonpt, ptnonipm, pt_oilgas)................................................................144

4.2.5 Stand-alone future year inventories (nonpt, ptnonipm) ............................................................................... 146

4.2.5.1 Portable fuel containers (nonpt)..............................................................................................................................146

4.2.5.2 Biodiesel plants (ptnonipm)....................................................................................................................................147

4.2.5.3 Cellulosic plants (nonpt) ........................................................................................................................................148

4.2.5.4 New cement plants (nonpt, ptnonipm).....................................................................................................................150

4.3 MOBILE SOURCE PROJECTIONS ............................................................................................................................. 151

4.3.1 Onroad mobile (onroad)............................................................................................................................ 151

4.3.1.1 Future activity data ................................................................................................................................................152

4.3.1.2 Set up and Run MOVES to create EFs....................................................................................................................154

4.3.1.3 National and California adjustments .......................................................................................................................155

4.4 NONROAD MOBILE SOURCE PROJECTIONS (NONROAD)........................................................................................... 156

4.5 “OTHER EMISSIONS”: OFFSHORE CATEGORY 3 COMMERCIAL MARINE VESSELS AND DRILLING PLATFORMS, CANADA AND 

MEXICO (OTHPT, OTHAR, AND OTHON) .......................................................................................................................... 157

5 EMISSION SUMMARIES.................................................................................................................................... 159

6 REFERENCES...................................................................................................................................................... 170
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List of Tables

Table 1-1. List of cases in the 2011 Version 6 Emissions Modeling Platform ...............................................2

Table 2-1. Platform sectors for the 2011 emissions modeling platform .........................................................6

Table 2-2. Summary of differences between 2011v6.2 platform and 2011NEIv2 emissions by sector...........8

Table 2-3. Point source oil and gas sector NAICS Codes.............................................................................12

Table 2-4. Corn Ethanol Plant Criteria Pollutant Emission Factors (grams per gallon produced)..................13

Table 2-5. Toxic-to-VOC Ratios for Corn Ethanol Plants...........................................................................13

Table 2-6. SCCs in the afdust platform sector.............................................................................................14

Table 2-7. Total Impact of Fugitive Dust Adjustments to Unadjusted 2011 Inventory.................................15

Table 2-8. Livestock SCCs extracted from the NEI to create the ag sector..................................................18

Table 2-9. Fertilizer SCCs extracted from the NEI for inclusion in the “ag” sector .....................................19

Table 2-10. SCCs in the Residential Wood Combustion Sector (rwc)* .......................................................20

Table 2-11. Onroad emission aggregate processes ......................................................................................23

Table 2-12. 2011NEIv2 SCCs extracted for the starting point in c1c2rail development...............................24

Table 2-13. Growth factors to project the 2002 ECA-IMO inventory to 2011 .............................................25

Table 2-14. 2011 Platform SCCs representing emissions in the ptprescfire and ptwildfire modeling sectors30

Table 2-15. Large fires apportioned to multiple grid cells...........................................................................30

Table 2-16. Meteorological variables required by BEIS 3.61 ......................................................................33

Table 3-1. Key emissions modeling steps by sector. ...................................................................................35

Table 3-2. Descriptions of the platform grids..............................................................................................37

Table 3-3. Emission model species produced for CB6 for CAMX* .............................................................39

Table 3-4. Cmaq2camx mapping file ..........................................................................................................41

Table 3-5. Integration approach for BAFM and EBAFM for each platform sector ......................................44

Table 3-6. MOVES integrated species in M-profiles...................................................................................46

Table 3-7. VOC profiles for WRAP Phase III basins ..................................................................................47

Table 3-8. National VOC profiles for oil and gas........................................................................................47

Table 3-9. Counties included in the WRAP Dataset....................................................................................48

Table 3-10. Select VOC profiles 2011 vs 2017 vs 2025 ..............................................................................50

Table 3-11. Onroad M-profiles...................................................................................................................51

Table 3-12. MOVES Process IDs ...............................................................................................................52

Table 3-13. MOVES Fuel subtype IDs .......................................................................................................53

Table 3-14. MOVES Regclass IDs .............................................................................................................53

Table 3-15. PM model species: AE5 versus AE6 ........................................................................................54

Table 3-16. NOX speciation profiles ...........................................................................................................55

Table 3-17. Temporal settings used for the platform sectors in SMOKE .....................................................56

Table 3-18. U.S. Surrogates available for the 2011 modeling platform........................................................80

Table 3-19. Off-Network Mobile Source Surrogates...................................................................................81

Table 3-20. Spatial Surrogates for Oil and Gas Sources..............................................................................81

Table 3-21. Selected 2011 CAP emissions by sector for U.S. Surrogates* ...................................................82

Table 3-22. Canadian Spatial Surrogates ....................................................................................................86

Table 3-23. CAPs Allocated to Mexican and Canadian Spatial Surrogates...................................................87

Table 4-1. Control strategies and growth assumptions for creating the 2017 and 2025 base-case emissions 

inventories from the 2011 base case.....................................................................................................92

Table 4-2. Subset of CoST Packet Matching Hierarchy ...............................................................................97

Table 4-3. Summary of non-EGU stationary projections subsections...........................................................98

Table 4-4. Reductions from all facility/unit/stack-level closures by modeling sector..................................100

Table 4-5. NH3 projection factors and total impacts to years 2017 and 2025 for animal operations............102

Table 4-6. Non-California projection factors for locomotives and Category 1 and Category 2 Commercial 

Marine Vessel Emissions...................................................................................................................103
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Table 4-7. Difference in c1c2rail sector emissions between 2011 and future years.....................................104

Table 4-8. Growth factors to project the 2011 ECA-IMO inventory to 2017 and 2025 ...............................105

Table 4-9. Difference in c3marine sector and othpt C3 CMV emissions between 2011 and future years ....105

Table 4-10. Petroleum pipelines & refineries and production storage and transport factors and reductions 107

Table 4-11. Sources of new industrial source growth factor data from the 2011v6.0 NODA ......................109

Table 4-12. Summary of “EPA” Projection Approaches for IC Engines/Gas Turbines and ICI Boilers/Process 

Heaters..............................................................................................................................................111

Table 4-13. NAICS Codes for which NAICS/SCC-level Growth Factors were developed .........................112

Table 4-14. AEO Oil/Gas Plays.................................................................................................................114

Table 4-15. Industrial source projections net impacts from 2011v6.0 NODA.............................................118

Table 4-16. Impact of 2011v6.0 projection factors for Texas .....................................................................120

Table 4-17. NEI SCC to FAA TAF ITN aircraft categories used for aircraft projections............................122

Table 4-18. National aircraft emission projection summary .......................................................................123

Table 4-19. U.S. Census Division ISMP-based projection factors for existing kilns...................................125

Table 4-20. ISMP-based cement industry projected emissions...................................................................125

Table 4-21. 2011 and 2017/2025 corn ethanol plant emissions [tons].........................................................126

Table 4-22. Non-West Coast RWC projection factors, including NSPS impacts ........................................128

Table 4-23. Cumulative national RWC emissions from growth, retirements and NSPS impacts.................128

Table 4-24. Assumed retirement rates and new source emission factor ratios for new sources for various 

NSPS rules ........................................................................................................................................130

Table 4-25. NSPS VOC oil and gas reductions from projected pre-control 2018 and 2025 grown values...131

Table 4-26. Summary RICE NESHAP SI and CI percent reductions prior to 2011NEIv2 analysis.............132

Table 4-27. National by-sector reductions from RICE Reconsideration controls (tons) ..............................133

Table 4-28. RICE NSPS Analysis and resulting 2011v6.2 new emission rates used to compute controls....134

Table 4-29. National by-sector reductions from RICE NSPS controls (tons)..............................................135

Table 4-30. Facility types potentially subject to Boiler MACT reductions .................................................136

Table 4-31. National-level, with Wisconsin exceptions, ICI boiler adjustment factors by base fuel type ....138

Table 4-32. New York and New Jersey NOX ICI Boiler Rules that supersede national approach................138

Table 4-33. Summary of ICI Boiler reductions ..........................................................................................138

Table 4-34. State Fuel Oil Sulfur Rules data provided by MANE-VU .......................................................139

Table 4-35. Summary of fuel sulfur rule impacts on SO2 emissions...........................................................140

Table 4-36. Stationary gas turbines NSPS analysis and resulting 2011v6.2 new emission rates used to 

compute controls ...............................................................................................................................141

Table 4-37. National by-sector NOX reductions from Stationary Natural Gas Turbine NSPS controls........142

Table 4-38. Process Heaters NSPS analysis and 2011v6.2 new emission rates used to compute controls ...143

Table 4-39. National by-sector NOX reductions from Process Heaters NSPS controls................................143

Table 4-40. Summary of remaining ptnonipm and pt_oilgas reductions.....................................................145

Table 4-41. PFC emissions for 2011, 2018 and 2025 [tons] .......................................................................147

Table 4-42. Emission Factors for Biodiesel Plants (Tons/Mgal).................................................................147

Table 4-43. 2018/2025 biodiesel plant emissions [tons].............................................................................148

Table 4-44. Criteria Pollutant Emission Factors for Cellulosic Plants (Tons/RIN gallon) ...........................148

Table 4-45. Toxic Emission Factors for Cellulosic Plants (Tons/RIN gallon).............................................149

Table 4-46. 2017/2025 cellulosic plant emissions [tons] ............................................................................149

Table 4-47. New cellulosic plants NOX emissions provided by Iowa DNR. ..............................................149

Table 4-48. Locations of new ISMP-generated cement kilns......................................................................150

Table 4-49. ISMP-generated new permitted and non-permitted emissions .................................................151

Table 4-50. Projection factors for 2018 and 2025 VMT (in millions of miles) ...........................................152

Table 4-51. Inputs for MOVES runs for 2018 and 2025.............................................................................154

Table 4-52. CA LEVIII program states......................................................................................................155

Table 5-1. National by-sector CAP emissions summaries for the 2011 evaluation case ..............................160
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Table 5-2. National by-sector CAP emissions summaries for the 2017 base case .......................................161

Table 5-3. National by-sector CAP emissions summaries for the 2025 base case .......................................162

Table 5-4. National by-sector CO emissions (tons/yr) summaries and percent change ...............................163

Table 5-5. National by-sector NH3 emissions (tons/yr) summaries and percent change ..............................164

Table 5-6. National by-sector NOx emissions (tons/yr) summaries and percent change ..............................165

Table 5-7. National by-sector PM2.5 emissions (tons/yr) summaries and percent change ............................166

Table 5-8. National by-sector PM10 emissions (tons/yr) summaries and percent change.............................167

Table 5-9. National by-sector SO2 emissions (tons/yr) summaries and percent change...............................168

Table 5-10. National by-sector VOC emissions (tons/yr) summaries and percent change ...........................169

List of Figures

Figure 2-1. Impact of adjustments to fugitive dust emissions due to transport fraction, precipitation, and 

cumulative ...........................................................................................................................................17

Figure 2-2. Illustration of regional modeling domains in ECA-IMO study..................................................26

Figure 2-3. Annual NO emissions output from BEIS 3.61 for 2011 ............................................................32

Figure 2-4. Annual isoprene emissions output from BEIS 3.61 for 2011.....................................................32

Figure 3-1. Air quality modeling domains ...................................................................................................37

Figure 3-2. Process of integrating BAFM with VOC for use in VOC Speciation.........................................43

Figure 3-3. Eliminating unmeasured spikes in CEMS data..........................................................................58

Figure 3-4. Seasonal diurnal profiles for EGU emissions in a Virginia Region............................................58

Figure 3-5. IPM Regions for EPA Base Case v5.14 ....................................................................................59

Figure 3-6. Month-to-day profiles for different fuels in a West Texas Region.............................................60

Figure 3-7. Future year emissions follow pattern of base year emissions.....................................................64

Figure 3-8. Excess emissions apportioned to hours less than maximum ......................................................64

Figure 3-9. Adjustment to Hours Less than Maximum not Possible, Regional Profile Applied....................65

Figure 3-10. Regional Profile Applied, but Exceeds Maximum in Some Hours ..........................................66

Figure 3-11. Example of RWC temporalization in 2007 using a 50 versus 60  ̊F threshold..........................67

Figure 3-12. RWC diurnal temporal profile ................................................................................................68

Figure 3-13. Diurnal profile for OHH, based on heat load (BTU/hr) ...........................................................69

Figure 3-14. Day-of-week temporal profiles for OHH and Recreational RWC............................................69

Figure 3-15. Annual-to-month temporal profiles for OHH and recreational RWC.......................................70

Figure 3-16. Example of animal NH3 emissions temporalization approach, summed to daily emissions......71

Figure 3-17. Example of SMOKE-MOVES temporal variability of NOX emissions....................................72

Figure 3-18. Previous onroad diurnal weekday profiles for urban roads......................................................73

Figure 3-19. Use of submitted versus new national default profiles.............................................................74

Figure 3-20. Updated national default profiles for LDGV vs. HHDDV, urban restricted.............................75

Figure 3-21. Updated national default profiles for day of week ...................................................................76

Figure 3-22. Combination long-haul truck restricted and hoteling profile....................................................77

Figure 3-23. Agricultural burning diurnal temporal profile .........................................................................78

Figure 4-1. Oil and gas plays with AEO projection data ............................................................................116

Figure 4-2. Oil and Gas NEMS Regions....................................................................................................117

Figure 4-3. Cement sector trends in domestic production versus normalized emissions..............................124

Figure 4-4. Light Duty VMT growth rates................................................................................................154
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List of Appendices

Appendix A: Nonpoint Oil and Gas NEI SCCs

Appendix B: Mapping of Fuel Distribution SCCs to BTP, BPS and RBT

Appendix C: Future Animal Population Projection Methodology

Acronyms

AE5 CMAQ Aerosol Module, version 5, introduced in CMAQ v4.7

AE6 CMAQ Aerosol Module, version 6, introduced in CMAQ v5.0

AEO Annual Energy Outlook

BAFM Benzene, Acetaldehyde, Formaldehyde and Methanol

BEIS Biogenic Emissions Inventory System

BELD Biogenic Emissions Land use Database

Bgal Billion gallons

BPS Bulk Plant Storage

BTP Bulk Terminal (Plant) to Pump

C1/C2 Category 1 and 2 commercial marine vessels

C3 Category 3 (commercial marine vessels)

CAEP Committee on Aviation Environmental Protection

CAIR Clean Air Interstate Rule

CAMD EPA’s Clean Air Markets Division

CAMX Comprehensive Air Quality Model with Extensions

CAP Criteria Air Pollutant

CARB California Air Resources Board

CB05 Carbon Bond 2005 chemical mechanism

CBM Coal-bed methane

CEC North American Commission for Environmental Cooperation

CEMS Continuous Emissions Monitoring System

CEPAM California Emissions Projection Analysis Model

CISWI Commercial and Industrial Solid Waste Incineration

Cl Chlorine

CMAQ Community Multiscale Air Quality

CMV Commercial Marine Vessel

CO Carbon monoxide

CSAPR Cross-State Air Pollution Rule

E0, E10, E85 0%, 10% and 85% Ethanol blend gasoline, respectively

EBAFM Ethanol, Benzene, Acetaldehyde, Formaldehyde and Methanol

ECA Emissions Control Area

EEZ Exclusive Economic Zone

EF Emission Factor

EGU Electric Generating Units

EIS Emissions Inventory System

EISA Energy Independence and Security Act of 2007

EPA Environmental Protection Agency

EMFAC Emission Factor (California’s onroad mobile model)

FAA Federal Aviation Administration
viii

FAPRI Food and Agriculture Policy and Research Institute

FASOM Forest and Agricultural Section Optimization Model

FCCS Fuel Characteristic Classification System

FF10 Flat File 2010

FIPS Federal Information Processing Standards

FHWA Federal Highway Administration

HAP Hazardous Air Pollutant

HCl Hydrochloric acid

HDGHG Heavy-Duty Vehicle Greenhouse Gas

Hg Mercury

HMS Hazard Mapping System

HPMS Highway Performance Monitoring System

HWC Hazardous Waste Combustion

HWI Hazardous Waste Incineration

ICAO International Civil Aviation Organization

ICI Industrial/Commercial/Institutional (boilers and process heaters)

ICR Information Collection Request 

IDA Inventory Data Analyzer

I/M Inspection and Maintenance

IMO International Marine Organization

IPAMS Independent Petroleum Association of Mountain States

IPM Integrated Planning Model

ITN Itinerant 

LADCO Lake Michigan Air Directors Consortium

LDGHG Light-Duty Vehicle Greenhouse Gas

LPG Liquefied Petroleum Gas

MACT Maximum Achievable Control Technology

MARAMA Mid-Atlantic Regional Air Management Association

MATS Mercury and Air Toxics Standards

MCIP Meteorology-Chemistry Interface Processor

Mgal Million gallons

MMS Minerals Management Service (now known as the Bureau of Energy 

Management, Regulation and Enforcement (BOEMRE)

MOVES Motor Vehicle Emissions Simulator

MSA Metropolitan Statistical Area

MSAT2 Mobile Source Air Toxics Rule

MTBE Methyl tert-butyl ether

MWRPO Mid-west Regional Planning Organization

NCD National County Database

NEEDS National Electric Energy Database System

NEI National Emission Inventory

NESCAUM Northeast States for Coordinated Air Use Management

NESHAP National Emission Standards for Hazardous Air Pollutants

NH3 Ammonia

NIF NEI Input Format

NLCD National Land Cover Database

NLEV National Low Emission Vehicle program

nm nautical mile

NMIM National Mobile Inventory Model

NOAA National Oceanic and Atmospheric Administration
ix

NODA Notice of Data Availability

NONROAD OTAQ’s model for estimation of nonroad mobile emissions

NOX Nitrogen oxides

NSPS New Source Performance Standards

NSR New Source Review

OAQPS EPA’s Office of Air Quality Planning and Standards

OHH Outdoor Hydronic Heater

OTAQ EPA’s Office of Transportation and Air Quality

ORIS Office of Regulatory Information System

ORD EPA’s Office of Research and Development

ORL One Record per Line

OTC Ozone Transport Commission

PADD Petroleum Administration for Defense Districts

PF Projection Factor, can account for growth and/or controls

PFC Portable Fuel Container

PM2.5 Particulate matter less than or equal to 2.5 microns

PM10 Particulate matter less than or equal to 10 microns

ppb, ppm Parts per billion, parts per million

RBT Refinery to Bulk Terminal

RFS2 Renewable Fuel Standard

RIA Regulatory Impact Analysis

RICE Reciprocating Internal Combustion Engine

RRF Relative Response Factor

RWC Residential Wood Combustion

RPO Regional Planning Organization

RVP Reid Vapor Pressure

SCC Source Classification Code

SEMAP Southeastern Modeling, Analysis, and Planning

SESARM Southeastern States Air Resource Managers

SESQ Sesquiterpenes

SMARTFIRE Satellite Mapping Automated Reanalysis Tool for Fire Incident Reconciliation

SMOKE Sparse Matrix Operator Kernel Emissions

SO2 Sulfur dioxide

SOA Secondary Organic Aerosol

SI Spark-ignition

SIP State Implementation Plan

SPDPRO Hourly Speed Profiles for weekday versus weekend

SPPD Sector Policies and Programs Division

TAF Terminal Area Forecast 

TCEQ Texas Commission on Environmental Quality

TOG Total Organic Gas

TSD Technical support document

ULSD Ultra Low Sulfur Diesel

USDA United States Department of Agriculture

VOC Volatile organic compounds

VMT Vehicle miles traveled

VPOP Vehicle Population

WRAP Western Regional Air Partnership

WRF Weather Research and Forecasting Model
1

1 Introduction

The U.S. Environmental Protection Agency (EPA) developed an air quality modeling platform for 2011 

based on the 2011 National Emissions Inventory, version 2 (2011NEIv2). The air quality modeling 

platform consists of all the emissions inventories and ancillary data files used for emissions modeling, as 

well as the meteorological, initial condition, and boundary condition files needed to run the air quality 

model. This document focuses on the emissions modeling component of the 2011 modeling platform, 

which includes the emission inventories, the ancillary data files, and the approaches used to transform 

inventories for use in air quality modeling. Many emissions inventory components of this air quality 

modeling platform are based on the 2011NEIv2, although there are some differences between the 

platform inventories and the 2011NEIv2 emissions.

This 2011 modeling platform includes all criteria air pollutants and precursors (CAPs) and the following 

hazardous air pollutants (HAPs): chlorine (Cl), hydrogen chloride (HCl), benzene, acetaldehyde, 

formaldehyde and methanol. The latter four HAPs are also abbreviated as BAFM. This platform is called 

the “CAP-BAFM 2011-Based Platform, version 6.2” because it is primarily a CAP platform with BAFM 

species included. Here, “version 6.2” denotes an evolution from the 2011-based platform, version 6.0, 

with improvements due to the use of newer data and methods. For the rest of this document, the platform 

that is described is referred to as the “2011 v6.2 platform” or “2011v6.2”. 

The 2011v6.2 platform was used to support ozone transport modeling for the 2008 National Ambient Air 

Quality Standards (NAAQS), the 2015 NAAQS for ozone, along with other special studies. The air 

quality model used for these rules is the Comprehensive Air Quality Model with Extensions (CAMX) 

model (http://www.camx.com/), version 6.10. However, emissions are first processed into a format 

compatible with for the Community Multiscale Air Quality (CMAQ) model 

(http://www.epa.gov/AMD/CMAQ/CMAQdocumentation.html), version 5.0.2 and those emissions are

converted to CAMX-ready format. The 2011 National Air Toxics Assessment (NATA) was developed 

using a similar modeling platform with some variations such as a focus on toxic air pollutants and will be

described in the Technical Support Document (TSD) “EPA’s 2011 National-Scale Air Toxics 

Assessment”. 

Both CAMX and CMAQ support modeling ozone (O3) and particulate matter (PM), and require as input 

hourly and gridded emissions of chemical species that correspond to CAPs and specific HAPs. The 

chemical mechanism used by CAMX for this platform is called Carbon Bond version 6 revision 2 (CB6r2) 

and includes important reactions for simulating ozone formation, NOx cycling, and formation of 

secondary aerosol species (Hildebrant Ruiz and Yarwood, 2013). CB6 provides several revisions to the 

previous carbon bond version (CB05) through inclusion of four new explicit organic species: benzene, 

propane, acetylene and acetone; along with updates to reaction chemistry for those species and several 

other VOCs. Note that because CMAQ does not currently support CB6, the CMAQ-format emissions 

produced during the emissions modeling process cannot actually be used to run CMAQ. To create files 

usable with CMAQ, the inventories would instead need to be processed using CB05 speciation.

The 2011v6.2 platform consists of three ‘complete’ emissions cases: the 2011 base case (i.e., 

2011eh_cb6v2_v6), the 2017 base case (i.e., 2017eh_cb6v2_v6) and the 2025 base case (i.e., 

2025eh_cb6v2_v6). In the case abbreviations, the 2011, 2017 and 2025 are the year represented by the 

emissions; the “e” stands for evaluation, meaning that year-specific data for fires and electric generating 

units (EGUs) are used, and the “h” represents that this was the eighth set of emissions modeled for a

2011-based modeling platform. Table 1-1 provides more information on these emissions cases. The 

purpose of the 2011 base case is to represent the year 2011 in a manner consistent with the methods used 
2

in corresponding future-year cases, including the 2017 and 2025 future year base cases, as well as any 

additional future year control and source apportionment cases. This 2011v6.2 TSD is available on EPA’s 

Emissions Modeling Clearinghouse (EMCH) website, http://www.epa.gov/ttn/chief/emch/, under the 

section entitled “2011-based Modeling Platform (2011v6 Platform)”.

For regulatory applications, the outputs from the 2011 base case are used in conjunction with the outputs 

from the 2017 and 2025 base cases in the relative response factor (RRF) calculations to identify future 

areas of nonattainment. For more information on the use of RRFs and air quality modeling, see 

“Guidance on the Use of Models and Other Analyses for Demonstrating Attainment of Air Quality Goals 

for Ozone, PM 2.5, and Regional Haze”, available from 

http://www.epa.gov/ttn/scram/guidance/guide/final-03-pm-rh-guidance.pdf. 

Table 1-1. List of cases in the 2011 Version 6 Emissions Modeling Platform

Case Name Abbreviation Description

2011 base case 2011eh_cb6v2_v6

2011 case relevant for air quality model evaluation purposes

and for computing relative response factors with 2017 and 

2025 scenario(s). Uses 2011NEIv2 and some other inventory 

data, with hourly 2011 continuous emissions monitoring

System (CEMS) data for Electrical Generating Units (EGUs), 

hourly onroad mobile emissions, and 2011 day-specific wild 

and prescribed fire data. 

2017 base case 2017eh_cb6v2_v6

2017 “base case” scenario, representing the best estimate for 

2017 that incorporates estimates of the impact of current “onthe-books” regulations.

2025 base case 2025eh_cb6v2_v6

2025 “base case” scenario, representing the best estimate for 

2025 that incorporates estimates of the impact of current “onthe-books” regulations.

All of the above cases use the same version of the 2011 meteorology and the cases are sometimes referred 

to with “_11g” after the emissions portion of the case name. A special version of the 2017eh_cb6v2_v6 

case called 2017eh_ussa_cb6v2_v6_11g was prepared for use with the CAMx OSAT/APCA feature that 

allowed the contribution of 2017 base case NOX and VOC emissions from all sources in each state to 

projected 2017 ozone concentrations at air quality monitoring sites to be quantified. The emissions for the 

case are equivalent to those in the 2017eh_cb6v2_v6 case, except that the emission sources are tagged 

according to their origin by state or sector. The steps for setting up the 2017eh_cb6v2_v6 source 

apportionment case included: 

1) prepare files for the source groups to track (e.g., anthropogenic emissions from each state, nongeographic sector-specific tags for biogenic, fugitive dust, fire, and non-US emissions);

2) rerun all sectors in SMOKE using the specified source groups;

3) create CAMx point source files for source groups tracked only by sector;

4) convert SMOKE outputs to CAMx point source files using the tags assigned by SMOKE; and

5) merge all of the point source files together into a single CAMx mrgpt file for each day.

More information on processing for source apportionment is available at 

ftp://ftp.epa.gov/EmisInventory/2011v6/v2platform/smoke_scripts_utils/ 

README_smoke_source_apportionment.txt. 

The year 2018 was used as the analytic year for the preliminary modeling performed with the 2011v6.0 

platform because at the onset of the modeling assessment, that year aligned with the December 2018 
3

attainment date for Moderate ozone nonattainment areas. However, subsequent to the completion of the 

2018 modeling, EPA issued the final 2008 Ozone NAAQS SIP Requirements Rule, which revised the 

attainment deadline for ozone nonattainment areas currently designated as Moderate for the 2008 ozone 

NAAQS to July 2018. The EPA established this deadline in the 2015 Ozone SIP Requirements Rule after 

previously establishing a deadline of December 31, 2018, that was vacated by the D.C. Circuit in Natural 

Resources Defense Council v. EPA. In order to demonstrate attainment by the revised attainment deadline, 

the demonstration would have to be based on design values calculated using 2015 through 2017 ozone 

season data, since the July 2018 deadline does not afford a full ozone season of measured data. Therefore, 

the EPA has adopted 2017 as the analytic year for the updated ozone transport modeling in the 2011v6.2 

platform. Because projected emission inventories had already been prepared for the year 2018 by the 

time of the Natural Resources Defense Council v. EPA decision, the projected emissions for some sectors 

were adjusted to the year 2017 using methods appropriate to those sectors.

The emissions data in the 2011v6.2 platform are primarily based on the 2011NEIv2 for point sources, 

nonpoint sources, commercial marine vessels (CMV), nonroad mobile sources and fires. The onroad 

mobile source emissions are similar to those in the 2011NEIv2, but were generated using the released 

2014 version of the Motor Vehicle Emissions Simulator (MOVES2014) with support for CB6 

(http://www.epa.gov/otaq/models/moves/), while the 2011NEIv2 emissions were generated using a 

slightly earlier version of MOVES2014 and had a different treatment of E-85 vehicles. The 2011v6.2

platform cases implement comments received on the Federal Register notices issued for 2011 and 2018 

emissions in the 2011v6.0 platform: 78 FR 70935 and 79 FR 2437, respectively. High-level descriptions 

of implemented comments are included in the relevant subsections. The 2011v6.2 platform 2011 and 

2017 emissions and air quality model results were released for review and comment in the Federal 

Register notice 80 FR 46271. The updates in the 2011v6.2 platform include the following:

- Emissions updates based on comments submitted during the notices of data availability for the 

2011 and 2018 emissions modeling platforms and the development of the 2011NEIv2 that 

resulted in changes to all sectors of emissions in 2011NEIv2;

- Use of updated EPA emissions data sets in the 2011NEIv2 for many sectors, including oil and 

gas, residential wood combustion (RWC), commercial marine vessels, and oil platforms in the 

Gulf of Mexico;

- Use of MOVES 2014 for base and future year onroad mobile source emissions, along with 

updated input databases based on comments and new EPA data sources, and updates to 

speciation, spatial surrogates, and temporal profiles for onroad mobile sources;

- Use of the Biogenic Emissions Inventory System (BEIS) version 3.61 for biogenic emissions,

including updated land use information;

- Use of the Integrated Planning Model (IPM) version 5.14 for future year EGU emissions and 

updated EGU temporalization methods;

- Updated emissions for Canada and Mexico; and

- Updated projections for stationary sources.

The primary emissions modeling tool used to create the air quality model-ready emissions was the 

SMOKE modeling system (http://www.smoke-model.org/). SMOKE version 3.6.5 was used to create

emissions files for a 12-km national grid that includes all of the contiguous states “12US2”, shown in 

Figure 3-1. Boundary conditions for this grid were obtained from a 2011 run of GEOS-Chem

(http://geos-chem.org/) and were consistent with those used for the 2011v6.1 platform used for the 

proposed 2015 ozone NAAQS. Electronic copies of the data used as input to SMOKE for the 2011 
4

Platform are available from the Emissions Modeling Clearinghouse website, 

http://www.epa.gov/ttn/chief/emch/ under the 2011-based modeling platform section.

The gridded meteorological model used for the emissions modeling was developed using the Weather 

Research and Forecasting Model (WRF, http://wrf-model.org) version 3.4, Advanced Research WRF core

(Skamarock, et al., 2008). The WRF Model is a mesoscale numerical weather prediction system 

developed for both operational forecasting and atmospheric research applications. WRF was run for 2011

over a domain covering the continental United States at a 12km resolution with 35 vertical layers. The 

WRF data were collapsed to 25 layers prior to running the emissions and air quality models. The run for 

this platform included high resolution sea surface temperature data from the Group for High Resolution 

Sea Surface Temperature (GHRSST) (see https://www.ghrsst.org/) and is given the EPA meteorological 

case label “11g” and are consistent with those used for the 2011v6.1 platform.

This document contains five sections and several appendices. Section 2 describes the 2011 inventories 

input to SMOKE. Section 3 describes the emissions modeling and the ancillary files used with the

emission inventories. Section 4, describes the development of the 2017 and 2025 inventories (projected 

from 2011). Data summaries comparing the 2011, 2017 and 2025 base cases are provided in Section 5. 

Section 6 provides references. The Appendices provide additional details about specific technical 

methods. 
5

2 2011 Emission Inventories and Approaches

This section describes the 2011 emissions data that make up the 2011 platform. The starting point for the 

2011 stationary source emission inputs is the 2011NEIv2. Emissions of NOX, SO2, VOC and PM 

emissions decrease from values in the 2008 NEI version 3 for most source sectors, with a couple of 

notable exceptions including increased industrial NOX, VOC and CO associated with increased oil and 

gas sector emissions and improved emission estimates; slightly increased VOC, CO and NH3 from fuel 

combustion; and increased wildfire emissions. Documentation for the 2011NEIv2, including a Technical 

Support Document (TSD), is available at 

http://www.epa.gov/ttn/chief/net/2011inventory.html#inventorydoc. 

The NEI data for CAPs are largely compiled from data submitted by state, local and tribal (S/L/T) air 

agencies. HAP emissions data are also from the state data, but are often augmented by EPA because they 

are voluntarily submitted. EPA uses the Emissions Inventory System (EIS) to compile the NEI. EIS 

includes hundreds of automated QA checks to help improve data quality, and also supports tracking 

release point (e.g., stack) coordinates separately from facility coordinates. EPA collaborated extensively

with S/L/T agencies to ensure a high quality of data in the 2011NEIv2. Tangible benefits of this 

collaboration are seen in improved data quality, improved completeness and reduced duplication between 

point and nonpoint source categories such as industrial boilers. Onroad mobile source emissions in the 

2011NEIv2 were developed using a pre-release version of MOVES2014; however, the 2011 emissions 

modeling platform used the released version of MOVES2014, with added support for CB6. When given 

the same inputs, these two versions of MOVES produce similar emissions estimates for the year 2011.

The 2011 NEI includes five data categories: point sources, nonpoint (formerly called “stationary area”) 

sources, nonroad mobile sources, onroad mobile sources, and events consisting of fires. The 2011NEIv2

uses 60 sectors to further describe the emissions, with an additional biogenic sector generated from a 

summation of the gridded, hourly 2011 biogenic data used in the modeling platform. In addition to the 

NEI data, emissions from the Canadian and Mexican inventories and several other non-NEI data sources 

are included in the 2011 platform. 

As explained below, the major differences between the 2011 NEIv2 and the 2011 platform include: a 

different version of MOVES-based onroad mobile source emissions, meteorologically-adjusted road dust

emissions, CEMS data for EGUs, and emissions for areas outside the U.S. In addition, the modeling 

platform uses more temporally-resolved emissions than the NEI for many sectors. 

Fire emissions in 2011NEIv2 were developed based on Version 2 of the Satellite Mapping Automated 

Reanalysis Tool for Fire Incident Reconciliation (SMARTFIRE) system (Sullivan, et al., 2008). 

SMARTFIRE2 was the first version of SMARTFIRE to assign all fires as either prescribed burning or 

wildfire categories. In past inventories, a significant number of fires were published as unclassified, 

which impacted the emissions values and diurnal emissions pattern. Recent updates to SMARTFIRE 

include improved emission factors for prescribed burning. 

For the purposes of preparing the air quality model-ready emissions, the 2011NEIv2 was split into finergrained sectors used for emissions modeling. The significance of an emissions modeling or “platform 

sector” is that the data are run through all of the SMOKE programs except the final merge (Mrggrid) 

independently from the other sectors. The final merge program then combines the sector-specific gridded, 

speciated, hourly emissions together to create CMAQ-ready emission inputs. For CAMx applications, the 

CMAQ-ready emissions are then converted into the format needed by CAMx using a convertor program.
6

Table 2-1 presents the sectors in the 2011 platform and how they generally relate to the 2011NEIv2 as a 

starting point. As discussed in greater detail in Table 2-2, the emissions in some of these sectors were 

modified from the 2011NEIv2 emissions for the 2011 modeling platform. The platform sector 

abbreviations are provided in italics. These abbreviations are used in the SMOKE modeling scripts, 

inventory file names, and throughout the remainder of this document.

Table 2-1. Platform sectors for the 2011 emissions modeling platform

Platform Sector: 

abbreviation

NEI Data 

Category Description and resolution of the data input to SMOKE

EGU non-peaking 

units:

ptegu

Point

2011NEIv2 point source EGUs. The 2011NEIv2 emissions are 

replaced with hourly 2011 CEMS values for NOX and SO2, where the 

units are matched to the NEI. Other pollutants are scaled from 

2011NEIv2 using CEMS heat input. Emissions for all sources not 

matched to CEMS data come from 2011NEIv2. For future year 

emissions, these units are mapped to the Integrated Planning Model 

(IPM) model results using a cross reference to the National Electric 

Energy Database System (NEEDS) version 5.14. Annual resolution for 

non-matched sources, hourly for CEMS sources.

Point source oil 

and gas: 

pt_oilgas

Point 2011NEIv2 point sources that include oil and gas production 

emissions processes. Annual resolution.

Remaining nonEGU point:

ptnonipm

Point

All 2011NEIv2 point source records not matched to the ptegu or

pt_oilgas sectors, except for offshore point sources that are in the othpt 

sector. Includes all aircraft emissions and some rail yard emissions. 

Annual resolution.

Agricultural:

ag

Nonpoint NH3 emissions from 2011NEIv2 nonpoint livestock and fertilizer 

application, county and annual resolution. 

Agricultural fires: 

agfire Nonpoint 2011NEIv2 agricultural fire sources. County and monthly resolution.

Area fugitive dust:

afdust Nonpoint

PM10 and PM2.5 fugitive dust sources from the 2011NEIv2 nonpoint 

inventory; including building construction, road construction, 

agricultural dust, and road dust; however, unpaved and paved road 

dust emissions differ from the NEI in that do not have a precipitation 

adjustment. Instead, the emissions modeling adjustment applies a 

transport fraction and a meteorology-based (precipitation and snow/ice 

cover) zero-out. County and annual resolution. 

Biogenic:

Beis Nonpoint

Year 2011, hour-specific, grid cell-specific emissions generated from 

the BEIS3.61 model within SMOKE, including emissions in Canada 

and Mexico.

Category 1 & 2 

CMV and 

locomotives:

c1c2rail

Nonpoint

Locomotives and category 1 (C1) and category 2 (C2) commercial 

marine vessel (CMV) emissions sources from the 2011NEIv2

nonpoint inventory. County and annual resolution.

commercial 

marine:

c3marine

Nonpoint Category 3 (C3) CMV emissions from the 2011NEIv2 from the 

2011NEIv2; see othpt sector for all non-U.S. emissions. 

Remaining 

nonpoint:

nonpt

Nonpoint 2011NEIv2 nonpoint sources not included in other platform sectors; 

county and annual resolution. 

Nonpoint source 

oil and gas: 

np_oilgas

Nonpoint 2011NEIv2 nonpoint sources from oil and gas-related processes. 

County and annual resolution.
7

Platform Sector: 

abbreviation

NEI Data 

Category Description and resolution of the data input to SMOKE

Residential Wood 

Combustion:

rwc

Nonpoint 2011NEIv2 NEI nonpoint sources with Residential Wood Combustion 

(RWC) processes. County and annual resolution.

Nonroad:

nonroad Nonroad

2011NEIv2 nonroad equipment emissions developed with the National 

Mobile Inventory Model (NMIM) using NONROAD2008 version 

NR08a. NMIM was used for all states except California and Texas, 

which submitted their own emissions for the 2011NEIv2. County and 

monthly resolution.

Onroad:

onroad Onroad

2011 onroad mobile source gasoline and diesel vehicles from parking 

lots and moving vehicles. Includes the following modes: exhaust, 

extended idle, auxiliary power units, evaporative, permeation, 

refueling, and brake and tire wear. For all states except California, 

based on monthly MOVES emissions tables from MOVES2014. 

California emissions are based on Emission Factor (EMFAC). 

MOVES-based emissions computed for each hour and model grid cell 

using monthly and annual activity data (e.g., VMT, vehicle 

population). 

Point source fires:

ptprescfire Fires

Point source day-specific prescribed fires for 2011 computed using 

SMARTFIRE2, except for Georgia and Florida-submitted emissions.

Consistent with 2011NEIv2. Note that CMAQ requires all fire 

emissions to be in a single sector (ptfire) to receive the fire-specific 

treatment for plume rise, so prescribed and wild must be merged.

Point source fires:

ptwildfire Fires

Point source day-specific wildfires for 2011 computed using 

SMARTFIRE2, except for Georgia and Florida-submitted emissions.

Consistent with 2011NEIv2.

Other dust

sources not from 

the 2011 NEI:

Othafdust

N/A Fugitive dust sources from Canada’s 2010 inventory.

Other point 

sources not from 

the 2011 NEI:

othpt

N/A

Point sources from Canada’s 2010 inventory and Mexico’s 2008

inventory, annual resolution. Also includes all non-U.S. C3 CMV and 

U.S. offshore oil production.

Other non-NEI 

nonpoint and 

nonroad:

othar

N/A Annual year 2010 Canada (province resolution) and year 2008 Mexico 

(municipio resolution) nonpoint and nonroad mobile inventories.

Other non-NEI 

onroad sources:

othon

N/A Year 2010 Canada (province resolution) and year 2008 Mexico 

(municipio resolution) onroad mobile inventories, annual resolution.

Table 2-2 provides a brief by-sector overview of the most significant differences between the 2011

emissions platform and the 2011NEIv2. Only those sectors with significant differences between the 

2011NEIv2 and the 2011 emissions modeling platform are listed. The specific by-sector updates to the 

2011 platform are described in greater detail later in this section under each by-sector subsection. 
8

Table 2-2. Summary of differences between 2011v6.2 platform and 2011NEIv2 emissions by sector

Platform Sector Summary of Significant Inventory Differences of 2011 Platform vs.

2011NEIv2

Area fugitive dust:

afdust

1) Replaced EPA-provided emission estimates for paved and unpaved road dust 

with “non-meteorologically-adjusted” emissions, then adjusted emissions to 

reflect land use (transport) and meteorological effects such as rain and snow 

cover which significantly reduces PM emissions. These adjusted emissions are 

known as the afdust_adj sector.

Biogenic: 

beis

1) Biogenic emissions changed from 3.60 to 3.61

Remaining 

nonpoint sector:

nonpt

1) Split the 2011NEIv2 nonpoint file into the platform sectors afdust, ag, agfire, 

beis, np_oilgas, rwc, c3marine, and c1c2rail.

2) Used agricultural fires emissions from a daily inventory aggregated to monthly

values, whereas the NEI only stores annual values.

Nonroad sector:

nonroad

1) Monthly rather than annual emissions that match 2011NEIv2 totals.

2) Texas: replaced with annual 2011 Texas data apportioned to months using 

EPA’s 2011 nonroad estimates.

Onroad sector:

Onroad

1) For all states except California: Year 2011 emissions based on emission 

factors from the released version of MOVES2014, as opposed to the early 

MOVES2014 which was used for the 2011NEIv2. Developed with SMOKEMOVES using 2011 meteorology.

2) Platform contains correction to diesel refueling emissions

3) Platform uses E-85 activity data and emission factors, where for NEI E85 was not included.

4) For California: merged in 2011 California data to post-adjust SMOKEMOVES data (discussed later). 

EGUs:

ptegu 

1) Based on 2011NEIv2 and 2011 CEMS data analysis by EPA and states, added 

ORIS Boiler IDs to some units (greater than 1,000 tons of NOX or SO2) with 

missing or incorrect values to allow for hourly CEMS data processing.

2) Added CEMS matches to additional units identified as CEMS sources.

Hourly NOX and SO2 CEMS data replaces annual NOX and SO2 NEI data in 

the air quality model inputs for 2011 and scaled hourly data in future years. 

Non-EGUs 

sector:

ptnonipm

1) Additional matches to IPM_YN codes and ORIS facility codes caused several 

sources to move out of ptnonipm and into the ptegu sector. The goal is to

prevent double counting of EGU emissions in the future years. 

The emission inventories in SMOKE input format for the 2011 base case are available from the Emissions 

Modeling Clearinghouse website http://www.epa.gov/ttn/chief/emch/index.html#2011. The 2011v6.2 

“readme” file indicates the particular zipped files associated with each platform sector. A number of 

reports were developed for the 2011 platform. Descriptions of the available data and reports are available 

from the FTP site at ftp://ftp.epa.gov/EmisInventory/2011v6/v2platform. The types of reports include 

state summaries of inventory pollutants and model species by modeling platform sector, county annual 

totals by modeling platform sector, daily NOx and VOC emissions by sector and total, and state-SCCsector summaries. . A comparison of the complete list of inventory files, ancillary files, and parameter 

settings for the 2011v6.2 platform modeling cases is also available.

The remainder of Section 2 provides details about the data contained in each of the 2011 platform sectors. 

Different levels of detail are provided for different sectors depending on the availability of reference 

information for the data, the degree of changes or manipulation of the data needed to prepare it for input 

to SMOKE, and whether the 2011 platform emissions are significantly different from the 2011NEIv2.
9

2.1 2011 NEI point sources (ptegu, pt_oilgas and ptnonipm)

Point sources are sources of emissions for which specific geographic coordinates (e.g., 

latitude/longitude) are specified, as in the case of an individual facility. A facility may have multiple 

emission release points, which may be characterized as units such as boilers, reactors, spray booths, 

kilns, etc. A unit may have multiple processes (e.g., a boiler that sometimes burns residual oil and 

sometimes burns natural gas). With a couple of minor exceptions, this section describes only NEI point 

sources within the contiguous United States. The offshore oil platform (othpt sector) and category 3 

CMV emissions (c3marine and othpt sectors) are processed by SMOKE as point source inventories, as 

described in Section 2.5.1 and Section 2.4.2, respectively. A comprehensive description of how EGU 

emissions were characterized and estimated in the 2011 NEI can be found in Section 3.10 in the 

2011NEIv2 TSD.

The point source file used for the modeling platform is exported from EIS into the Flat File 2010 (FF10) 

format that is compatible with SMOKE (see http://www.cmascenter.org/smoke/documentation/3.5.1/ 

html/ch08s02s10.html#d0e44906). After moving offshore oil platforms into the othpt sector, and 

dropping sources without true locations (i.e., their FIPS code ends in 777), initial versions of the other 

four platform point source sectors were created from the remaining 2011NEIv2 point sources. The point 

sectors are: the EGU sector for non-peaking units (ptegu), point source oil and gas extraction -related 

emissions (pt_oilgas) and the remaining non-EGU sector also called the non-IPM (ptnonipm) sector. 

The EGU emissions are split out from the other sources to facilitate the use of distinct SMOKE temporal 

processing and future-year projection techniques. The oil and gas sector emissions (pt_oilgas) were 

processed separately for summary tracking purposes and distinct future-year projection techniques from 

the remaining non-EGU emissions (ptnonipm).

The inventory pollutants processed through SMOKE for all point source sectors were: CO, NOX, VOC, 

SO2, NH3, PM10, and PM2.5 and the following HAPs: HCl (pollutant code = 7647010), and Cl (code = 

7782505). The inventory BAFM from these sectors was not used, instead VOC was speciated to these 

pollutants without any use (i.e., integration) of the VOC HAP pollutants from the inventory (VOC 

integration is discussed in detail in Section 0).

The ptnonipm and pt_oilgas sector emissions were provided to SMOKE as annual emissions. For those 

ptegu sources with CEMS data (that could be matched to the 2011NEIv2), 2011 hourly CEMS NOX and 

SO2 emissions were used rather than NEI emissions, and for all other pollutants annual emissions were 

used as-is from the NEI, but were allocated to hourly values using heat input CEMS data. For the nonCEMS sources in the ptegu sector, daily emissions were created using an approach described in Section 

2.1.1, and IPM region- and pollutant-specific diurnal profiles were applied to create hourly emissions. 

Changes made to the point-based sectors from the 2011NEIv2 for the 2011 platform were described in 

Table 2-2. Some of these changes involved splitting the stacks, units and facilities into the ptnonipm, 

pt_oilgas and ptegu sectors. Sources were included in the ptegu sector only when it was determined that 

these sources were reflected in the future-year IPM output data. These changes and other updates to the 

point source sectors for the 2011 platform are discussed in the following sections.

2.1.1 EGU sector (ptegu)

The ptegu sector contains emissions from EGUs in the 2011NEIv2 point inventory that could be 

matched to units found in the NEEDS v5.14 database. It was necessary to put these EGUs into separate 

sectors in the platform because IPM projects future emissions for the EGUs defined in the NEEDS
10

database, and emissions for sources in the ptegu sector are replaced with IPM outputs in the future year 

modeling case. Sources not matched to units found in NEEDS are placed into the pt_oilgas (see Section 

2.1.2) or ptnonipm (see Section 2.1.3) sectors and are projected to the future year using projection and 

control factors. It is important that the matching between the NEI and NEEDS database be as complete 

as possible because there can be double counting of emissions in the future year if emissions for units 

are projected by IPM are not properly matched to the units in the NEI. The 2011v6.1 platform included 

a ptegu_pk sector, but this was determined not to add significant information and therefore all identified 

EGUs are in the ptegu sector in the 2011v6.2 platform.

In the SMOKE point flat file, emission records for sources that have been matched to the NEEDS 

database have a value filled into the IPM_YN column. Many of these matches are stored within EIS. In 

some cases, it was difficult to match the sources between the databases due to different facility names in 

the two data systems and due to differences in how the units are defined, thereby resulting in matches 

that are not always one-to-one. Some additional matches were made in the modeling platform to 

accommodate some of these situations as described later in this section. The NEEDS v5.14 database can 

be found at http://www.epa.gov/powersectormodeling/psmodel514.html , along with additional 

information about IPM. The cross reference between NEEDS 5.14 units and those in the NEI can be 

found here: ftp://ftp.epa.gov/EmisInventory/2011v6/v2platform/reports/ 

ipm_to_flat_file_xref_2011NEIv2_IPM5.14_20150113.xlsx and is used when IPM outputs are

postprocessed to create flat files for modeling. An updated version with additional matches to be used

with later versions of IPM called ipm_to_flat_file_xref_2011NEIv2_Updated_20150710.xlsx is also 

available.

Some units in the ptegu sector are matched to CEMS data via ORIS facility codes and boiler ID. Many 

additional units were matched to CEMS data than were matched for the 2011v6.1 platform. For matched

units, SMOKE replaces the 2011 emissions of NOX and SO2 with the CEMS emissions, thereby 

ignoring the annual values specified in the NEI. For other pollutants, the hourly CEMS heat input data 

are used to allocate the NEI annual emissions to hourly values. All stack parameters, stack locations, 

and SCC codes for these sources come from the NEI. Because these attributes are obtained from the 

NEI, the chemical speciation of VOC and PM2.5 for the sources is selected based on the SCC or in some 

cases, based on unit-specific data. If CEMS data exists for a unit, but the unit is not matched to the NEI, 

the CEMS data for that unit is not used in the modeling platform. However, if the source exists in the 

NEI and is not matched to a CEMS unit, the emissions from that source are still modeled using the 

annual emission value in the NEI. EIS stores many matches from EIS units to the ORIS facility codes 

and boiler IDs used to reference the CEMS data. Some additional matches were made in the modeling 

platform as described later in this section. 

In the SMOKE point flat file, emission records for point sources matched to CEMS data have values 

filled into the ORIS_FACILITY_CODE and ORIS_BOILER_ID columns. The CEMS data in SMOKEready format is available at http://ampd.epa.gov/ampd/ near the bottom of the “Prepackaged Data” tab. 

Many smaller emitters in the CEMS program are not identified with ORIS facility or boiler IDs that can 

be matched to the NEI due to inconsistencies in the way a unit is defined between the NEI and CAMD 

datasets, or due to uncertainties in source identification such as inconsistent plant names in the two data 

systems. Also, the NEEDS database of units modeled by IPM includes many smaller emitting EGUs

that are not included in the CAMD hourly CEMS programs. Therefore, there will be more units in the 

NEEDS database than have CEMS data. The temporalization of EGU units matched to CEMS is based 

on the CEMS data in the base and future years are based on the base year CEMS data for those units, 

whereas regional profiles are used for the remaining units. More detail can be found in Section 3.3.2.
11

For sources not matched to CEMS data, daily emissions were computed from the NEI annual emissions 

using average CEMS data profiles specific to fuel type, pollutant2, and IPM region. To allocate 

emissions to each hour of the day, diurnal profiles were created using average CEMS data for heat input 

specific to fuel type and IPM region. For future-year scenarios, there are no CEMS data available for 

specific units, but the shape of the CEMS profiles is preserved for sources that are carried into the future 

year. This method keeps the temporal behavior of the base and future year cases as consistent as 

possible. See Section 3.3.2 for more details on the temporalization approach for ptegu sources.

Finding additional matches between the NEI, NEEDS, and CEMS data

Several analytical steps were performed to better link the NEEDS units to the 2011NEIv2, along with 

implementing better matching to the CEMS data cross-referenced using “ORIS” facility and boiler IDs. 

The steps described in the 2011NEIv2 TSD have some detail on how the values in the IPM_YN column

were assigned. For the modeling platform, an initial ptegu/ptnonipm split was determined using the 

values in the SMOKE point source flat file variable “IPM_YN”, which is populated based on an EIS 

alternative facility identifier. Because EIS expects the matches to be one-to-one for an entire unit, if the 

units are not defined in the same way in EIS and NEEDS, one-to-many or many-to-many matches can 

only be stored in EIS with specified “end dates” and will not export directly to the flat file. However, 

one-to-many and many-to-many matches to the IPM_YN values were placed into the SMOKE input file 

through a postprocessing step. This requires the additional of additional “dummy” records in the 

SMOKE file that will be overlaid with CEMS data when SMOKE is run. 

Additional matches between the NEI and NEEDS were identified by identifying units in IPM outputs 

that were not yet matched to NEI data, and by looking for units identified in the NEI with facility type 

codes identifying them as EGUs or facility names that indicated they were EGUs. In each case, priority 

was given to units with larger emissions (e.g., > 300TPY of NOx or SO2). The units in each data set that 

did not yet have matches within the same county were compared to one another on the basis of their 

plant names and locations. In some cases, IDs were similar but were mismatched only due to a missing 

leading zero in one of the databases. In other cases, a facility level match was specified, but a unit/boiler 

level match was not yet identified and therefore the units at the facility were compared to one another on 

the basis of design capacity and naming. For any new matches that were found, values that represented 

the NEEDS IDs were filled in to the IPM_YN in the modeling platform flat files. When possible, these 

matches were loaded into EIS.

A similar matching process was used to identify additional matches between the 2011NEIv2 and CEMS

data. To determine whether a NEI unit matched a CEMS unit, the CEMS units were compared to 

facilities in the NEI that were not yet identified as a CEMS unit on the basis of their county FIPS codes, 

locations, and total emissions of NOx and SO2. Additional CEMS matches that were found were applied 

to the FF10 file by specifying values for ORIS_FACILITY_CODE, ORIS_BOILER_ID. Because IPM 

uses a concatenation of the ORIS facility code and boiler ID, values were also filled in to the IPM_YN 

field for these units. 

As a result of identifying additional matches through this analysis, many EGUs that otherwise would 

have remained in the ptnonipm sector were moved to the ptegu sector. Many new CEMS assignments 

 

2 The year to day profiles use NOx and SO2 CEMS for NOx and SO2, respectively. For all other pollutants, they use heat 

input CEMS data.
12

were loaded into EIS for use in future inventories. Note that SMOKE can perform matches of CEMS 

data down to the stack or release point-level, which is finer than unit-level. 

2.1.2 Point source oil and gas sector (pt_oilgas)

The pt_oilgas sector was separated from the ptnonipm sector by selecting sources with specific NAICS 

codes shown in Table 2-3. This was done differently than in the 2011v6.1 platform and resulted in more 

sources and emissions in the pt_oilgas sector and fewer sources and emissions in the ptnonipm sector. 

The emissions and other source characteristics in the pt_oilgas sector are submitted by states, while EPA 

developed a dataset of nonpoint oil and gas emissions for each county in the U.S. with oil and gas 

activity that was available for states to use. Nonpoint oil and gas emissions can be found in the 

np_oilgas sector. More information on the development of the 2011 oil and gas emissions can be found 

in Section 3.20 of the 2011NEIv2 TSD.

Table 2-3. Point source oil and gas sector NAICS Codes

NAICS NAICS description

2111 Oil and Gas Extraction 

2212 Natural Gas Distribution 

4862 Pipeline Transportation of Natural Gas 

21111 Oil and Gas Extraction 

22121 Natural Gas Distribution 

48611 Pipeline Transportation of Crude Oil

48621 Pipeline Transportation of Natural Gas 

211111 Crude Petroleum and Natural Gas Extraction 

211112 Natural Gas Liquid Extraction 

213111 Drilling Oil and Gas Wells 

213112 Support Activities for Oil and Gas Operations

221210 Natural Gas Distribution 

486110 Pipeline Transportation of Crude Oil 

486210 Pipeline Transportation of Natural Gas 

2.1.3 Non-IPM sector (ptnonipm)

Except for some minor exceptions, the non-IPM (ptnonipm) sector contains the 2011NEIv2 point 

sources that are not in the ptegu or pt_oilgas sectors. For the most part, the ptnonipm sector reflects the 

non-EGU sources of the NEI point inventory; however, it is likely that some small low-emitting EGUs 

not matched to the NEEDS database or to CEMS data are present in the ptnonipm sector. The sector 

includes some ethanol plants that have been identified by EPA and require special treatment in the future 

cases as they are impacted by mobile source rules.

The ptnonipm sector contains a small amount of fugitive dust PM emissions from vehicular traffic on 

paved or unpaved roads at industrial facilities, coal handling at coal mines, and grain elevators. Sources 

with state/county FIPS code ending with “777” are in the 2011NEIv2 but are not included in any 

modeling sectors. These sources typically represent mobile (temporary) asphalt plants that are only 

reported for some states, and are generally in a fixed location for only a part of the year and are therefore 

difficult to allocate to specific places and days as is needed for modeling. Therefore, these sources are 

dropped from the point-based sectors in the modeling platform.
13

EPA estimates for ethanol facilities

Ethanol plants are important facilities for mobile source rules that have impact development work, EPA 

developed a list of corn ethanol facilities for 2011. Ethanol facilities that were not in 2011NEIv1 were 

added into 2011NEIv2. Locations and FIPS codes for these ethanol plants were verified using web 

searches and Google Earth. EPA believes that some of these sources were not originally included in the 

NEI as point sources because they do not meet the 100 ton/year potential-to-emit threshold for NEI point 

sources. Emission rates for the ethanol plants were obtained from EPA’s updated spreadsheet model for 

upstream impacts developed for the Renewable Fuel Standard (RFS2) rule (EPA, 2010a). Plant 

emission rates for criteria pollutants used to estimate impacts for years 2011 (and are assumed to be the 

same in 2018 and 2025) are given in Table 2-4. 

Table 2-4. Corn Ethanol Plant Criteria Pollutant Emission Factors (grams per gallon produced)

Corn Ethanol Plant Type VOC CO NOX PM10 PM2.5 SO2 NH3

Dry Mill Natural Gas (NG) 2.29 0.58 0.99 0.94 0.23 0.01 0.00

Dry Mill NG (wet distillers grains with solubles (DGS)) 2.27 0.37 0.63 0.91 0.20 0.00 0.00

Dry Mill Biogas 2.29 0.62 1.05 0.94 0.23 0.01 0.00

Dry Mill Biogas (wet DGS) 2.27 0.39 0.67 0.91 0.20 0.00 0.00

Dry Mill Coal 2.31 2.65 4.17 3.81 1.71 4.52 0.00

Dry Mill Coal (wet DGS) 2.31 2.65 2.65 2.74 1.14 2.87 0.00

Dry Mill Biomass 2.42 2.55 3.65 1.28 0.36 0.14 0.00

Dry Mill Biomass (wet DGS) 2.35 1.62 2.32 1.12 0.28 0.09 0.00

Wet Mill NG 2.35 1.62 1.77 1.12 0.28 0.09 0.00

Wet Mill Coal 2.33 1.04 5.51 4.76 2.21 5.97 0.00

Air toxic emission rates were estimated by applying toxic to VOC ratios in Table 2-5 were multiplied by 

facility production estimates for 2011 and 2018 based on analyses performed for the industry 

characterization described in Chapter 1 of the RFS2 final rule regulatory impact analysis. For air toxics 

except ethanol, the toxic-to-VOC ratios were developed using emission inventory data from the 2005 

NEI (EPA, 2009a).

Table 2-5. Toxic-to-VOC Ratios for Corn Ethanol Plants

Acetaldehyde Acrolein Benzene 1,3-Butadiene Formaldehyde

Wet Mill NG 0.02580 0.00131 0.00060 2.82371E-08 0.00127

Wet Mill Coal 0.08242 0.00015 0.00048 2.82371E-08 0.00108

Dry Mill NG 0.01089 0.00131 0.00060 2.82371E-08 0.00127

Dry Mill Coal 0.02328 0.00102 0.00017 2.82371E-08 0.00119

2.2 2011 nonpoint sources (afdust, ag, agfire, np_oilgas, rwc, nonpt)

Several modeling platform sectors were created from the 2011NEIv2 nonpoint inventory. This section 

describes the stationary nonpoint sources. Locomotives, C1 and C2 CMV, and C3 CMV are also 

included the 2011NEIv2 nonpoint data category, but are mobile sources that are described in Sections

2.4.1 and 2.4.2 as the c1c2rail and c3marine sectors, respectively. The 2011NEIv2 TSD available from 

http://www.epa.gov/ttn/chief/net/2011inventory.html includes documentation for the nonpoint sector of 

the 2011NEIv2.
14

The nonpoint tribal-submitted emissions are dropped during spatial processing with SMOKE due to the 

configuration of the spatial surrogates. Part of the reason for this is to prevent possible double-counting 

with county-level emissions and also because spatial surrogates for tribal data are not currently 

available. These omissions are not expected to have an impact on the results of the air quality modeling 

at the 12-km scales used for this platform. 

The following subsections describe how the sources in the 2011NEIv2 nonpoint inventory were 

separated into 2011 modeling platform sectors, along with any data that were updated replaced with 

non-NEI data. 

2.2.1 Area fugitive dust sector (afdust)

The area-source fugitive dust (afdust) sector contains PM10 and PM2.5 emission estimates for nonpoint 

SCCs identified by EPA staff as dust sources. Categories included in the afdust sector are paved roads, 

unpaved roads and airstrips, construction (residential, industrial, road and total), agriculture production, 

and mining and quarrying. It does not include fugitive dust from grain elevators, coal handling at coal 

mines, or vehicular traffic on paved or unpaved roads at industrial facilities because these are treated as

point sources so they are properly located. 

The afdust sector is separated from other nonpoint sectors to allow for the application of a “transport 

fraction,” and meteorological/precipitation reductions. These adjustments are applied with a script that 

applies land use-based gridded transport fractions followed by another script that zeroes out emissions

for days on which at least 0.01 inches of precipitation occurs or there is snow cover on the ground. The 

land use data used to reduce the NEI emissions determines the amount of emissions that are subject to 

transport. This methodology is discussed in (Pouliot, et al., 2010), 

http://www.epa.gov/ttn/chief/conference/ei19/session9/pouliot_pres.pdf, and in “Fugitive Dust 

Modeling for the 2008 Emissions Modeling Platform” (Adelman, 2012). Both the transport fraction and 

meteorological adjustments are based on the gridded resolution of the platform (e.g., 12km grid cells); 

therefore, different emissions will result if the process were applied to different grid resolutions. A 

limitation of the transport fraction approach is the lack of monthly variability that would be expected 

with seasonal changes in vegetative cover. While wind speed and direction are not accounted for in the 

emissions processing, the hourly variability due to soil moisture, snow cover and precipitation is 

accounted for in the subsequent meteorological adjustment.

The sources in the afdust sector are for SCCs and pollutant codes (i.e., PM10 and PM2.5) that are 

considered to be “fugitive” dust sources. These SCCs are provided in Table 2-6.

Table 2-6. SCCs in the afdust platform sector

SCC SCC Description

2275085000 Mobile Sources;Aircraft;Unpaved Airstrips;Total 

2294000000 Mobile Sources;Paved Roads;All Paved Roads;Total: Fugitives 

2294000002 Mobile Sources;Paved Roads;All Paved Roads;Total: Sanding/Salting - Fugitives 

2296000000 Mobile Sources;Unpaved Roads;All Unpaved Roads;Total: Fugitives 

2296005000 Mobile Sources;Unpaved Roads;Public Unpaved Roads;Total: Fugitives 

2296010000 Mobile Sources;Unpaved Roads;Industrial Unpaved Roads;Total: Fugitives 

2311000000 Industrial Processes;Construction: SIC 15 - 17;All Processes;Total 

2311010000 Industrial Processes;Construction: SIC 15 - 17;Residential;Total 

2311020000 Industrial Processes;Construction: SIC 15 - 17;Industrial/Commercial/Institutional;Total 
15

SCC SCC Description

2311030000 Industrial Processes;Construction: SIC 15 - 17;Road Construction;Total 

2311040000 Industrial Processes;Construction: SIC 15 - 17;Special Trade Construction;Total 

2325000000 Industrial Processes;Mining and Quarrying: SIC 14;All Processes;Total 

2325020000 Industrial Processes;Mining and Quarrying: SIC 14;Crushed and Broken Stone;Total 

2325030000 Industrial Processes;Mining and Quarrying: SIC 14;Sand and Gravel;Total 

2801000000 Miscellaneous Area Sources;Agriculture Production - Crops;Agriculture - Crops;Total 

2801000002 Miscellaneous Area Sources;Agriculture Production - Crops;Agriculture - Crops;Planting 

2801000003 Miscellaneous Area Sources;Agriculture Production - Crops;Agriculture - Crops;Tilling 

2801000005

Miscellaneous Area Sources;Agriculture Production - Crops;Agriculture -

Crops;Harvesting 

2801000008

Miscellaneous Area Sources;Agriculture Production - Crops;Agriculture -

Crops;Transport 

2805001000

Miscellaneous Area Sources;Agriculture Production - Livestock;Beef cattle - finishing 

operations on feedlots (drylots);Dust Kicked-up by Hooves (use 28-05-020, -001, -002, or 

-003 for Waste

The dust emissions in the modeling platform are not the same as the 2011NEIv2 emissions because the 

NEI paved and unpaved road dust emissions include a built-in precipitation reduction that is based on 

average meteorological data, which is at a coarser temporal and spatial resolution than the modeling 

platform meteorological adjustment. Due to this, in the platform the paved and unpaved road emissions 

data used did not include any precipitation-based reduction. This allows the entire sector to be processed 

consistently so that the same grid-specific transport fractions and meteorological adjustments can be 

applied. Where states submitted afdust data, it was assumed that the state-submitted data were not metadjusted and therefore the meteorological adjustments were still applied. Thus, it is possible that these 

sources may have been adjusted twice. Even with that possibility, air quality modeling shows that in 

general, dust is frequently overestimated in the air quality modeling results.

The total impacts of the transport fraction and meteorological adjustments for the 2011NEIv2 are shown 

in Table 2-7, where the starting inventory numbers include unadjusted paved and unpaved road dust, so 

they do not match the NEI values because those include a different type of adjustment. The amount of 

the reduction ranges from about 7% in New Hampshire to about 72% in Nevada. 

Table 2-7. Total Impact of Fugitive Dust Adjustments to Unadjusted 2011 Inventory 

State Unadjusted 

PM10

Unadjusted 

PM2_5

Change in 

PM10

Change in 

PM2_5

PM10 

Reduction

PM2_5 

Reduction

Alabama 378,874 47,158 -310,750 -38,597 18% 18%

Arizona 237,361 30,015 -78,519 -9,778 67% 67%

Arkansas 421,958 58,648 -305,611 -40,757 28% 31%

California 255,889 38,664 -119,035 -17,930 54% 54%

Colorado 244,630 40,421 -130,598 -20,991 47% 48%

Connecticut 29,067 4,393 -25,877 -3,912 11% 11%

Delaware 11,548 1,968 -8,219 -1,396 29% 29%

D.C. 2,115 337 -1,596 -254 25% 25%

Florida 292,797 39,637 -181,017 -24,333 38% 39%

Georgia 733,478 90,041 -593,644 -72,028 19% 20%

Idaho 432,116 49,294 -291,880 -32,897 33% 33%

Illinois 763,665 123,680 -472,806 -76,086 38% 39%
16

State Unadjusted 

PM10

Unadjusted 

PM2_5

Change in 

PM10

Change in 

PM2_5

PM10 

Reduction

PM2_5 

Reduction

Indiana 603,152 85,151 -435,027 -60,660 28% 29%

Iowa 590,528 96,070 -339,349 -54,855 43% 43%

Kansas 747,242 118,726 -352,559 -54,760 53% 54%

Kentucky 199,744 29,496 -160,640 -23,511 20% 20%

Louisiana 236,787 35,730 -162,780 -24,086 31% 33%

Maine 50,547 7,016 -43,643 -6,078 14% 13%

Maryland 65,701 10,215 -49,481 -7,691 25% 25%

Massachusetts 205,561 22,444 -177,808 -19,370 14% 14%

Michigan 462,324 61,969 -353,225 -47,137 24% 24%

Minnesota 336,791 64,253 -217,036 -41,145 36% 36%

Mississippi 956,702 107,965 -782,249 -86,685 18% 20%

Missouri 1,063,992 130,995 -780,488 -94,576 27% 28%

Montana 385,541 50,583 -266,046 -33,521 31% 34%

Nebraska 591,457 85,206 -316,918 -45,198 46% 47%

Nevada 160,699 20,477 -47,147 -5,688 71% 72%

New Hampshire 25,540 3,766 -23,836 -3,515 7% 7%

New Jersey 24,273 5,412 -19,215 -4,255 21% 21%

New Mexico 924,497 95,871 -352,117 -36,344 62% 62%

New York 274,114 37,493 -236,431 -31,990 14% 15%

North Carolina 186,650 33,409 -146,918 -26,184 21% 22%

North Dakota 354,107 59,113 -218,630 -36,286 38% 39%

Ohio 414,902 64,609 -319,831 -49,298 23% 24%

Oklahoma 733,750 87,864 -385,344 -44,585 48% 49%

Oregon 348,093 40,596 -268,605 -30,516 23% 25%

Pennsylvania 208,246 30,344 -179,991 -26,158 14% 14%

Rhode Island 4,765 731 -3,628 -564 24% 23%

South Carolina 259,350 31,494 -198,175 -24,002 24% 24%

South Dakota 262,935 44,587 -155,938 -26,215 41% 41%

Tennessee 139,731 25,357 -107,964 -19,514 23% 23%

Texas 2,573,687 304,551 -1,278,053 -146,122 50% 52%

Utah 196,551 21,589 -113,837 -12,464 42% 42%

Vermont 67,690 7,563 -61,423 -6,855 9% 9%

Virginia 131,798 19,374 -108,700 -15,895 18% 18%

Washington 174,969 27,999 -99,720 -15,425 43% 45%

West Virginia 85,956 10,652 -79,745 -9,888 7% 7%

Wisconsin 239,851 41,669 -164,113 -28,542 32% 32%

Wyoming 434,090 45,350 -264,580 -27,467 39% 39%

Domain Total 18,525,814 2,489,943 -11,790,743 -1,566,004 36% 37%

Figure 2-1 shows the impact of each step of the adjustment for 2011. The reductions due to the transport 

fraction adjustments alone are shown at the top of Figure 2-1. The reductions due to the precipitation 

adjustments are shown in the middle of Figure 2-1. The cumulative emission reductions after both 

transport fraction and meteorological adjustments are shown at the bottom of Figure 2-1. The top plot 

shows how the transport fraction has a larger reduction effect in the east, where forested areas are more 

effective at reducing PM transport than in many western areas. The middle plot shows how the 

meteorological impacts of precipitation, along with snow cover in the north, further reduce the dust 

emissions.
17

Figure 2-1. Impact of adjustments to fugitive dust emissions due to transport fraction, precipitation, and 

cumulative
18

2.2.2 Agricultural ammonia sector (ag)

The agricultural NH3 (ag) sector includes livestock and agricultural fertilizer application emissions from 

the 2011NEIv2 nonpoint inventory. The livestock and fertilizer emissions in this sector are based only 

on the SCCs listed in Table 2-8 and Table 2-9. The “ag” sector includes all of the NH3 emissions from 

fertilizer from the NEI. However, the “ag” sector does not include all of the livestock ammonia 

emissions, as there are also a small amount of NH3 emissions from livestock feedlots in the ptnonipm 

inventory (as point sources) in California (175 tons) and Wisconsin (125 tons). 

Table 2-8. Livestock SCCs extracted from the NEI to create the ag sector

SCC SCC Description*

2805001100 Beef cattle - finishing operations on feedlots (drylots);Confinement

2805001200 Beef cattle - finishing operations on feedlots (drylots);Manure handling and storage

2805001300 Beef cattle - finishing operations on feedlots (drylots);Land application of manure

2805002000 Beef cattle production composite;Not Elsewhere Classified

2805003100 Beef cattle - finishing operations on pasture/range;Confinement

2805007100 Poultry production - layers with dry manure management systems;Confinement

2805007300 Poultry production - layers with dry manure management systems;Land application of manure

2805008100 Poultry production - layers with wet manure management systems;Confinement

2805008200 Poultry production - layers with wet manure management systems;Manure handling and storage

2805008300 Poultry production - layers with wet manure management systems;Land application of manure

2805009100 Poultry production - broilers;Confinement

2805009200 Poultry production - broilers;Manure handling and storage

2805009300 Poultry production - broilers;Land application of manure

2805010100 Poultry production - turkeys;Confinement

2805010200 Poultry production - turkeys;Manure handling and storage

2805010300 Poultry production - turkeys;Land application of manure

2805018000 Dairy cattle composite;Not Elsewhere Classified

2805019100 Dairy cattle - flush dairy;Confinement

2805019200 Dairy cattle - flush dairy;Manure handling and storage

2805019300 Dairy cattle - flush dairy;Land application of manure

2805020000 Cattle and Calves Waste Emissions;Milk Total

2805020002 Cattle and Calves Waste Emissions:Beef Cows

2805021100 Dairy cattle - scrape dairy;Confinement

2805021200 Dairy cattle - scrape dairy;Manure handling and storage

2805021300 Dairy cattle - scrape dairy;Land application of manure

2805022100 Dairy cattle - deep pit dairy;Confinement

2805022200 Dairy cattle - deep pit dairy;Manure handling and storage

2805022300 Dairy cattle - deep pit dairy;Land application of manure

2805023100 Dairy cattle - drylot/pasture dairy;Confinement

2805023200 Dairy cattle - drylot/pasture dairy;Manure handling and storage

2805023300 Dairy cattle - drylot/pasture dairy;Land application of manure

2805025000 Swine production composite;Not Elsewhere Classified (see also 28-05-039, -047, -053)

2805030000 Poultry Waste Emissions;Not Elsewhere Classified (see also 28-05-007, -008, -009)

2805030003 Poultry Waste Emissions;Layers

2805030004 Poultry Waste Emissions;Broilers

2805030007 Poultry Waste Emissions;Ducks

2805030008 Poultry Waste Emissions;Geese

2805030009 Poultry Waste Emissions;Turkeys

2805035000 Horses and Ponies Waste Emissions;Not Elsewhere Classified

2805039100 Swine production - operations with lagoons (unspecified animal age);Confinement

2805039200 Swine production - operations with lagoons (unspecified animal age);Manure handling and storage
19

SCC SCC Description*

2805039300 Swine production - operations with lagoons (unspecified animal age);Land application of manure

2805040000 Sheep and Lambs Waste Emissions;Total

2805045000 Goats Waste Emissions;Not Elsewhere Classified

2805045002 Goats Waste Emissions;Angora Goats

2805045003 Goats Waste Emissions;Milk Goats

2805047100 Swine production - deep-pit house operations (unspecified animal age);Confinement

2805047300 Swine production - deep-pit house operations (unspecified animal age);Land application of manure

2805053100 Swine production - outdoor operations (unspecified animal age);Confinement

* All SCC Descriptions begin “Miscellaneous Area Sources;Agriculture Production – Livestock”

Table 2-9. Fertilizer SCCs extracted from the NEI for inclusion in the “ag” sector

SCC SCC Description*

2801700001 Anhydrous Ammonia

2801700002 Aqueous Ammonia

2801700003 Nitrogen Solutions

2801700004 Urea

2801700005 Ammonium Nitrate

2801700006 Ammonium Sulfate

2801700007 Ammonium Thiosulfate

2801700008 Other Straight Nitrate

2801700009 Ammonium Phosphates

2801700010 N-P-K (multi-grade nutrient fertilizers)

2801700011 Calcium Ammonium Nitrate

2801700012 Potassium Nitrate

2801700013 Diammonium Phosphate

2801700014 Monoammonium Phosphate

2801700015 Liquid Ammonium Polyphosphate

2801700099 Miscellaneous Fertilizers

* All descriptions include “Miscellaneous Area Sources; 

Agriculture Production – Crops; Fertilizer Application” as 

the beginning of the description.

2.2.3 Agricultural fires (agfire)

The agricultural fire (agfire) sector contains emissions from agricultural fires. These emissions were 

placed into the sector based on their SCC code. All SCCs starting with 28015 were included. The first 

three levels of descriptions for these SCCs are: Fires - Agricultural Field Burning; Miscellaneous Area 

Sources; Agriculture Production - Crops - as nonpoint; Agricultural Field Burning - whole field set on 

fire. The SCC 2801500000 does not specify the crop type or burn method, while the more specific 

SCCs specify field or orchard crops, and in some cases the specific crop being grown. For more 

information on how emissions for agricultural fires were developed in the 2011NEIv2, see Section 5.2 

of the 2011NEIv2 TSD.

2.2.4 Nonpoint source oil and gas sector (np_oilgas)

The nonpoint oil and gas (np_oilgas) sector contains onshore and offshore oil and gas emissions. EPA

estimated emissions for all counties with 2011 oil and gas activity data with the Oil and Gas Tool, and 

many S/L/T agencies also submitted nonpoint oil and gas data. The types of sources covered include 

drill rigs, workover rigs, artificial lift, hydraulic fracturing engines, pneumatic pumps and other devices, 
20

storage tanks, flares, truck loading, compressor engines, and dehydrators. For more information on the 

development of the oil and gas emissions in the 2011NEIv2, see Section 3.20 of the 2011NEIv2 TSD. 

A complete list of SCCs for the np_oilgas modeling platform sector is provided in Appendix A. See the 

pt_oilgas sector (section 2.1.2) for more information on point source oil and gas sources. Updates were 

made to the speciation, temporalization, and spatial allocation of sources in the 2011v6.2 platform based 

on comments that were received. Sections 3.2, 3.3, and 3.4 provide additional details. 

2.2.5 Residential wood combustion sector (rwc)

The residential wood combustion (rwc) sector includes residential wood burning devices such as 

fireplaces, fireplaces with inserts (inserts), free standing woodstoves, pellet stoves, outdoor hydronic 

heaters (also known as outdoor wood boilers), indoor furnaces, and outdoor burning in firepots and 

chimneas. Free standing woodstoves and inserts are further differentiated into three categories: 

conventional (not EPA certified); EPA certified, catalytic; and EPA certified, noncatalytic. Generally 

speaking, the conventional units were constructed prior to 1988. Units constructed after 1988 had to 

meet EPA emission standards and they are either catalytic or non-catalytic. For more information on the 

development of the residential wood combustion emissions, see Section 3.14 of the 2011NEIv2 TSD. 

The SCCs in the rwc sector are shown in Table 2-10. Some reductions to Clark County, NV were 

implemented in the modeling platform as a result of data review for NATA, but these are not reflected in 

the 2011NEIv2.

Table 2-10. SCCs in the Residential Wood Combustion Sector (rwc)*

SCC SCC Description

2104008100 SSFC;Residential;Wood;Fireplace: general

2104008210 SSFC;Residential;Wood;Woodstove: fireplace inserts; non-EPA certified

2104008220 SSFC;Residential;Wood;Woodstove: fireplace inserts; EPA certified; non-catalytic

2104008230 SSFC;Residential;Wood;Woodstove: fireplace inserts; EPA certified; catalytic

2104008300 SSFC;Residential;Wood;Woodstove: freestanding, general

2104008310 SSFC;Residential;Wood;Woodstove: freestanding, non-EPA certified

2104008320 SSFC;Residential;Wood;Woodstove: freestanding, EPA certified, non-catalytic

2104008330 SSFC;Residential;Wood;Woodstove: freestanding, EPA certified, catalytic

2104008400 SSFC;Residential;Wood;Woodstove: pellet-fired, general (freestanding or FP insert)

2104008420

SSFC;Residential;Wood;Woodstove: pellet-fired, EPA certified (freestanding or FP 

insert)

2104008510 SSFC;Residential;Wood;Furnace: Indoor, cordwood-fired, non-EPA certified

2104008610 SSFC;Residential;Wood;Hydronic heater: outdoor

2104008700 SSFC;Residential;Wood;Outdoor wood burning device, NEC (fire-pits, chimeas, etc)

2104009000 SSFC;Residential;Firelog;Total: All Combustor Types

* SSFC=Stationary Source Fuel Combustion

2.2.6 Other nonpoint sources sector (nonpt)

Stationary nonpoint sources that were not subdivided into the afdust, ag, np_oilgas, or rwc sectors were 

assigned to the “nonpt” sector. Locomotives and CMV mobile sources from the 2011NEIv2 nonpoint 

inventory are described in Section 2.4.1. There are too many SCCs to list all of them individually, but 

the types of sources in the nonpt sector include:

 stationary source fuel combustion, including industrial, commercial, and residential; 

 chemical manufacturing; 
21

 industrial processes such as commercial cooking, metal production, mineral processes, petroleum 

refining, wood products, fabricated metals, and refrigeration; 

 solvent utilization for surface coatings such as architectural coatings, auto refinishing, traffic 

marking, textile production, furniture finishing, and coating of paper, plastic, metal, appliances, 

and motor vehicles; 

 solvent utilization for degreasing of furniture, metals, auto repair, electronics, and 

manufacturing;

 solvent utilization for dry cleaning, graphic arts, plastics, industrial processes, personal care 

products, household products, adhesives and sealants; 

 solvent utilization for asphalt application and roofing, and pesticide application; 

 storage and transport of petroleum for uses such as portable gas cans, bulk terminals, gasoline 

service stations, aviation, and marine vessels; 

 storage and transport of chemicals;

 waste disposal, treatment, and recovery via incineration, open burning, landfills, and composting;

 agricultural burning and orchard heating;

 miscellaneous area sources such as cremation, hospitals, lamp breakage, and automotive repair 

shops.

2.3 2011 onroad mobile sources (onroad)

Onroad mobile sources include emissions from motorized vehicles that are normally operated on public 

roadways. These include passenger cars, motorcycles, minivans, sport-utility vehicles, light-duty trucks, 

heavy-duty trucks, and buses. The sources are further divided between diesel, gasoline, E-85, and 

compressed natural gas (CNG) vehicles. The sector characterizes emissions from parked vehicle

processes (e.g. starts, hot soak, and extended idle) as well as from on-network processes (i.e., from 

vehicles moving along the roads). Except for California, all onroad emissions are generated using the 

SMOKE-MOVES emissions modeling framework that leverages MOVES generated outputs 

(http://www.epa.gov/otaq/models/moves/index.htm) and hourly meteorology. The SCCs used in the 

2011v6.2 platform are significantly different than what was used in previous platforms. The new onroad 

SCCs were designed to be more consistent with MOVES. For more details, see the 2011NEIv2 TSD. 

Updates to speciation, temporal allocation, and spatial allocation for the onroad sector were made in the

2011v6.2 platform as a result of comments received and upgrades to the platform. Sections 3.2, 3.3, and 

3.4 contain more details.

2.3.1 Onroad (onroad)

For the continental U.S., EPA used a modeling framework that took into account the temperature 

sensitivity of the on-road emissions. Specifically, EPA used MOVES inputs for representative counties, 

vehicle miles traveled (VMT) and vehicle population (VPOP) data for all counties, along with tools that 

integrated the MOVES model with SMOKE. In this way, it was possible to take advantage of the 

gridded hourly temperature information available from meteorology modeling used for air quality 

modeling. The “SMOKE-MOVES” integration tool was developed by EPA in 2010 and is used for 

regional air quality modeling of onroad mobile sources. 

SMOKE-MOVES requires that emission rate “lookup” tables be generated by MOVES which 

differentiate emissions by process (i.e., running, start, vapor venting, etc.), vehicle type, road type, 

temperature, speed, hour of day, etc. To generate the MOVES emission rates that could be applied 
22

across the U.S., EPA used an automated process to run MOVES to produce emission factors by 

temperature and speed for a series of “representative counties,” to which every other county was 

mapped. Using the MOVES emission rates, SMOKE selects appropriate emissions rates for each 

county, hourly temperature, SCC, and speed bin and multiplied the emission rate by activity (VMT 

(vehicle miles travelled), VPOP (vehicle population)), or HOTELING (hours of extended idle) to 

produce emissions. These calculations were done for every county and grid cell, in the continental U.S.

for each hour of the year. 

The SMOKE-MOVES process for creating the model-ready emissions consists of the following steps:

1) Determine which counties will be used to represent other counties in the MOVES runs.

2) Determine which months will be used to represent other month’s fuel characteristics.

3) Create MOVES inputs needed only by MOVES. MOVES requires county-specific information 

on vehicle populations, age distributions, and inspection-maintenance programs for each of the 

representative counties.

4) Create inputs needed both by MOVES and by SMOKE, including temperatures and activity data.

5) Run MOVES to create emission factor tables for the temperatures found in each county.

6) Run SMOKE to apply the emission factors to activity data (VMT, VPOP, and HOTELING) to 

calculate emissions based on the gridded hourly temperatures in the meteorological data.

7) Aggregate the results to the county-SCC level for summaries and quality assurance.

The onroad emissions inputs are similar to the emissions in the onroad data category of the 2011NEIv2, 

described in more detail in Section 4.6 of the 2011NEIv2 TSD. Specifically the platform and 

2011NEIv2 have identical:

 MOVES County databases (CDBs)

 Representative counties

 Fuel months

 Meteorology

 Activity data (VMT, VPOP, speed, HOTELING)

There are some key differences between the two onroad emission inventories:

 The 2011 platform used a different post-processor to create EFs for SMOKE because the 

pollutants needed for speciation and running CMAQ are different than what is needed for the 

NEI. For example, the NEI needs a much larger set of HAPs and the modeling platform requires 

emissions for the components of PM2.5.

 The 2011 platform had separate activity data for E-85. For the 2011 NEIv2, E-85 VMT and 

VPOP were combined with gasoline VMT and VPOP because the CDBs were not generating a 

complete set of EF for the E-85 sources. EPA corrected the seeding script and regenerated the 

representative CDBs so that the EF tables had a complete set of EF for all fuel types.

 The seeding of some representative counties left out the generation of combination long-haul 

trucks on rural restricted highways and therefore for no emission factors were generated and as 

a result hoteling emissions were zero. To mitigate this, the hoteling emission factors were taken 

from other nearby counties.
23

 The MOVES code and MOVES default database for the platform were version 20141021cb6 

and movesdb20141021cb6, respectively. Also for the platform, EPA updated the internal 

speciation of TOG to provide revised CB05 and CB6 model-species for air quality modeling.

 The 2011 platform used an updated fuel database: movesdb20141021_fuelsupply.

 The treatment of California emissions differs between the two inventories (see below for more 

details). 

 The list of emission modes and SCCs differ between the two inventories. Both SMOKEMOVES runs were generated at the same level of detail, but the NEI emissions were aggregated 

into 2 all-inclusive modes: refueling and all other modes. In addition, the NEI SCCs were 

aggregated over roads to all parking and all road emissions. The list of modes (or aggregate 

processes) used in the v6.2 platform and the corresponding MOVES processes mapped to them 

are listed in Table 2-11.

Table 2-11. Onroad emission aggregate processes

Aggregate process Description MOVES process IDs

40 All brake and tire wear 9;10

53 All extended idle exhaust 17;90

62 All refueling 18;19

72 All exhaust and evaporative except refueling and hoteling 1;2;11;12;13;15;16

91 Auxiliary Power Units 91

One reason that brake and tire wear was split out from the other processes was to allow for better 

modeling of the impacts of electric vehicles in future years, since these vehicles still have brake and tire 

wear emissions, but do not have exhaust, evaporative, or refueling emissions. For more detailed 

information on methods used to develop the onroad emissions and input data sets and on running 

SMOKE-MOVES, see the 2011NEIv2 TSD.

The California onroad emissions were created through a hybrid approach of combining state-supplied 

annual emissions (from the 2011NEIv2) with EPA developed SMOKE-MOVES runs. Through this 

approach, the platform was able to reflect California’s unique rules, while leveraging the more detailed 

SCCs and the highly resolved spatial patterns, temporal patterns, and speciation from SMOKE-MOVES. 

The basic steps involved in temporally allocating California’s onroad emissions based on SMOKEMOVES results were:

1) Run CA using EPA inputs through SMOKE-MOVES to produce hourly 2011 emissions

hereafter known as “EPA estimates”. These EPA estimates for CA are run in a separate sector 

called “onroad_ca”.

2) Calculate ratios between state-supplied emissions and EPA estimates3. For California, these 

were calculated for each county/comparison SCC64/pollutant combination. These were not 

 

3 These ratios were created for all matching pollutants. These ratios were duplicated for all appropriate modeling species. 

For example, EPA used the NOX ratio for NO, NO2, HONO and used the PM2.5 ratio for PEC, PNO3, POC, PSO4etc (For 

more details on NOX and PM speciation, see Sections 3.2.3 and 0). For VOC model-species, if there was an exact match 

(e.g., BENZENE), EPA used that HAP pollutant ratio. For other VOC-based model-species that didn’t exist in the NEI 

inventory, EPA used VOC ratios.

4 Comparison SCC6 are aggregate codes to classify fuels and vehicle type. These were created to make a consistent 

comparison between the MOBILE6 era SCCs (2011 NEIv1 and before) and MOVES SCCs (2011 NEIv2). See the 2011 

NEIv2 TSD for more details.
24

calculated at a greater resolution because California’s emissions did not provide data for all

vehicle types.

3) Create an adjustment factor file (CFPRO) that includes EPA-to-state estimate ratios. 

4) Rerun CA through SMOKE-MOVES using EPA inputs and the new adjustment factor file.

Through this process, adjusted model-ready files were created that sum to California’s annual totals, but 

have the temporal and spatial patterns reflecting the highly resolved meteorology and SMOKE-MOVES. 

After adjusting the emissions, this sector is called “onroad_ca_adj”. Note that in emission summaries, 

the emissions from the “onroad” and “onroad_ca_adj” sectors are summed and designated as the 

emissions for the onroad sector.

An additional step was taken for the refueling emissions. Colorado submitted point emissions for 

gasoline refueling for some counties5. For these counties, EPA zeroed out the onroad estimates of 

gasoline refueling (SCC 2201*62) so that the states’ point emissions would take precedence. The 

onroad refueling emissions were zeroed out using the adjustment factor file (CFPRO) and Movesmrg.

2.4 2011 nonroad mobile sources (c1c2rail, c3marine, nonroad)

The nonroad mobile source emission modeling sectors consist of nonroad equipment emissions 

(nonroad) and locomotive and commercial marine vessel (CMV) emissions divided into two nonroad 

sectors: “c1c2rail” and “c3marine”.

2.4.1 Category 1/Category 2 Commercial Marine Vessels and Locomotives and 

(c1c2rail)

The c1c2rail sector contains locomotive and smaller CMV sources, except for railway maintenance

locomotives. Railway maintenance emissions are included in the nonroad sector. The “c1c2” portion of 

this sector name refers to the Category 1 and 2 CMV emissions, not the railway emissions. The C3 

CMV emissions are in the c3marine and othpt sectors. All emissions in this sector are annual and at the 

county-SCC resolution. As discussed in Table 2-1 and Table 2-2, the modeling platform emissions for 

the c1c2rail SCCs were extracted from the 2011NEIv2 nonpoint inventory using the SCCs listed in

Table 2-12. The emissions include the offshore portion of the C1 and C2 commercial marine sources, 

including fishing vessels and oil rig support vessels in the Gulf of Mexico. Emissions that occur outside 

of state waters are not assigned to states. For more information on CMV and locomotive sources in the 

NEI, see Section 4.3 and Section 4.4 of the 2011NEIv2 TSD, respectively.

Table 2-12. 2011NEIv2 SCCs extracted for the starting point in c1c2rail development

SCC Description: Mobile Sources prefix for all

2280002100 Marine Vessels; Commercial; Diesel; Port

2280002200 Marine Vessels; Commercial; Diesel; Underway

2285002006 Railroad Equipment; Diesel; Line Haul Locomotives: Class I Operations

2285002007 Railroad Equipment; Diesel; Line Haul Locomotives: Class II / III Operations

2285002008 Railroad Equipment; Diesel; Line Haul Locomotives: Passenger Trains (Amtrak)

2285002009 Railroad Equipment; Diesel; Line Haul Locomotives: Commuter Lines

2285002010 Railroad Equipment; Diesel; Yard Locomotives

 

5 There were 53 counties in Colorado that had point emissions for gasoline refueling. Outside Colorado, it was determined 

that refueling emissions in the 2011 NEIv2 point did not significantly overlap the refueling emissions in onroad.
25

2.4.2 Category 3 commercial marine vessels (c3marine)

The Category 3 (C3) CMV sources in the c3marine sector of the 2011v6.2 platform run on residual oil 

and use the SCCs 2280003100 and 2280003200 for port and underway emissions, respectively, and are 

consistent with the 2011NEIv2. Emissions for this sector use state-submitted values and EPA-developed 

emissions in areas where states did not submit. A change in the 2011v6.2 platform is to restrict this 

sector only to include emissions in state-waters and to treat the emissions as nonpoint sources instead of 

point sources. Thus, the c3marine emissions are placed in layer 1 and allocated to grid cells using spatial

surrogates. Note that there are no Category 3 CMV emissions in the Great Lakes states, as all the vessels 

in that region are smaller than C3. The development of the ECA-IMO-based C3 CMV inventory is 

discussed below. Canadian emissions, C3 CMV emissions outside of state waters, and non-U.S. 

emissions farther offshore than U.S. waters are processed in the “othpt” sector (see Section 2.5.1). 

The EPA-estimated C3 CMV emissions were developed based on a 4-km resolution ASCII raster format 

dataset that preserves shipping lanes. This dataset has been used since the Emissions Control AreaInternational Marine Organization (ECA-IMO) project began in 2005, although it was then known as the 

Sulfur Emissions Control Area (SECA). The ECA-IMO emissions consist of large marine diesel 

engines (at or above 30 liters/cylinder) that until recently were allowed to meet relatively modest 

emission requirements and as a result these ships would often burn residual fuel in that region. The 

emissions in this sector are comprised of primarily foreign-flagged ocean-going vessels, referred to as 

C3 CMV ships. The c3marine inventory includes these ships in several intra-port modes (i.e., cruising, 

hoteling, reduced speed zone, maneuvering, and idling) and an underway mode, and includes near-port 

auxiliary engine emissions. 

An overview of the C3 ECA Proposal to the International Maritime Organization (EPA-420-F-10-041, 

August 2010) project and future-year goals for reduction of NOX, SO2, and PM C3 emissions can be 

found at: http://www.epa.gov/oms/regs/nonroad/marine/ci/420r09019.pdf. The resulting ECA-IMO 

coordinated strategy, including emission standards under the Clean Air Act for new marine diesel 

engines with per-cylinder displacement at or above 30 liters, and the establishment of Emission Control 

Areas is available from http://www.epa.gov/oms/oceanvessels.htm. The base year ECA inventory is 

2002 and consists of these CAPs: PM10, PM2.5, CO, CO2, NH3, NOX, SOX (assumed to be SO2), and 

hydrocarbons (assumed to be VOC). EPA developed regional growth (activity-based) factors that were 

applied to create the 2011 inventory from the 2002 data. These growth factors are provided in Table 

2-13. The geographic regions listed in the table are shown in Figure 2-2. * The East Coast and Gulf 

Coast regions were divided along a line roughly through Key Largo (longitude 80°26’ West). 

Technically, the EEZ FIPS are not really “FIPS” state-county codes, but are treated as such in the 

inventory and emissions processing.

Table 2-13. Growth factors to project the 2002 ECA-IMO inventory to 2011

Region EEZ FIPS NOX PM10 PM2.5 VOC CO SO2

East Coast (EC) 85004 1.301 0.500 0.496 1.501 1.501 0.536

Gulf Coast (GC) 85003 1.114 0.428 0.423 1.288 1.288 0.461

North Pacific (NP) 85001 1.183 0.467 0.458 1.353 1.353 0.524

South Pacific (SP) 85002 1.367 0.525 0.521 1.565 1.562 0.611

Great Lakes (GL) n/a 1.072 0.394 0.390 1.177 1.176 0.415

Outside ECA 98001 1.341 1.457 1.457 1.457 1.457 1.457
26

Figure 2-2. Illustration of regional modeling domains in ECA-IMO study

The emissions were converted to SMOKE point source inventory format as described in 

http://www.epa.gov/ttn/chief/conference/ei17/session6/mason.pdf, allowing for the emissions to be 

allocated to modeling layers above the surface layer. As described in the paper, the ASCII raster dataset 

was converted to latitude-longitude, mapped to state/county FIPS codes that extended up to 200 nautical 

miles (nm) from the coast, assigned stack parameters, and monthly ASCII raster dataset emissions were 

used to create monthly temporal profiles. All non-US, non-EEZ emissions (i.e., in waters considered 

outside of the 200 nm EEZ, and hence out of the U.S. and Canadian ECA-IMO controllable domain) 

were simply assigned a dummy state/county FIPS code=98001, and were projected to year 2011 using 

the “Outside ECA” factors in Table 2-13. 

The assignment of U.S. state/county FIPS codes was restricted to state-federal water boundaries data 

from the Mineral Management Service (MMS) that extend approximately 3 to 10 nautical miles (nm) off 

shore. Emissions outside the 3 to 10 mile MMS boundary, but within the approximately 200 nm EEZ 

boundaries in Figure 2-2, were projected to year 2011 using the same regional adjustment factors as the 

U.S. emissions; however, the state/county FIPS codes were assigned as “EEZ” codes and those 

emissions processed in the “othpt” sector (see Section 2.5.1). Note that state boundaries in the Great 

Lakes are an exception, extending through the middle of each lake such that all emissions in the Great 

Lakes are assigned to a U.S. county or Ontario. This holds true for Midwest states and other states such 

as Pennsylvania and New York. The classification of emissions to U.S. and Canadian FIPS codes is 

needed to avoid double-counting of C3 CMV U.S. emissions in the Great Lakes because, as discussed in 

the previous section, all CMV emissions in the Midwest RPO are processed in the “c1c2rail” sector.

The SMOKE-ready data have been cropped from the original ECA-IMO entire northwestern quarter of 

the globe to cover only the large continental U.S. 36-km “36US1” air quality model domain, the largest 

domain used by EPA in recent years6. 

 

6 The extent of the “36US1” domain is similar to the full geographic region shown in Figure 3-1. Note that this domain is not 

specifically used in this 2011 platform, although spatial surrogates that can be used with it are provided.
27

The original ECA-IMO inventory did not delineate between ports and underway emissions (or other C3 

modes such as hoteling, maneuvering, reduced-speed zone, and idling). However, a U.S. ports spatial 

surrogate dataset was used to assign the ECA-IMO emissions to ports and underway SCCs 2280003100 

and 2280003200, respectively. This had no effect on temporal allocation or speciation because all C3 

CMV emissions, unclassified/total, port and underway, share the same temporal and speciation profiles. 

See Section 3.2.1.3 for more details on c3marine speciation and Section 3.3.6 for details on temporal 

allocation.

For California, the ECA-IMO 2011 emissions were scaled to match those provided by CARB for year 

2011 because CARB has had distinct projection and control approaches for this sector since 2002. 

These CARB C3 CMV emissions are documented in a staff report available at: 

http://www.arb.ca.gov/regact/2010/offroadlsi10/offroadisor.pdf. The CMV emissions obtained from the 

CARB nonroad mobile dataset include the 2011 regulations to reduce emissions from diesel engines on 

commercial harbor craft operated within California waters and 24 nautical miles of the California 

shoreline. These emissions were developed using Version 1 of the California Emissions Projection 

Analysis Model (CEPAM) that supports various California off-road regulations. The locomotive 

emissions were obtained from the CARB trains dataset “ARMJ_RF#2002_ANNUAL_TRAINS.txt”. 

Documentation of the CARB offroad mobile methodology, including c1c2rail sector data, is provided at: 

http://www.arb.ca.gov/msei/categories.htm#offroad_motor_vehicles.

2.4.3 Nonroad mobile equipment sources: (nonroad)

The nonroad equipment emissions are equivalent to the emissions in the nonroad data category of the 

2011NEIv2, with the exception that the modeling platform emissions also include monthly totals. All 

nonroad emissions are compiled at the county/SCC level. NMIM (EPA, 2005) creates the nonroad 

emissions on a month-specific basis that accounts for temperature, fuel types, and other variables that 

vary by month. The nonroad sector includes monthly exhaust, evaporative and refueling emissions from 

nonroad engines (not including commercial marine, aircraft, and locomotives) that EPA derived from 

NMIM for all states except California and Texas. Additional details on the development of the 

2011NEIv2 nonroad emissions are available in Section 4.5 the 2011NEIv2 TSD. Note that the nonroad 

emissions for 2011NEIv2 are the same as those in the 2011NEIv1 for all states except Delaware.

California year 2011 nonroad emissions were submitted to the 2011NEIv2 and are also documented in a 

staff report (ARB, 2010a). The nonroad sector emissions in California were developed using a modular 

approach and include all rulemakings and updates in place by December 2010. These emissions were 

developed using Version 1 of the CEPAM which supports various California off-road regulations such 

as in-use diesel retrofits (ARB, 2007), Diesel Risk-Reduction Plan (ARB, 2000) and 2007 State 

Implementation Plans (SIPS) for the South Coast and San Joaquin Valley air basins (ARB, 2010b).

The CARB-supplied nonroad annual inventory emissions values were converted to monthly values by 

using the aforementioned EPA NMIM monthly inventories to compute monthly ratios by county, SCC7

(fuel, engine type, and equipment type group), mode, and pollutant. SCC7 ratios were used because the 

SCCs in the CARB inventory did not align with many of the SCCs in EPA NMIM inventory. By 

aggregating up to SCC7, the two inventories had a more consistent coverage of sources. Some VOC 

emissions were added to California to account for situations when VOC HAP emissions were included 

in the inventory, but there were no VOC emissions. These additional VOC emissions were computed by

summing benzene, acetaldehyde, and formaldehyde for the specific sources. 
28

Texas year 2011 nonroad emissions were also submitted to the NEI. The 2011NEIv2 nonroad annual 

inventory emissions values were converted to monthly values by using EPA’s NMIM monthly 

inventories to compute monthly ratios by county, SCC7, mode, and poll7.

Some updates to spatial surrogate assignments for the nonroad sector were made in the 2011v6.2 

platform in response to comments. Details can be found in Section 3.4.

2.5 “Other Emissions”: Offshore Category 3 commercial marine vessels 

and drilling platforms and non-U.S. sources

The emissions from Canada, Mexico, and non-U.S. offshore Category 3 Commercial Marine Vessels 

(C3 CMV) and drilling platforms are included as part of three emissions modeling sectors: othpt, othar, 

and othon. The “oth” refers to the fact that these emissions are usually “other” than those in the U.S. 

state-county geographic FIPS, and the third and fourth characters provide the SMOKE source types: 

“pt” for point, “ar” for “area and nonroad mobile”, and “on” for onroad mobile.

2.5.1 Point sources from offshore C3 CMV, drilling platforms, Canada and 

Mexico (othpt)

As discussed in Section 2.4.2, the ECA-IMO-based C3 CMV emissions outside of state waters are 

processed in the othpt sector. These C3 CMV emissions include those assigned to U.S. federal waters, 

Canada, those assigned to the Exclusive Economic Zone (EEZ; defined as those emissions beyond the 

U.S. Federal waters approximately 3-10 miles offshore, and extending to about 200 nautical miles from 

the U.S. coastline), along with any other offshore emissions. These emissions are developed in the same 

way as the EPA-dataset described in the c3marine sector (see Section 2.4.2). Emissions in U.S. waters 

are aggregated into large regions and included in the 2011NEIv2 using special FIPS codes. Because 

these emissions are treat as point sources, shipping lane routes can be preserved and they may be 

allocated to air quality model layers higher than layer 1.

For Canadian point sources, 2010 emissions provided by Environment Canada were used. Note that 

VOC was not provided for Canadian point sources, but any VOC emissions were speciated into CB05 

species. Temporal profiles and speciated emissions were also provided. Point sources in Mexico were 

compiled based on the Inventario Nacional de Emisiones de Mexico, 2008 (ERG, 2014a). The point 

source emissions in the 2008 inventory were converted to English units and into the FF10 format that 

could be read by SMOKE, missing stack parameters were gapfilled using SCC-based defaults, and 

latitude and longitude coordinates were verified and adjusted if they were not consistent with the 

reported municipality. Note that there are no explicit HAP emissions in this inventory.

The othpt sector also includes point source offshore oil and gas drilling platforms that are beyond U.S. 

state-county boundaries in the Gulf of Mexico. For these offshore emissions, data from the 2011NEIv2

were used. 

2.5.2 Area and nonroad mobile sources from Canada and Mexico (othar, 

othafdust)

For Canada area and nonroad mobiles sources, year-2010 emissions provided by Environment Canada

were used, including C3 CMV emissions. An overlap between these emissions and the U.S. C3 CMV 

 

7

If there was no match at county/SCC7/mode/poll, the allocation would fall back to state/SCC7/mode/poll. If that did not 

find a match, then state/SCC7 was used. For a few situations, that would also fail to match and the monthly emissions were 

allocated with a similar SCC7.
29

emissions in the St. Lawrence River resulted in a double count in the 2011v6.2 platform cases. The 

Canadian inventory included fugitive dust emissions that do not incorporate either a transportable 

fraction or meteorological-based adjustments. To properly account for these issues, a separate sector 

called othafdust was created and modeled using the same adjustments as are done for U.S. sources (see 

Section 2.2.1 for more details). Updated Shapefiles for creating spatial surrogates for Canada were also 

provided. 

Area and nonroad mobile sources in Mexico were compiled from the Inventario Nacional de Emisiones 

de Mexico, 2008 (ERG, 2014a). The 2008 emissions were quality assured for completeness, SCC 

assignments were made when needed, the pollutants expected for the various processes were reviewed, 

and adjustments were made to ensure that PM10 was greater than or equal to PM2.5. The resulting 

inventory was written using English units to the nonpoint FF10 format that could be read by SMOKE.

Note that unlike the U.S. inventories, there are no explicit HAPs in the nonpoint or nonroad inventories 

for Canada and Mexico, and therefore all HAPs are created from speciation.

2.5.3 Onroad mobile sources from Canada and Mexico (othon)

Onroad mobile sources in Mexico were compiled from the Inventario Nacional de Emisiones de 

Mexico, 2008 (ERG, 2014a). SCCs compatible with the 2011NEIv2 were assigned to the 2008 onroad 

mobile source emissions in Mexico, and it was enforced that PM10 be greater than or equal to PM2.5.

Quality assurance of the onroad mobile source emissions data revealed that Baja California, Michoacán, 

and Nuevo León had significantly high per capita emissions for all pollutants and should be considered 

to be outliers. The emissions for these states were replaced with values computed based on the average 

per capita emissions for the remaining states. The data were written using English units to the nonpoint 

FF10 format that could be read by SMOKE. 

For Canada, year-2010 emissions provided by Environment Canada were used. Note that unlike the 

U.S. inventories, there are no explicit HAPs in the onroad inventories for Canada and Mexico, and 

therefore all HAPs are created from speciation.

2.6 Fires (ptwildfire, ptprescfire)

In the 2011v6.2 platform, wildfires are in the ptwildfire sector and prescribed burning emissions are 

contained in the ptprescfire sector. The sectors were split from the single ptfire sector used in previous 

emissions to aid in the analysis of the impacts of the different types of fires. Fire emissions are specified 

at geographic coordinates (point locations) and have daily emissions values. The ptwildfire and 

ptprescfire sectors exclude agricultural burning and other open burning sources that are included in the 

nonpt sector. Emissions are day-specific and include satellite-derived latitude/longitude of the fire’s 

origin and other parameters associated with the emissions such as acres burned and fuel load, which 

allow estimation of plume rise. Emissions for the SCCs listed in Table 2-14 are treated as point sources 

and are consistent with the fires stored in the Events data category of the 2011NEIv2. Emissions for 

SCC 2811015000 are in the ptprescfire sector, while the rest are in the ptwildfire sector. For more 

information on the development of the 2011NEIv2 fire inventory, see Section 5.1 of the 2011NEIv2

TSD.
30

Table 2-14. 2011 Platform SCCs representing emissions in the ptprescfire and ptwildfire modeling 

sectors

SCC SCC Description*

2810001000 Other Combustion; Forest Wildfires; Total

2810001001 Other Combustion; Forest Wildfires; Wildland fire use

2811015000 Other Combustion-as Event; Prescribed Burning for Forest Management; Total

* The first tier level of the SCC Description is “Miscellaneous Area Sources” 

The point source day-specific emission estimates for 2011 fires rely on SMARTFIRE 2 (Sullivan, et al., 

2008), which uses the National Oceanic and Atmospheric Administration’s (NOAA’s) Hazard Mapping 

System (HMS) fire location information as input. Additional inputs include the CONSUMEv3.0 

software application (Joint Fire Science Program, 2009) and the Fuel Characteristic Classification 

System (FCCS) fuel-loading database to estimate fire emissions from wildfires and prescribed burns on 

a daily basis. The method involves the reconciliation of ICS-209 reports (Incident Status Summary 

Reports) with satellite-based fire detections to determine spatial and temporal information about the 

fires. A functional diagram of the SMARTFIRE 2 process of reconciling fires with ICS-209 reports is 

available in the documentation (Raffuse, et al., 2007). Once the fire reconciliation process is completed, 

the emissions are calculated using the U.S. Forest Service’s CONSUMEv3.0 fuel consumption model 

and the FCCS fuel-loading database in the BlueSky Framework (Ottmar, et al., 2007).

SMARTFIRE 2 estimates were used directly for all states except Georgia and Florida. For Georgia, the 

satellite-derived emissions were removed from the ptfire inventory and replaced with a separate statesupplied ptfire inventory. Adjustments were also made to Florida as described in Section 5.1.4 of the 

2011NEIv2 TSD. These changes made the data in the ptfire inventory consistent with the data in the 

2011NEIv2. 

An update in the 2011v6.2 platform was to split fires over 20,000 acres into the respective grid cells that 

they overlapped. The idea of this was to prevent all emissions from going into a single grid cell, when 

in reality the fire was more dispersed than a single point. The large fires were each projected as a circle 

over the area centered on the specified latitude and longitude, and then apportioned into the grid cells 

they overlapped. The area of each of the “subfires” was computed in proportion to the overlap with that 

grid cell. These “subfires” were given new names that were the same as the original, but with “_a”, 

“_b”, “_c”, and “_d” appended as needed. The FIPS state and county codes and fire IDs for the fifteen 

fires apportioned to multiple grid cells are shown in Table 2-15.

Table 2-15. Large fires apportioned to multiple grid cells

County FIPS Fire ID

32007 SF11C1774898

32007 SF11C1775252

32013 SF11C1774993

35027 SF11C1760072

35027 SF11C1760460

46065 SF11C1503125

48003 SF11C1718109

48081 SF11C1742329

48125 SF11C1749358
31

County FIPS Fire ID

48243 SF11C1738273

48243 SF11C1747162

48353 SF11C1759082

48371 SF11C1750272

48415 SF11C1742358

56013 SF11C1791126

2.7 Biogenic sources (beis)

Biogenic emissions were computed based on the same 11g version of the 2011 meteorology data used 

for the air quality modeling, and were developed using the Biogenic Emission Inventory System, version 

3.61 (BEIS3.61) within SMOKE. This was an update from the emissions in the 2011v6.1 platform that 

used BEIS 3.14, and from the 2011NEIv2 that used BEIS 3.60. Like BEIS 3.14, BEIS3.61 creates 

gridded, hourly, model-species emissions from vegetation and soils. It estimates CO, VOC (most 

notably isoprene, terpene, and sesquiterpene), and NO emissions for the contiguous U.S. and for 

portions of Mexico and Canada. 

BEIS3.61 has some important updates from BEIS 3.14. These include the incorporation of Version 4 of 

the Biogenic Emissions Land use Database (BELD4), and the incorporation of a canopy model to 

estimate leaf-level temperatures (Pouliot and Bash, 2015). BEIS version 3.61 includes a two-layer 

canopy model. Layer structure varies with light intensity and solar zenith angle. Both layers of the 

canopy model include estimates of sunlit and shaded leaf area based on solar zenith angle and light 

intensity, direct and diffuse solar radiation, and leaf temperature (Bash et al., 2015). The new algorithm 

requires additional meteorological variables over previous versions of BEIS. The variables output from 

the Meteorology-Chemistry Interface Processor (MCIP) that are used to convert WRF outputs to CMAQ 

inputs are shown in Table 2-16.

BELD4 is based on an updated version of the USDA-USFS Forest Inventory and Analysis (FIA) 

vegetation speciation based data from 2002 to 2013 from the Forest Inventory and Analysis version 5.1. 

Canopy coverage is based on the Landsat satellite NLCD product from 2001, since no canopy product 

was developed for the 2006 NLCD. The FIA includes approximately 250,000 representative plots of 

species fraction data that are within approximately 75 km of one another in areas identified as forest by 

the NLCD canopy coverage. The 2006 NLCD provides land cover information with a native data grid 

spacing of 30 meters. For land areas outside the conterminous United States, 500 meter grid spacing 

land cover data from the Moderate Resolution Imaging Spectroradiometer (MODIS) is used.

To provide a sense of the scope and spatial distribution of the emissions, plots of annual BEIS outputs 

for isoprene and NO for 2011 are shown in Figure 2-3 and Figure 2-4, respectively.
32

Figure 2-3. Annual NO emissions output from BEIS 3.61 for 2011

Figure 2-4. Annual isoprene emissions output from BEIS 3.61 for 2011
33

Table 2-16. Meteorological variables required by BEIS 3.61

Variable Description

LAI leaf-area index 

PRSFC surface pressure

Q2 mixing ratio at 2 m

RC convective pcpn per met TSTEP

RGRND solar rad reaching sfc

RN nonconvec. pcpn per met TSTEP

RSTOMI inverse of bulk stomatal resistance 

SLYTP soil texture type by USDA category

SOIM1 volumetric soil moisture in top cm 

SOIT1 soil temperature in top cm

TEMPG skin temperature at ground

USTAR cell averaged friction velocity

RADYNI inverse of aerodynamic resistance

TEMP2 temperature at 2 m

2.8 SMOKE-ready non-anthropogenic inventories for chlorine 

The ocean chlorine gas emission estimates are based on the build-up of molecular chlorine (Cl2) 

concentrations in oceanic air masses (Bullock and Brehme, 2002). Data at 36 km and 12 km resolution 

were available and were not modified other than the model-species name “CHLORINE” was changed to 

“CL2” to support CMAQ modeling. 
34

3 Emissions Modeling Summary

Both the CMAQ and CAMX models require hourly emissions of specific gas and particle species for the 

horizontal and vertical grid cells contained within the modeled region (i.e., modeling domain). To 

provide emissions in the form and format required by the model, it is necessary to “pre-process” the 

“raw” emissions (i.e., emissions input to SMOKE) for the sectors described above in Section 2. In brief, 

the process of emissions modeling transforms the emissions inventories from their original temporal 

resolution, pollutant resolution, and spatial resolution into the hourly, speciated, gridded resolution 

required by the air quality model. Emissions modeling includes temporal allocation, spatial allocation, 

and pollutant speciation. In some cases, emissions modeling also includes the vertical allocation of point 

sources, but many air quality models also perform this task because it greatly reduces the size of the 

input emissions files if the vertical layers of the sources are not included. 

As seen in Section 2, the temporal resolutions of the emissions inventories input to SMOKE vary across 

sectors, and may be hourly, daily, monthly, or annual total emissions. The spatial resolution, may be 

individual point sources, county/province/municipio totals, or gridded emissions and varies by sector. 

This section provides some basic information about the tools and data files used for emissions modeling 

as part of the modeling platform. In Section 2, the emissions inventories and how they differ from the 

2011NEIv2 were described. In Section 3, the descriptions of data are limited to the ancillary data 

SMOKE uses to perform the emissions modeling steps. Note that all SMOKE inputs for the 2011v6 

platform are available from the CHIEF Emissions Modeling Clearinghouse website (see Section 1).

SMOKE version 3.6.5 was used to pre-process the raw emissions inventories into emissions inputs for 

CMAQ. For projects that used CAMx, the CMAQ emissions were converted into the CAMx formats 

using CAMx convertor programs. For sectors that have plume rise, the in-line emissions capability of 

the air quality models was used, which allows the creation of source-based and two-dimensional gridded 

emissions files that are much smaller than full three-dimensional gridded emissions files. For quality 

assurance of the emissions modeling steps, emissions totals by specie for the entire model domain are 

output as reports that are then compared to reports generated by SMOKE on the input inventories to 

ensure that mass is not lost or gained during the emissions modeling process. 

3.1 Emissions modeling Overview

When preparing emissions for the air quality model, emissions for each sector are processed separately 

through SMOKE, and then the final merge program (Mrggrid) is run to combine the model-ready, 

sector-specific emissions across sectors. The SMOKE settings in the run scripts and the data in the 

SMOKE ancillary files control the approaches used by the individual SMOKE programs for each sector. 

Table 3-1 summarizes the major processing steps of each platform sector. The “Spatial” column shows 

the spatial approach used: here “point” indicates that SMOKE maps the source from a point location 

(i.e., latitude and longitude) to a grid cell; “surrogates” indicates that some or all of the sources use 

spatial surrogates to allocate county emissions to grid cells; and “area-to-point” indicates that some of 

the sources use the SMOKE area-to-point feature to grid the emissions (further described in Section

3.4.2). The “Speciation” column indicates that all sectors use the SMOKE speciation step, though 

biogenics speciation is done within the Tmpbeis3 program and not as a separate SMOKE step. The 

“Inventory resolution” column shows the inventory temporal resolution from which SMOKE needs to 

calculate hourly emissions. Note that for some sectors (e.g., onroad, beis), there is no input inventory;

instead, activity data and emission factors are used in combination with meteorological data to compute 

hourly emissions. 
35

Finally, the “plume rise” column indicates the sectors for which the “in-line” approach is used. These 

sectors are the only ones with emissions in aloft layers based on plume rise. The term “in-line” means 

that the plume rise calculations are done inside of the air quality model instead of being computed by 

SMOKE. The air quality model computes the plume rise using the stack data and the hourly air quality 

model inputs found in the SMOKE output files for each model-ready emissions sector. The height of 

the plume rise determines the model layer into which the emissions are placed. The othpt sector has only 

“in-line” emissions, meaning that all of the emissions are treated as elevated sources and there are no 

emissions for those sectors in the two-dimensional, layer-1 files created by SMOKE. Day-specific point 

fires are treated separately. For CMAQ modeling, fire plume rise is done within CMAQ itself, but for 

CAMx, the plume rise is done by running SMOKE to create a three-dimensional output file and then 

those emissions are postprocessed into a point source format that CAMx can read. In either case, after 

plume rise is applied, there will be emissions in every layer from the ground up to the top of the plume.

Table 3-1. Key emissions modeling steps by sector.

Platform sector Spatial Speciation

Inventory

resolution Plume rise

afdust Surrogates Yes annual

ag Surrogates Yes annual

agfire Surrogates Yes monthly

beis Pre-gridded 

land use in BEIS3.14 computed hourly

c1c2rail Surrogates Yes annual

c3marine Surrogates Yes annual in-line

nonpt Surrogates &

area-to-point Yes annual

nonroad Surrogates &

area-to-point Yes monthly

np_oilgas Surrogates Yes annual

onroad Surrogates Yes monthly activity, 

computed hourly

othafdust Surrogates Yes annual

othar Surrogates Yes annual

othon Surrogates Yes annual

othpt Point Yes annual in-line

pt_oilgas Point Yes annual in-line

ptegu Point Yes daily & hourly in-line

ptprescfire Point Yes daily in-line

ptwildfire Point Yes daily in-line

ptnonipm Point Yes annual in-line

rwc Surrogates Yes annual

SMOKE has the option of grouping sources so that they are treated as a single stack when computing 

plume rise. For the 2011 platform, no grouping was performed because grouping combined with “inline” processing will not give identical results as “offline” processing (i.e., when SMOKE creates 3-

dimensional files). This occurs when stacks with different stack parameters or lat/lons are grouped, 

thereby changing the parameters of one or more sources. The most straightforward way to get the same 

results between in-line and offline is to avoid the use of grouping. 
36

To prepare fires for CAMx using a plume rise algorithm that is consistent with the algorithms in 

SMOKE and CMAQ, the following steps are performed:

1) The ptfire inventories are run through SMOKE programs to read the inventories, speciate, 

temporalize, and grid the emissions.

2) The SMOKE program laypoint is used to estimate the plume height and layer fractions for 

each fire (see 

https://www.cmascenter.org/smoke/documentation/3.6.5/html/ch06s06.html#sect_programs_

laypoint_plume_rise_fires). 

3) The emissions are gridded and layered, and then written as three-dimensional netCDF 

CMAQ ready files.

4) Species in the CMAQ-formatted file are converted to CAMx species using the spcmap

program.

5) The netCDF fire files are converted to a CAMx “PTSOURCE” type file where each grid cell 

centroid represents one stack using the cmaq2uam program. Note: each virtual stack has 

default stack parameters of 1 m height, 1 m diameter, 273 K temperature, and 1 m/s velocity.

Also, an individual virtual stack point (grid cell centroid) will have all of the emissions for 

the grid cell divided up into layers with an effective plume height at each layer. Only the

layers that contain emissions are kept for each virtual stack.

6) The program pthtq is run to add an effective plume height based on the cell center height 

from the METCRO3D (ZH).

7) The resulting PTSOURCE files have emissions as a stack at (x,y) that to up to layer z that is 

derived from the CMAQ 3D file, and are merged with the PTSOURCE sector files from 

other sectors into a single PTSOURCE file with stacks for all point sources. This file, along 

with the 2D emissions file, is input into the CAMx model.

SMOKE was run for the smaller 12-km CONtinental United States “CONUS” modeling domain 

(12US2) shown in Figure 3-1 and boundary conditions were obtained from a 2011 run of GEOS-Chem. 
37

Figure 3-1. Air quality modeling domains

Both grids use a Lambert-Conformal projection, with Alpha = 33o, Beta = 45o and Gamma = -97o, with a 

center of X = -97o and Y = 40o. Table 3-2 describes the grids for the two domains.

Table 3-2. Descriptions of the platform grids

Common 

Name

Grid 

Cell Size

Description 

(see Figure 3-1) Grid name

Parameters listed in SMOKE grid 

description (GRIDDESC) file:

 projection name, xorig, yorig, 

 xcell, ycell, ncols, nrows, nthik

Continental 

12km grid 12 km

Entire conterminous 

US plus some of 

Mexico/Canada

12US1_459X299 ‘LAM_40N97W', -2556000, -1728000, 

12.D3, 12.D3, 459, 299, 1

US 12 km or 

“smaller” 

CONUS-12

12 km

Smaller 12km 

CONUS plus some of 

Mexico/Canada

12US2 ‘LAM_40N97W', -2412000 , -

1620000, 12.D3, 12.D3, 396, 246, 1

Section 3.4 provides the details on the spatial surrogates and area-to-point data used to accomplish 

spatial allocation with SMOKE.
38

3.2 Chemical Speciation

The emissions modeling step for chemical speciation creates the “model species” needed by the air 

quality model for a specific chemical mechanism. These model species are either individual chemical 

compounds or groups of species, called “model species.” The chemical mechanism used for the 2011 

platform is the CB6 mechanism (Yarwood, 2010). The 2011v6.2 platform is the first EPA modeling 

platform to use CB6; previous platforms used CB05 and earlier versions of the carbon bond mechanism. 

The key difference in CB6 from CB05 from an emissions modeling perspective is that is has additional 

lumped and explicit model species. The specific version of CAMx used in applications of this platform 

include secondary organic aerosol (SOA) and HONO enhancements. In addition, this platform 

generates the PM2.5 model species associated with the CMAQ Aerosol Module, version 6 (AE6), though 

they are not used by CAMX. Table 3-3 lists the model species produced by SMOKE in the 2011v6.2 

platform and Table 3-4 provides the cmaq2camx mapping file used to convert the SMOKE generated 

model species to the appropriate inputs for CAMX.

The TOG and PM2.5 speciation factors that are the basis of the chemical speciation approach were 

developed from the SPECIATE 4.4 database (http://www.epa.gov/ttn/chief/software/speciate), which is 

EPA's repository of TOG and PM speciation profiles of air pollution sources. However, a few of the 

profiles used in the v6.2 platform will be published in later versions of the SPECIATE database after the 

release of this documentation. The SPECIATE database development and maintenance is a collaboration 

involving EPA’s ORD, OTAQ, and the Office of Air Quality Planning and Standards (OAQPS), in 

cooperation with Environment Canada (EPA, 2006a). The SPECIATE database contains speciation 

profiles for TOG, speciated into individual chemical compounds, VOC-to-TOG conversion factors 

associated with the TOG profiles, and speciation profiles for PM2.5. 

Some updates to speciation made in the 2011v6.2 platform include the following (the subsections below 

contain more details on the specific changes):

 VOC speciation profile cross reference assignments for nonpoint oil and gas sources were 

updated based on comments;

 VOC and PM speciation for onroad mobile sources occurs within MOVES2014;

 the latest CB6 chemical mechanism was used;

 only AE6 PM species are included, where previously both AE5 and AE6 species were generated;

 the 2010 Canadian point source inventories in the othpt use CB05 speciation as it was provided 

from Environment Canada; and

 speciation for onroad mobile sources in Mexico was updated to be more consistent with that used

in the United States.

Speciation profiles and cross-references for the 2011v6.2 platform are available in the SMOKE input 

files for the 2011v6.2 platform. Totals of each model species by state and sector can be found in the 

state-sector totals workbooks for the respective cases. In addition, the county-monthly reports for each 

case include EC and OC, and the 2011eh_county_SCC7_sector_CAP_PM.xlsx workbook contains 

speciated PM by county and the first seven digits of the SCC code.
39

Table 3-3. Emission model species produced for CB6 for CAMX*

Inventory Pollutant Model Species Model species description

Cl2 CL2 Atomic gas-phase chlorine

HCl HCL Hydrogen Chloride (hydrochloric acid) gas

CO CO Carbon monoxide

NOX NO Nitrogen oxide

NO2 Nitrogen dioxide

HONO Nitrous acid

SO2 SO2 Sulfur dioxide

SULF Sulfuric acid vapor

NH3 NH3 Ammonia

VOC ACET Acetone

ALD2 Acetaldehyde

ALDX Propionaldehyde and higher aldehydes

BENZ Benzene 

CH4 Methane8

ETH Ethene

ETHA Ethane

ETHY Ethyne

ETOH Ethanol

FORM Formaldehyde

KET Ketone Groups

IOLE Internal olefin carbon bond (R-C=C-R)

ISOP Isoprene

MEOH Methanol

OLE Terminal olefin carbon bond (R-C=C)

PAR Paraffin carbon bond

PRPA Propane

TOL Toluene and other monoalkyl aromatics

XYL Xylene and other polyalkyl aromatics

VOC species from the biogenics 

model that do not map to model 

species above

SESQ Sesquiterpenes

TERP Terpenes

PM10 PMC Coarse PM > 2.5 microns and  10 microns

 

8 Technically, CH4 is not a VOC but part of TOG. Although emissions of CH4 are derived, the AQ models do not use these 

emissions because the anthropogenic emissions are dwarfed by the CH4 already in the atmosphere.
40

Inventory Pollutant Model Species Model species description

PM2.5 PAL Aluminum

PCA Calcium

PCL Chloride

PEC Particulate elemental carbon  2.5 microns

PFE Iron

PK Potassium

PH2O Water

PMG Magnesium

PMN Manganese

PMOTHR PM2.5 not in other AE6 species

PNA Sodium

PNCOM Non-carbon organic matter

PNO3 Particulate nitrate  2.5 microns

PNH4 Ammonium

POC Particulate organic carbon (carbon only)  2.5 microns

PSI Silica

PSO4 Particulate Sulfate  2.5 microns

PTI Titanium

Sea-salt species (non –

anthropogenic)

9

PCL Particulate chloride

PNA Particulate sodium

*Notes:

1. CL2 is not used in CAMX and is provided above because of its use in CMAQ

2. CAMX particulate sodium is NA (in CMAQ it is PNA)

3. CAMX uses different names for species that are both in CB6 and SOA for the following: TOLA=TOL, XYLA=XYL, 

ISP=ISOP, TRP=TERP. They are duplicate species in CAMX that are used in the SOA chemistry. CMAQ uses the same 

names in CB05 and SOA for these species.

4. CAMX uses a different name for sesquiterpenes: CMAQ SESQ = CAMX SQT

5. CAMX particulate species have different names for organic carbon, coarse particulate matter and other particulate mass: 

CAMX uses POA, CPRM, FCRS, and FPRM, respectively.

 

9 These emissions are created outside of SMOKE
41

Table 3-4. Cmaq2camx mapping file

CMAQ 

Species

CMAQ to

CAMx 

Factor

CAMx 

Species Units

CMAQ 

Species

CMAQ 

to CAMx 

Factor

CAMx 

Species Units

SO2 1 SO2 moles/hr UNR 1 NR moles/hr

SULF 1 SULF moles/hr NR 1 NR moles/hr

NH3 1 NH3 moles/hr TOL 1 TOLA moles/hr

CO 1 CO moles/hr XYL 1 XYLA moles/hr

NO 1 NO moles/hr PSO4 1 PSO4 g/hr

NO2 1 NO2 moles/hr PH2O 1 PH2O g/hr

HONO 1 HONO moles/hr PNH4 1 PNH4 g/hr

CL2 1 CL2 moles/hr PNO3 1 PNO3 g/hr

HCL 1 HCL moles/hr PEC 1 PEC g/hr

CH4 1 CH4 moles/hr POC 1 POC g/hr

PAR 1 PAR moles/hr PMOTHR 1 PMOTHR g/hr

ETHA 1 ETHA moles/hr PMC 1 CPRM g/hr

MEOH 1 MEOH moles/hr ISOP 1 ISP moles/s

ETOH 1 ETOH moles/hr TERP 1 TRP moles/s

ETH 1 ETH moles/hr SESQ 1 SQT moles/s

OLE 1 OLE moles/hr PCL 1 PCL g/hr

IOLE 1 IOLE moles/hr PNCOM 1 PNCOM g/hr

ISOP 1 ISOP moles/hr PAL 1 PAL g/hr

TERP 1 TERP moles/hr PCA 1 PCA g/hr

FORM 1 FORM moles/hr PFE 1 PFE g/hr

ALD2 1 ALD2 moles/hr PMG 1 PMG g/hr

ALDX 1 ALDX moles/hr PK 1 PK g/hr

TOL 1 TOL moles/hr PMN 1 PMN g/hr

XYL 1 XYL moles/hr PSI 1 PSI g/hr

PRPA 1 PRPA moles/hr PTI 1 PTI g/hr

ETHY 1 ETHY moles/hr PNA 1 NA g/hr

BENZ 1 BENZ moles/hr POC 1 POA g/hr

ACET 1 ACET moles/hr PNCOM 1 POA g/hr

KET 1 KET moles/hr

3.2.1 VOC speciation

The concept of VOC speciation is to use emission source-related speciation profiles to convert VOC to 

TOG, to speciate TOG into individual chemical compounds, and to use a chemical mechanism mapping 

file to aggregate the chemical compounds to the chemical mechanism model species. The chemical 

mechanism mapping file is typically developed by the developer of the chemical mechanism.

SMOKE uses profiles that convert inventory species and TOG directly to the model species. The 

SMOKE-ready profiles are generated from the Speciation Tool which uses the “raw” (TOG to chemical 

compounds) SPECIATE profiles and the chemical mechanism mapping file. 

For the 2011v6.2 platform, Greg Yarwood (ENVIRON) provided the CB6 chemical mapping file based 

on the latest mechanism table for CB05 from Bill Carter. This CB6 mapping file included some 
42

corrections to the CB05 profiles used in the 2011v6.1 platform. Similarly to previous platforms, HAP 

VOC inventory species were used in the VOC speciation process for some sectors as described below. 

3.2.1.1 The combination of HAP BAFM (benzene, acetaldehyde, formaldehyde and 

methanol) and VOC for VOC speciation

The VOC speciation includes HAP emissions from the 2011NEIv2 in the speciation process. Instead of 

speciating VOC to generate all of the species listed in Table 3-3, emissions of four specific HAPs: 

benzene, acetaldehyde, formaldehyde and methanol (collectively known as “BAFM”) from the NEI 

were “integrated” with the NEI VOC. The integration combines these HAPs with the VOC in a way 

that does not double count emissions and uses the HAP inventory directly in the speciation process. The 

basic process is to subtract the specified HAPs emissions mass from the VOC emissions mass, and to 

then use a special “integrated” profile to speciate the remainder of VOC to the model species excluding 

the specific HAPs. EPA believes that the HAP emissions in the NEI are often more representative of 

emissions than HAP emissions generated via VOC speciation, although this varies by sector.

The BAFM HAPs (benzene, acetaldehyde, formaldehyde and methanol) were chosen for integration in 

previous platforms because, with the exception of BENZENE10, they are the only explicit VOC HAPs in 

the base version of the CMAQ 5.0.2 (CAPs only with chlorine chemistry) model. These remain 

appropriate for the 2011v6.2 platform since they are all explicit in CAMx. Explicit means that they are 

not lumped chemical groups like PAR, IOLE and several other CB6 model species. These “explicit 

VOC HAPs” are model species that participate in the modeled chemistry using the CB6 chemical 

mechanism. The use of inventory HAP emissions along with VOC is called “HAP-CAP integration”. 

For specific sources, especially within the nonpt sector, the integration included ethanol. To 

differentiate when a source was integrating BAFM versus EBAFM (ethanol in addition to BAFM), the 

speciation profiles that do not include ethanol are referred to as an “E-profile” and should be used when 

ethanol comes from the inventory. For example, the E10 headspace gasoline evaporative speciation 

profile 8763 should be used when ethanol is speciated from VOC, but 8763E should be used when

ethanol is obtained directly from the inventory. 

The integration of HAP VOC with VOC is a feature available in SMOKE for all inventory formats other 

than PTDAY (the format used for the ptfire sector). SMOKE allows the user to specify both the 

particular HAPs to integrate via the INVTABLE and the particular sources to integrate via the 

NHAPEXCLUDE file (which actually provides the sources to be excluded from integration11). For the 

“integrated” sources, SMOKE subtracts the “integrated” HAPs from the VOC (at the source level) to 

compute emissions for the new pollutant “NONHAPVOC.” The user provides NONHAPVOC-toNONHAPTOG factors and NONHAPTOG speciation profiles12. SMOKE computes NONHAPTOG and 

then applies the speciation profiles to allocate the NONHAPTOG to the other air quality model VOC 

species not including the integrated HAPs. After determining if a sector is to be integrated, if all sources 

have the appropriate HAP emissions, then the sector is considered fully integrated and does not need a 

NHAPEXCLUDE file. If on the other hand, certain sources do not have the necessary HAPs, then an

 

10 BENZENE was chosen to keep its emissions consistent between the multi-pollutant and base versions of CMAQ

11 In SMOKE version 3.6.5, the options to specify sources for integration are expanded so that a user can specify the 

particular sources to include or exclude from integration, and there are settings to include or exclude all sources within a 

sector. In addition, the error checking is significantly stricter for integrated sources. If a source is supposed to be integrated, 

but it is missing BAFM or VOC, SMOKE will now raise an error.

12 These ratios and profiles are typically generated from the Speciation Tool when it is run with integration of a specified list 

of pollutants, for example BAFM.
43

NHAPEXCLUDE file must be provided based on the evaluation of each source’s pollutant mix. EPA 

considered CAP-HAP integration for all sectors and developed “integration criteria” for some of them 

(see Section 3.2.1.3 for details).

The process of partial integration for BAFM is illustrated in Figure 3-2 that the BAFM records in the 

input inventories do not need to be removed from any sources in a partially integrated sector because 

SMOKE does this automatically using the INVTABLE configuration. For EBAFM integration, this 

process is identical to that shown in the figure except for the addition of ethanol (E) to the list of 

subtracted HAP pollutants. For full integration, the process would be very similar except that the 

NHAPEXCLUDE file would not be used and all sources in the sector would be integrated.

Figure 3-2. Process of integrating BAFM with VOC for use in VOC Speciation

In SMOKE, the INVTABLE allows the user to specify both the particular HAPs to integrate. Two 

different types of INVTABLE files are included for use with different sectors of the platform. For 

sectors that had no integration across the entire sector (see Table 3-5), EPA created a “no HAP use” 

INVTABLE in which the “KEEP” flag is set to “N” for BAFM pollutants. Thus, any BAFM pollutants 

in the inventory input into SMOKE are automatically dropped. This approach both avoids doublecounting of these species and assumes that the VOC speciation is the best available approach for these 

species for sectors using this approach. The second INVTABLE, used for sectors in which one or more 

sources are integrated, causes SMOKE to keep the inventory BAFM pollutants and indicates that they 

are to be integrated with VOC. This is done by setting the “VOC or TOG component” field to “V” for 

all four HAP pollutants. This type of INVTABLE is further differentiated into a version for those 

sectors that integrate BAFM and another for those that integrate EBAFM.
44

Table 3-5. Integration approach for BAFM and EBAFM for each platform sector

Platform 

Sector

Approach for Integrating NEI emissions of Benzene (B), Acetaldehyde (A), 

Formaldehyde (F), Methanol (M), and Ethanol (E)

ptegu No integration 

ptnonipm No integration 

ptprescfire No integration

ptwildfire No integration 

othafdust No integration

othar No integration

othon No integration 

ag N/A – sector contains no VOC 

afdust N/A – sector contains no VOC

biog N/A – sector contains no inventory pollutant "VOC"; but rather specific VOC species

agfire Partial integration (BAFM)

c1c2rail Partial integration (BAFM)

c3marine Partial integration (BAFM)

nonpt Partial integration (BAFM and EBAFM)

nonroad Partial integration (BAFM)

np_oilgas Partial integration (BAFM)

pt_oilgas Partial integration (BAFM)

rwc Partial integration (BAFM)

othpt Partial integration (BAFM)

onroad Full integration (internal to MOVES)

More details on the integration of specific sectors and additional details of the speciation are provided in 

Section 3.2.1.3.

3.2.1.2 County specific profile combinations (GSPRO_COMBO)

SMOKE can compute speciation profiles from mixtures of other profiles in user-specified proportions. 

The combinations are specified in the GSPRO_COMBO ancillary file by pollutant (including pollutant 

mode, e.g., EXH__VOC), state and county (i.e., state/county FIPS code) and time period (i.e., 

month).This feature was used to speciate nonroad mobile and gasoline-related related stationary sources 

that use fuels with varying ethanol content. In these cases, the speciation profiles require different 

combinations of gasoline profiles, e.g. E0 and E10 profiles. Since the ethanol content varies spatially 

(e.g., by state or county), temporally (e.g., by month) and by modeling year (future years have more 

ethanol) the GSPRO_COMBO feature allows combinations to be specified at various levels for different 

years. SMOKE computes the resultant profile using the fraction of each specific profile assigned by 

county, month and emission mode. 

The GSREF file indicates that a specific source uses a combination file with the profile code 

“COMBO”. Because the GSPRO_COMBO file does not differentiate by SCC and there are various 

levels of integration across sectors, sector-specific GSPRO_COMBO files are used. Different profile 

combinations are specified by the mode (e.g. exhaust, evaporative) and by changing the pollutant name 

(e.g. EXH__NONHAPTOG, EVP__NONHAPTOG). For the nonpt sector, a combination of BAFM 

and EBAFM integration is used. Due to the lack of SCC-specificity in the GSPRO_COMBO, the only 

way to differentiate the sources that should use BAFM integrated profiles versus E-profiles is by 

changing the pollutant name. For example, EPA changed the pollutant name for the PFC future year 
45

inventory so the integration would use EVP__NONHAPVOC to correctly select the E-profile 

combinations, while other sources used NONHAPVOC to select the typical BAFM profiles.

3.2.1.3 Additional sector specific details

The decision to integrate HAPs into the speciation was made on a sector by sector basis. For some 

sectors there is no integration and VOC is speciated directly; for some sectors there is full integration 

meaning all sources are integrated; and for other sectors there is partial integration meaning some 

sources are not integrated and other sources are integrated. The integrated HAPs are either BAFM 

(BAFM HAPs subtracted from VOC) or EBAFM (ethanol and BAFM HAPs subtracted from VOC). 

Table 3-5 above summarizes the integration method for each platform sector. 

For the c1c2rail sector, EPA integrated BAFM for most sources from the 2011NEIv2. There were a few 

sources that had zero BAFM; therefore, they were not integrated. The MWRPO and CARB inventories 

(see Section 2.4.1) did not include HAPs; therefore, all non-NEI source emissions in the c1c2rail sector 

were not integrated. For California, the CARB inventory TOG was converted to VOC by dividing the 

inventory TOG by the available VOC-to-TOG speciation factor. 

For the othpt sector, the C3 marine sources (see Section 2.4.2) are integrated. HAPs in this sector are 

derived identically to the U.S. c3marine sector. The rest of the sources in othpt are not integrated, thus 

the sector is partially integrated.

For the onroad sector, there are series of unique speciation issues. First, SMOKE-MOVES (see Section

2.3.1) is used to create emissions for these sectors and both the MEPROC and INVTABLE files are 

involved in controlling which pollutants are processed. Second, the speciation occurs within MOVES 

itself, not within SMOKE. The advantage of using MOVES to speciate VOC is that during the internal 

calculation of MOVES, the model has complete information on the characteristics of the fleet and fuels 

(e.g. model year, ethanol content, process, etc.), thereby allowing it to more accurately make use of 

specific speciation profiles. This means that MOVES produces EF tables that include inventory 

pollutants (e.g. TOG) and model-ready species (e.g. PAR, OLE, etc)13. SMOKE essentially calculates 

the model-ready species by using the appropriate emission factor without further speciation14. Third, 

MOVES’ internal speciation uses full integration of an extended list of HAPs beyond EBAFM (called 

“M-profiles”). The M-profiles integration is very similar to BAFM integration explained above except 

that the integration calculation (see Figure 3-2) is performed on emissions factors instead of on 

emissions. The list of integrated HAPs is described in Table 3-6. An additional run of the speciation 

tool was necessary to create the M-profiles that were then loaded into the MOVES default database.

Fourth, for California EPA applied adjustment factors to SMOKE-MOVES to produce California 

adjusted model-ready files (see Section 2.3.1 for details). By applying the ratios through SMOKEMOVES, the CARB inventories are essentially speciated to match EPA estimated speciation.

 

13 Because the EF table has the speciation “baked” into the factors, all counties that are in the county group (i.e. are mapped 

to that reference county) will have the same speciation.

14 For more details on the use of model-ready EF, see the SMOKE 3.6.5 documentation:

https://www.cmascenter.org/smoke/documentation/3.6.5/html/
46

Table 3-6. MOVES integrated species in M-profiles

MOVES ID Pollutant Name

5 Methane (CH4)

20 Benzene

21 Ethanol

22 MTBE

24 1,3-Butadiene

25 Formaldehyde

26 Acetaldehyde

27 Acrolein

40 2,2,4-Trimethylpentane

41 Ethyl Benzene

42 Hexane

43 Propionaldehyde

44 Styrene

45 Toluene

46 Xylene

185 Naphthalene gas

For the nonroad sector, CNG or LPG sources (SCCs beginning with 2268 or 2267) are not integrated 

because NMIM computed only VOC and not any HAPs for these SCCs. All other nonroad sources were 

integrated except in California. For California, the CARB inventory TOG was converted to VOC by 

dividing the inventory TOG by the available VOC-to-TOG speciation factor. SMOKE later applies the 

same VOC-to-TOG factor prior to computing speciated emissions. The CARB-based nonroad data 

includes exhaust and evaporative mode-specific data for VOC, but does not contain refueling. The 

CARB inventory does not include HAP estimates for all sources. Therefore, the sources which have 

VOC but not BAFM, or for which BAFM is greater than VOC, are not integrated and the remaining 

sources are integrated. The future year CARB inventories did not have BAFM so all sources for 

California were not integrated. The gasoline exhaust profiles were updated to 8750a and 8751a (this is 

true nation-wide).

For the ptnonipm sector, the 2011, 2017 and 2025 runs were not integrated. This was an oversight— it 

should have been partial integration because the 2011 ethanol inventory (SCC 30125010) provided by 

OTAQ includes BAFM. In the future years, ptnonipm should be partially integrated because both the 

ethanol and biodiesel inventories (SCC 30125010) provided by OTAQ include BAFM. Aircraft 

emissions use the profile 5565. In previous versions of the platform, a significant amount of VOC 

emissions associated with the pulp and paper and the chemical manufacturing industries did not have 

specific profiles assigned to them (i.e. they had the default VOC profile 0000). To address this, EPA 

and Environ developed industry wide average profiles to improve the speciation of these significant 

sources of VOC. The two new composite profiles are “Composite Profile – Chemical Manufacturing 

(95325)” and “Composite Profile – Pulp and Paper Mills” (95326)15. 

 

15 These profiles are expected to be included in SPECIATE 4.5.
47

For most sources in the rwc sector, the VOC emissions were greater than or equal to BAFM, and BAFM 

was not zero, so those sources were integrated, although a few specific sources that did not meet these 

criteria could not be integrated.

For the oil and gas sources in the np_oilgas and pt_oilgas sectors, the basins studied in WRAP Phase III 

have basin-specific VOC speciation that takes into account the distinct composition of gas. ENVIRON 

developed these basin-specific profiles using gas composition analysis data obtained from operators 

through surveys. ENVIRON separated out emissions and speciation from conventional/tight sands/shale 

gas from coal‐bed methane (CBM) gas sources. Table 3-7 lists the basin- and gas composition-specific 

profiles used for the sources in the WRAP Phase III basins. For oil and gas sources outside of the 

WRAP Phase III basins, the profiles did not vary by region or basin (see Table 3-8). Table 3-9 lists the 

WRAP Phase III counties.

Table 3-7. VOC profiles for WRAP Phase III basins

Profile Code Description

DJFLA D-J Basin Flashing Gas Composition for Condensate

DJVNT D-J Basin Produced Gas Composition

PNC01 Piceance Basin Gas Composition at Conventional Wells

PNC02 Piceance Basin Gas Composition at Oil Wells

PNC03 Piceance Basin Flashing Gas Composition for Condensate

PRBCO Powder River Basin Produced Gas Composition for Conventional Wells

PRM01 Permian Basin Produced Gas Composition

SSJCO South San Juan Basin Produced Gas Composition for Conventional Wells

SWFLA SW Wyoming Basin Flash Gas Composition

SWVNT SW Wyoming Basin Vented Gas Composition

UNT02 Uinta Basin Gas Composition at Conventional Wells

UNT03 Uinta Basin Flashing Gas Composition for Oil

UNT04 Uinta Basin Flashing Gas Composition for Condensate

WRBCO Wind River Basin Produced Gas Composition for Conventional Wells

Table 3-8. National VOC profiles for oil and gas

profile Description

0000 Over All Average 

0001 External Combustion Boiler - Residual Oil 

0002 External Combustion Boiler - Distillate Oil 

0003 External Combustion Boiler - Natural Gas 

0004 External Combustion Boiler - Refinery Gas 

0007 Natural Gas Turbine 

0008 Reciprocating Diesel Engine 

0051 Flares - Natural Gas 

0296 Fixed Roof Tank - Crude Oil Production 

1001 Internal Combustion Engine - Natural Gas 

1010 Oil and Gas Production - Fugitives - Unclassified 

1011 Oil and Gas Production - Fugitives - Valves and Fittings - Liquid Service 
48

profile Description

1012 Oil and Gas Production - Fugitives - Valves and Fittings - Gas Service 

1207 Well Heads (Water Flood) Composite 

2487 Composite of 7 Emission Profiles from Crude Oil Storage Tanks - 1993 

2489 Composite of 15 Fugitive Emission Profiles from Petroleum Storage Facilities - 1993 

8489 Natural Gas Production

8950 Natural Gas Transmission

Table 3-9. Counties included in the WRAP Dataset

FIPS State County

08001 CO Adams 

08005 CO Arapahoe 

08007 CO Archuleta 

08013 CO Boulder 

08014 CO Broomfield 

08029 CO Delta 

08031 CO Denver 

08039 CO Elbert 

08043 CO Fremont 

08045 CO Garfield 

08051 CO Gunnison 

08059 CO Jefferson

08063 CO Kit Carson 

08067 CO La Plata 

08069 CO Larimer 

08073 CO Lincoln 

08075 CO Logan 

08077 CO Mesa 

08081 CO Moffat 

08087 CO Morgan 

08095 CO Phillips 

08097 CO Pitkin

08103 CO Rio Blanco 

08107 CO Routt 

08115 CO Sedgwick 

08121 CO Washington 

08123 CO Weld 

08125 CO Yuma 

30003 MT Big Horn 

30075 MT Powder River 

35005 NM Chaves

35015 NM Eddy

35015 NM Lea

FIPS State County

35031 NM Mc Kinley 

35039 NM Rio Arriba 

35041 NM Roosevelt

35043 NM Sandoval 

35045 NM San Juan 

48003 TX Andrews

48033 TX Borden

48079 TX Cochran

48081 TX Coke

48103 TX Crane

48105 TX Crockett

48107 TX Crosby

48109 TX Culberson

48115 TX Dawson

48125 TX Dickens

48135 TX Ector

48141 TX El Paso

48151 TX Fisher

48165 TX Gaines

48169 TX Garza

48173 TX Glasscock

48219 TX Hockley

48227 TX Howard

48229 TX Hudspeth

48235 TX Irion

48263 TX Kent

48269 TX King

48301 TX Loving

48303 TX Lubbock

48305 TX Lynn

48317 TX Martin

48329 TX Midland

48335 TX Mitchell

FIPS State County

48353 TX Nolan

48371 TX Pecos

48383 TX Reagan

48389 TX Reeves

48413 TX Schleicher

48415 TX Scurry

48431 TX Sterling

48435 TX Sutton

48445 TX Terry

48451 TX Tom Green

48461 TX Upton

48475 TX Ward

48495 TX Winkler

48501 TX Yoakum

49007 UT Carbon 

49009 UT Daggett 

49013 UT Duchesne 

49015 UT Emery 

49019 UT Grand 

49043 UT Summit 

49047 UT Uintah 

56001 WY Albany 

56005 WY Campbell 

56007 WY Carbon 

56009 WY Converse 

56011 WY Crook 

56013 WY Fremont 

56019 WY Johnson 

56023 WY Lincoln 

56025 WY Natrona 

56027 WY Niobrara 

56033 WY Sheridan 

56035 WY Sublette 
49

FIPS State County

56037 WY Sweetwater 

FIPS State County

56041 WY Uinta 

FIPS State County

56045 WY Weston 

Although the intention was to apply WRAP speciation everywhere in the WRAP region (Table 3-9), a 

SMOKE processing error meant that for select sources in select counties the national VOC profiles for oil 

and gas were used16. For the biog sector, the speciation profiles used by BEIS are not included in 

SPECIATE. The 2011 platform uses BEIS3.61, which includes a new species (SESQ) that was mapped 

to the model species SESQT. The profile code associated with BEIS3.61 for use with CB05 is “B10C5”, 

while the profile for use with CB6 is “B10C6”. The main difference between the profiles is the explicit 

treatment of acetone emissions in B10C6.

For the nonpt sector, where VOC emissions were greater than or equal to BAFM and BAFM was not 

zero, the sources were integrated. For portable fuel containers (PFCs) and fuel distribution operations 

associated with the bulk-plant-to-pump (BTP) distribution, ethanol may be mixed into the fuels; therefore, 

county- and month-specific COMBO speciation was used (via the GSPRO_COMBO file). Refinery to 

bulk terminal (RBT) fuel distribution and bulk plant storage (BPS) speciation are considered upstream 

from the introduction of ethanol into the fuel; therefore a single profile is sufficient for these sources. No

refined information on potential VOC speciation differences between cellulosic diesel and cellulosic 

ethanol sources was available, therefore cellulosic diesel and cellulosic ethanol sources used the same 

SCC (30125010: Industrial Chemical Manufacturing, Ethanol by Fermentation production) for VOC 

speciation as was used for corn ethanol plants. For the future year, PFC and the cellulosic sources were 

integrated EBAFM (i.e. used E-profiles) because ethanol was present in those inventories.

3.2.1.4 Future year speciation

The VOC speciation approach used for the future year case is customized to account for the impact of fuel 

changes. These changes affect the onroad, nonroad, and parts of the nonpt and ptnonipm sectors. 

Speciation profiles for VOC in the nonroad sector account for the changes in ethanol content of fuels 

across years. A description of the actual fuel formulations for 2011 can be found in the 2011NEIv2 TSD,

and for 2017 and 2025 see Section 4.3. For 2011, EPA used “COMBO” profiles to model combinations

of profiles for E0 and E10 fuel use. For 2017 and 2025, EPA assumed E10 fuel use for all nonroad 

gasoline processes. 

The speciation changes from fuels in the nonpt sector are for PFCs and fuel distribution operations 

associated with the BTP distribution. For these sources, ethanol may be mixed into the fuels, in which 

case speciation would change across years. The speciation changes from fuels in the ptnonipm sector 

include BTP distribution operations inventoried as point sources. RBT fuel distribution and BPS 

speciation does not change across the modeling cases because this is considered upstream from the 

introduction of ethanol into the fuel. For PFCs, ethanol was present in the future inventories and therefore 

 

16 The sources were accidentally not included in the list of no-integrated sources/counties. At the time of the 

modeling, EPA only had no-integrate WRAP profiles (VOC); therefore the incorrectly assigned integrated sources 

(NONHAPVOC) defaulted to the national integrated profiles for oil and gas. This impacted np_oilgas but not 

pt_oilgas.
50

EBAFM profiles were used to integrate ethanol in the future year speciation. The mapping of fuel 

distribution SCCs to PFC, BTP, BPS, and RBT emissions categories can be found in Appendix B.

Table 3-10 summarizes the different profiles utilized for the fuel-related sources in each of the sectors for 

2011 and the future year cases. This table indicates when “E-profiles” were used instead of BAFM 

integrated profiles. The term “COMBO” indicates that a combination of the profiles listed was used to 

speciate that subcategory using the GSPRO_COMBO file. Although some of the component profiles are 

the same between 2017 and 2025, for example “nonpt, BTP”, the proportion of each profile within the 

GSPRO_COMBO differs between the two future years.

Table 3-10. Select VOC profiles 2011 vs 2017 vs 2025

sector

Subcategory 2011 2017 2025

nonroad gasoline 

exhaust

COMBO 8751a

Pre-Tier 2 E10 

exhaust 8751a

Pre-Tier 2 E10 

exhaust

8750a

Pre-Tier 2 E0 

exhaust

8751a

Pre-Tier 2 

E10 exhaust

nonroad

gasoline 

evaporative

COMBO 8754 E10 evap 8754 E10 evap

8753 E0 evap

8754 E10 evap

nonroad gasoline 

refueling

COMBO 8870 E10 Headspace 8870 E10 Headspace

8869

E0 

Headspace

8870

E10 

Headspace

nonroad

diesel 

exhaust 8774

Pre-2007 MY 

HDD exhaust 8774

Pre-2007 MY 

HDD exhaust 8774

Pre-2007 MY HDD 

exhaust

nonroad

diesel 

evaporative 4547Diesel 

Headspace 4547

Diesel 

Headspace 4547 Diesel Headspace

nonroad

diesel 

refueling 4547

Diesel 

Headspace 4547

Diesel 

Headspace 4547 Diesel Headspace

nonpt/

ptnonipm PFC

COMBO

8869

E0 

Headspace 8870E E10 Headspace 8870E E10 Headspace

8870

E10 

Headspace

nonpt/

ptnonipm BTP

COMBO COMBO COMBO

8869

E0 

Headspace 8870 E10 Headspace 8870 E10 Headspace

8870

E10 

Headspace 8871 E15 Headspace 8871 E15 Headspace

8934 E85 Evap 8934 E85 Evap
51

sector

Subcategory 2011 2017 2025

nonpt/

ptnonipm BPS/RBT 8869

E0 

Headspace 8869 E0 Headspace 8869 E0 Headspace

The speciation of onroad VOC occurs within MOVES. MOVES takes into account fuel type and 

properties, emission standards as they affect different vehicle types and model years, and specific 

emission processes. A description of the actual fuel formulations for 2011 can be found in the 2011NEIv2 

TSD; for 2017 and 2025 see Section 4.3. Table 3-11 describes all of the M-profiles available to MOVES 

depending on the model year range, MOVES process (processID), fuel sub-type (fuelSubTypeID), and 

regulatory class (regClassID). Table 3-12 to Table 3-14 describe the meaning of these MOVES codes. 

For a specific representative county and future year, there will be a different mix of these profiles. For 

example, for HD diesel exhaust, the emissions will use a combination of profiles 8774M and 8775M 

depending on the proportion of HD vehicles that are pre-2007 model years (MY) in that particular county. 

As that county is projected farther into the future, the proportion of pre-2007 MY vehicles will decrease. 

A second example, for gasoline exhaust (not including E-85), the emissions will use a combination of 

profiles 8756M, 8757M, 8758M, 8750aM, and 8751aM. Each representative county has a different mix 

of these key properties and therefore has a unique combination of the specific M-profiles.

Table 3-11. Onroad M-profiles

Profile Profile Description Model Year 

range

processID fuelSubTypeID regClassID

1001M CNG Exhaust 1940-2050 1,2,15,16 30 48

4547M Diesel Headspace 1940-2050 11 20,21,22 0

4547M Diesel Headspace 1940-2050 12,13,18,19 20,21,22 10,20,30,40,41, 

42,46,47,48

8753M E0 Evap 1940-2050 12,13,19 10 10,20,30,40,41,42, 

46,47,48

8754M E10 Evap 1940-2050 12,13,19 12,13,14 10,20,30,40,41, 

42,46,47,48

8756M Tier 2 E0 Exhaust 2001-2050 1,2,15,16 10 20,30

8757M Tier 2 E10 Exhaust 2001-2050 1,2,15,16 12,13,14 20,30

8758M Tier 2 E15 Exhaust 1940-2050 1,2,15,16 15,18 10,20,30,40,41, 

42,46,47,48

8766M E0 evap permeation 1940-2050 11 10 0

8769M E10 evap permeation 1940-2050 11 12,13,14 0

8770M E15 evap permeation 1940-2050 11 15,18 0

8774M Pre-2007 MY HDD 

exhaust 1940-2006 1,2,15,16,17,90

20,21,22 40,41,42,46,47,48

8774M Pre-2007 MY HDD 

exhaust 1940-2050 91 20,21,22 46,47

8774M Pre-2007 MY HDD 

exhaust 1940-2006 1,2,15,16 20,21,22 20,30

8775M 2007+ MY HDD exhaust 2007-2050 1,2,15,16 20,21,22 20,30

8775M 2007+ MY HDD exhaust 2007-2050 1,2,15,16,17,9

0

20,21,22 40,41,42,46,47,48

8855M Tier 2 E85 Exhaust 1940-2050 1,2,15,16 50,51,52 10,20,30,40,41, 

42,46,47,48
52

Profile Profile Description Model Year 

range

processID fuelSubTypeID regClassID

8869M E0 Headspace 1940-2050 18 10 10,20,30,40,41, 

42,46,47,48

8870M E10 Headspace 1940-2050 18 12,13,14 10,20,30,40,41, 

42,46,47,48

8871M E15 Headspace 1940-2050 18 15,18 10,20,30,40,41, 

42,46,47,48

8872M E15 Evap 1940-2050 12,13,19 15,18 10,20,30,40,41, 

42,46,47,48

8934M E85 Evap 1940-2050 11 50,51,52 0

8934M E85 Evap 1940-2050 12,13,18,19 50,51,52 10,20,30,40,41, 

42,46,47,48

8750aM Pre-Tier 2 E0 exhaust 1940-2000 1,2,15,16 10 20,30

8750aM Pre-Tier 2 E0 exhaust 1940-2050 1,2,15,16 10 10,40,41,42,46,47,48

8751aM Pre-Tier 2 E10 exhaust 1940-2000 1,2,15,16 11,12,13,14 20,30

8751aM Pre-Tier 2 E10 exhaust 1940-2050 1,2,15,16 11,12,13,14,15,1

8

10,40,41,42,46,47,48

Table 3-12. MOVES Process IDs

Process ID Process Name

1 Running Exhaust

2 Start Exhaust

11 Evap Permeation

12 Evap Fuel Vapor Venting

13 Evap Fuel Leaks

15 Crankcase Running Exhaust

16 Crankcase Start Exhaust

17 Crankcase Extended Idle Exhaust

18 Refueling Displacement Vapor Loss

19 Refueling Spillage Loss

20 Evap Tank Permeation

21 Evap Hose Permeation

22 Evap RecMar Neck Hose Permeation

23 Evap RecMar Supply/Ret Hose Permeation

24 Evap RecMar Vent Hose Permeation

30 Diurnal Fuel Vapor Venting

31 HotSoak Fuel Vapor Venting

32 RunningLoss Fuel Vapor Venting

40 Nonroad

90 Extended Idle Exhaust

91 Auxiliary Power Exhaust
53

Table 3-13. MOVES Fuel subtype IDs

Fuel Subtype ID Fuel Subtype Descriptions

10 Conventional Gasoline

11 Reformulated Gasoline (RFG)

12 Gasohol (E10)

13 Gasohol (E8)

14 Gasohol (E5)

15 Gasohol (E15)

18 Ethanol (E20)

20 Conventional Diesel Fuel

21 Biodiesel (BD20)

22 Fischer-Tropsch Diesel (FTD100)

30 Compressed Natural Gas (CNG)

50 Ethanol

51 Ethanol (E85)

52 Ethanol (E70)

Table 3-14. MOVES Regclass IDs

Reg. Class ID Regulatory Class Description

0 Doesn’t Matter

10 Motorcycles

20 Light Duty Vehicles

30 Light Duty Trucks

40 Class 2b Trucks with 2 Axles and 4 Tires (8,500 lbs < GVWR <= 10,000 lbs)

41

Class 2b Trucks with 2 Axles and at least 6 Tires or Class 3 Trucks (8,500 lbs < GVWR <= 14,000 

lbs)

42 Class 4 and 5 Trucks (14,000 lbs < GVWR <= 19,500 lbs)

46 Class 6 and 7 Trucks (19,500 lbs < GVWR <= 33,000 lbs)

47 Class 8a and 8b Trucks (GVWR > 33,000 lbs)

48 Urban Bus (see CFR Sec 86.091_2)

3.2.2 PM speciation

In addition to VOC profiles, the SPECIATE database also contains the PM2.5 speciated into both 

individual chemical compounds (e.g., zinc, potassium, manganese, lead), and into the “simplified” PM2.5

components used in the air quality model. We speciated PM2.5 into the AE6 species associated with 

CMAQ 5.0.1 and later versions. While provided in the platform, they are not used in CAMX but rather 

converted to the PM2.5 species based on the cmaq2camx file presented in Table 3-4. 

Table 3-15 shows the mapping of AE5 and AE6 for historical reference. The majority of the 2011 

platform PM profiles come from the 911XX series which include updated AE6 speciation17. The 

2011eh_cb6v2, 2017eh_cb6v2, and 2025eh_cb6v2 state-sector totals workbooks include state totals of the 

PM emissions for each state for the sectors that include PM.

 

17 The exceptions are 5674 (Marine Vessel – Marine Engine – Heavy Fuel Oil) used for c3marine and 92018 (Draft Cigarette 

Smoke – Simplified) used in nonpt.
54

Table 3-15. PM model species: AE5 versus AE6

Species name Species description AE5 AE6

POC organic carbon Y Y

PEC elemental carbon Y Y

PSO4 Sulfate Y Y

PNO3 Nitrate Y Y

PMFINE unspeciated PM2.5 Y N

PNH4 Ammonium N Y

PNCOM non-carbon organic matter N Y

PFE Iron N Y

PAL Aluminum N Y

PSI Silica N Y

PTI Titanium N Y

PCA Calcium N Y

PMG Magnesium N Y

PK potassium N Y

PMN Manganese N Y

PNA Sodium N Y

PCL Chloride N Y

PH2O Water N Y

PMOTHR PM2.5 not in other AE6 species N Y

For the onroad sector, for all processes except brake and tire wear, PM speciation occurs within MOVES 

itself, not within SMOKE (similar to the VOC speciation described above). The advantage of using 

MOVES to speciate PM is that during the internal calculation of MOVES, the model has complete 

information on the characteristics of the fleet and fuels (e.g. model year, sulfur content, process, etc.) to 

accurately match to specific profiles. This means that MOVES produces EF tables that include total PM 

(e.g. PM10 and PM2.5) and speciated PM (e.g. PEC, PFE, etc). SMOKE essentially calculates the PM 

components by using the appropriate EF without further speciation18. For onroad brake and tire wear, the 

PM is speciated in the moves2smk postprocessor that prepares the emission factors for processing in 

SMOKE. The formulas for this are based on the standard speciation factors that would otherwise be used 

in SMOKE via the profiles 91134 for brake wear and 91150 for tire wear:

POC = 0.4715 * PM25TIRE + 0.107 * PM25BRAKE

PEC = 0.22 * PM25TIRE + 0.0261 * PM25BRAKE

PNO3 = 0.0015 * PM25TIRE + 0.0016 * PM25BRAKE

PSO4 = 0.0311 * PM25TIRE + 0.0334 * PM25BRAKE

PNH4 = 0.00019 * PM25TIRE + 0.00003 * PM25BRAKE

PNCOM = 0.1886 * PM25TIRE + 0.0428 * PM25BRAKE

For California onroad emissions, adjustment factors were applied to SMOKE-MOVES to produce 

California adjusted model-ready files (see Section 2.3.1 for details). California did not supply speciated 

 

18 Unlike previous platforms, the PM components (e.g. POC) are now consistently defined between MOVES2014 and CMAQ. 

For more details on the use of model-ready EF, see the SMOKE 3.6.5 documentation: 

https://www.cmascenter.org/smoke/documentation/3.6.5/html/
55

PM, therefore the adjustment factors applied to PM2.5 were also applied to the speciated PM components. 

By applying the ratios through SMOKE-MOVES, the CARB inventories are essentially speciated to 

match EPA estimated speciation.

3.2.3 NOX speciation

NOX can be speciated into NO, NO2, and/or HONO. For the non-mobile sources, EPA used a single 

profile “NHONO” to split NOX into NO and NO2. For the mobile sources except for onroad (including 

nonroad, c1c2rail, c3marine, othon sectors) and for specific SCCs in othar and ptnonipm, the profile 

“HONO” splits NOX into NO, NO2, and HONO. Table 3-16 gives the split factor for these two profiles.

The onroad sector does not use the “HONO” profile to speciate NOX. MOVES2014 produces speciated 

NO, NO2, and HONO by source, including emission factors for these species in the emission factor tables 

used by SMOKE-MOVES. Within MOVES, the HONO fraction is a constant 0.008 of NOX. The NO 

fraction varies by heavy duty versus light duty, fuel type, and model year. The NO2 fraction = 1 – NO –

HONO. For more details on the NOX fractions within MOVES, see 

http://www.epa.gov/otaq/models/moves/documents/420r12022.pdf. 

Table 3-16. NOX speciation profiles

Profile pollutant species split factor

HONO NOX NO2 0.092

HONO NOX NO 0.9

HONO NOX HONO 0.008

NHONO NOX NO2 0.1

NHONO NOX NO 0.9

3.3 Temporal Allocation

Temporal allocation (i.e., temporalization) is the process of distributing aggregated emissions to a finer 

temporal resolution, thereby converting annual emissions to hourly emissions. While the total emissions 

are important, the timing of the occurrence of emissions is also essential for accurately simulating ozone, 

PM, and other pollutant concentrations in the atmosphere. Many emissions inventories are annual or 

monthly in nature. Temporalization takes these aggregated emissions and if needed distributes them to the 

month, and then distributes the monthly emissions to the day and the daily emissions to the hours of each 

day. This process is typically done by applying temporal profiles to the inventories in this order: monthly, 

day of the week, and diurnal. A summary of emissions by temporal profile and sector for the 2011eh case 

is available from ftp://ftp.epa.gov/EmisInventory/2011v6/v2platform/reports/ 

2011eh_emissions_by_temporal_profile.xlsx. 

In SMOKE 3.6.5 and in the 2011v6.2 platform, more readable and flexible files formats are used for 

temporal profiles and cross references. The profiles and cross references were initially created by 

converting the 2011v6.1 platform temporal profiles into the new formats, and then any specific 

adjustments for the 2011v6.2 platform were made. The temporal factors applied to the inventory are 

selected using some combination of country, state, county, SCC, and pollutant. Table 3-17 summarizes 

the temporal aspects of emissions modeling by comparing the key approaches used for temporal 

processing across the sectors. In the table, “Daily temporal approach” refers to the temporal approach for 

getting daily emissions from the inventory using the SMOKE Temporal program. The values given are 

the values of the SMOKE L_TYPE setting. The “Merge processing approach” refers to the days used to 

represent other days in the month for the merge step. If this is not “all”, then the SMOKE merge step runs

only for representative days, which could include holidays as indicated by the right-most column. The 

values given are those used for the SMOKE M_TYPE setting (see below for more information). 
56

Table 3-17. Temporal settings used for the platform sectors in SMOKE

Platform sector 

short name

Inventory 

resolutions

Monthly 

profiles 

used?

Daily 

temporal 

approach

Merge 

processing 

approach

Process Holidays 

as separate days

afdust_adj Annual Yes week all Yes

Ag Annual Yes all all Yes

agfire Monthly week week Yes

beis Hourly n/a all Yes

c1c2rail Annual Yes mwdss mwdss

c3marine Annual Yes aveday aveday

nonpt Annual Yes week week Yes

nonroad Monthly mwdss mwdss Yes

np_oilgas Annual yes mwdss mwdss Yes

onroad Annual & monthly1all all Yes

onroad_ca_adj Annual & monthly1all all Yes

othar Annual yes week week

othon Annual yes week week

othpt Annual yes mwdss mwdss

pt_oilgas Annual yes mwdss mwdss Yes

ptegu Daily & hourly all all Yes

ptnonipm Annual yes mwdss mwdss Yes

ptprescfire Daily all all Yes

ptwildfire Daily all all Yes

rwc Annual no met-based all Yes

1. Note the annual and monthly “inventory” actually refers to the activity data (VMT and VPOP) for onroad. The 

actual emissions are computed on an hourly basis.

The following values are used in the table: The value “all” means that hourly emissions are computed for 

every day of the year and that emissions potentially have day-of-year variation. The value “week” means 

that hourly emissions computed for all days in one “representative” week, representing all weeks for each 

month. This means emissions have day-of-week variation, but not week-to-week variation within the 

month. The value “mwdss” means hourly emissions for one representative Monday, representative 

weekday (Tuesday through Friday), representative Saturday, and representative Sunday for each month. 

This means emissions have variation between Mondays, other weekdays, Saturdays and Sundays within 

the month, but not week-to-week variation within the month. The value “aveday” means hourly 

emissions computed for one representative day of each month, meaning emissions for all days within a

month are the same. Special situations with respect to temporalization are described in the following 

subsections. 

In addition to the resolution, temporal processing includes a ramp-up period for several days prior to 

January 1, 2011, which is intended to mitigate the effects of initial condition concentrations. The ramp-up 

period was 10 days (December 22-31, 2010). For most sectors, emissions from December 2011 were 

used to fill in surrogate emissions for the end of December 2010. In particular, December 2011 emissions 

(representative days) were used for December 2010. For biogenic emissions, December 2010 emissions 

were processed using 2010 meteorology.
57

3.3.1 Use of FF10 format for finer than annual emissions

The Flat File 2010 format (FF10) inventory format for SMOKE provides a more consolidated format for 

monthly, daily, and hourly emissions inventories than prior formats supported. Previously, processing

monthly inventory data required the use of 12 separate inventory files. With the FF10 format, a single 

inventory file can contain emissions for all 12 months and the annual emissions in a single record. This 

helps simplify the management of numerous inventories. Similarly, daily and hourly FF10 inventories 

contain individual records with data for all days in a month and all hours in a day, respectively. 

SMOKE prevents the application of temporal profiles on top of the “native” resolution of the inventory. 

For example, a monthly inventory should not have annual-to-month temporalization applied to it; rather, 

it should only have month-to-day and diurnal temporalization. This becomes particularly important when 

specific sectors have a mix of annual, monthly, daily, and/or hourly inventories. The flags that control 

temporalization for a mixed set of inventories are discussed in the SMOKE documentation. The 

modeling platform sectors that make use of monthly values in the FF10 files are agfire, nonroad, onroad, 

and ptegu.

3.3.2 Electric Generating Utility temporalization (ptegu)

3.3.2.1 Base year temporal allocation of EGUs

The 2011NEIv2 annual EGU emissions are allocated to hourly emissions using the following 3-step 

methodology: annual value to month, month to day, and day to hour. Several updates were made to EGU 

temporalization in the 2011v6.2 platform. First, the CEMS data were processed using a tool that 

reviewed the data quality flags that indicate the data were not measured. Unmeasured data can cause 

erroneously high values in the CEMS data. If the data were not measured at specific hours, and those 

values were found to be more the 3 times the annual mean for that unit, the data for those hours were 

replaced with annual mean values (Adelman, et al., 2012). These adjusted CEMS data were then used for 

the remainder of the temporalization process described below (see Figure 3-3 for an example). Another 

update in the 2011v6.2 platform was the incorporation of winter and summer seasons into the 

development of the diurnal profiles as opposed to using data for the entire year. Analysis of the hourly 

CEMS data revealed that there were different diurnal patterns in winter versus summer in many areas. 

Typically a single mid-day peak is visible in the summer, while there are morning and evening peaks in 

the winter as shown in Figure 3-4. 

The temporal allocation procedure is differentiated by whether or not the source could be directly 

matched to a CEMS unit via ORIS facility code and boiler ID. Prior to temporal allocation, as many 

sources as possible were matched to CEMS data via ORIS facility code and boiler ID. Units were 

considered matches if the FIPS state/county code matched, the facility name was similar, and the NOx 

and SO2 emissions were similar. EIS stores a base set of previously matched units via alternate facility 

and unit IDs. Additions to these matches were made for the 2011v6.2 platform. For any units that are 

matched, the ORIS facility and boiler ID columns of the point FF10 inventory files are filled with the 

information on the rows for the corresponding NEI unit. Note that for units matched to CEMS data, 

annual totals of their emissions may be different than the annual values in 2011NEIv2 because the CEMS

data actually replaces the inventory data for the seasons in which the CEMS are operating. If a CEMSmatched unit is determined to be a partial year reporter, as can happen for sources that run CEMS only in 

the summer, emissions totaling the difference between the annual emissions and the total CEMS 

emissions are allocated to the non-summer months.
58

Figure 3-3. Eliminating unmeasured spikes in CEMS data

Figure 3-4. Seasonal diurnal profiles for EGU emissions in a Virginia Region

For sources not matched to CEMS units, the allocation of annual emissions to months and then days are 

done outside of SMOKE and then daily emissions are output to day-specific inventory files. For these 

units, the allocation of the inventory annual emissions to months is done using average fuel-specific 

season-to-month factors generated for each of the 64 IPM regions shown in Figure 3-5. These factors are 
59

based 2011 CEMS data only. In each region, separate factors were developed for the fuels: coal, natural 

gas, and “other”, where the types of fuels included in “other” vary by region. Separate profiles were 

computed for NOx, SO2, and heat input. An overall composite profile was also computed and was used 

when there were no CEMS units with the specified fuel in the region containing the unit. For both CEMSmatched units and units not matched to CEMS, NOx and SO2 CEMS data are used to allocate NOx and 

SO2 emissions to daily emissions, respectively, while heat input data are used to allocate emissions of all 

other pollutants. 

Figure 3-5. IPM Regions for EPA Base Case v5.14

Daily temporal allocation of units matched to CEMS was performed using a procedure similar to the 

approach to allocate emissions to months in that the CEMS data replaces the inventory data for each 

pollutant. For units without CEMS data, emissions were allocated from month to day using IPM-region 

and fuel-specific average month-to-day factors based on the 2011 CEMS data. Separate month-to-day 

allocation factors were computed for each month of the year using heat input for the fuels coal, natural 

gas, and “other” in each region. For both CEMS and non-CEMS matched units, NOx and SO2 CEMS data 

are used to allocate NOx and SO2 emissions, while CEMS heat input data are used to allocate all other 

pollutants. An example of month-to-day profiles for gas, coal, and an overall composite for a region in 

western Texas is shown in Figure 3-6.
60

Figure 3-6. Month-to-day profiles for different fuels in a West Texas Region

For units matched to CEMS data, hourly emissions use the hourly CEMS values for NOx and SO2, while 

other pollutants are allocated according to heat input values. For units not matched to CEMS data, 

temporal profiles from days to hours are computed based on the season-, region- and fuel-specific average 

day-to-hour factors derived from the CEMS data for those fuels and regions using the appropriate subset 

of data. For the unmatched units, CEMS heat input data are used to allocate all pollutants (including NOx

and SO2) because the heat input data was generally found to be more complete than the pollutant-specific 

data. SMOKE then allocates the daily emissions data to hours using the temporal profiles obtained from 

the CEMS data for the analysis base year (i.e., 2011 in this case).

3.3.2.2 Future year temporal allocation of EGUs

IPM provides unit-level emission projections of average winter (representing October through April) and 

average summer (representing May through September) values. To use these data in an air quality model, 

the unit-level data must first be converted to into hourly values through the temporal allocation process. 

These annualized emissions are allocated to hourly emissions using a 3-step methodology: annualized 

summer/winter value to month, month to day, and day to hour. The first two steps are done outside of 

SMOKE and the third step is done by SMOKE using daily emissions files created from the first two steps. 

The approach in the 2011v6.2 platform maximizes the use of the CEMS data from the air quality analysis 

year (e.g., 2011).

The goal of the temporal allocation process is to reflect the variability in the unit-level emissions that can 

impact air quality over seasonal, daily, or hourly time scales, in a manner compatible with incorporating 

future-year emission projections into future-year air quality modeling. The temporal allocation process is 

applied to the seasonal emission projections obtained from an IPM modeling scenario. IPM represents 

two seasons: summer (May through September) and winter (October through April). IPM unit-level 

parsed files contain seasonal and annual totals of SO2, NOX, CO2, Hg, and HCl emissions (computed 

directly within IPM), while PM2.5, PM10, VOC, NH3, and CO emissions are calculated using a post-
61

processing tool19 based on each unit’s projected fuel use and configuration, coupled with pollutantspecific emission factors.20 When calculating PM emissions, the post-processing tool utilizes specific data 

assumptions such as the ash and sulfur content of the coal projected to be used at the unit. The tool creates 

a Flat File (in a comma-separated value or .csv file format) that provides the starting point for developing 

emission inputs to an air quality model.

The resulting Flat File contains all of the endogenously-determined and post-calculated unit-level 

emissions combined with stack parameters (i.e., stack location and other characteristics consistent with 

information found in the National Emissions Inventory (NEI)). A cross reference is used to map the units 

in NEEDS to the stack parameter and facility, unit, release point, and process identifiers used in the 

National Emissions Inventory (NEI). The cross reference also maps sources to the hourly Continuous 

Emissions Monitoring System (CEMS) data used to temporally allocate the emissions in the base year air 

quality modeling. This cross reference has been updated for the v5.14 platform through collaboration with 

EPA, regional planning organizations, and states and is also used to determine which emissions sources in 

the NEI sources have future year emissions predicted by IPM, and is available at 

ftp://ftp.epa.gov/EmisInventory/2011v6/v2platform/reports/ipm_to_flat_file_xref_2011NEIv2_IPM5.14_

20150113.xlsx. 

Emissions from point sources for which emissions are not predicted by IPM are carried forward into the 

future year modeling platform using other projection methods. Therefore, if the NEI and IPM sources are 

not properly matched, double-counting could result because the future year emissions output from IPM in 

the future year are treated as a full replacement for the base year emissions, although only for the 

emissions processes estimated by IPM. Note: any feedback to EPA on future updates to the cross 

reference should be provided based on this updated version that will be used with later versions of IPM: 

ftp://ftp.epa.gov/EmisInventory/2011v6/v2platform/reports/ 

ipm_to_flat_file_xref_2011NEIv2_Updated_20150710.xlsx. 

In order to support the temporal allocation process and other requirements of modeling point sources, the 

Flat File output from the IPM postprocessor specifies annual and monthly emissions for each stack; 

however, since IPM projections are only modeled for two seasons comprising multiple months each, 

monthly emissions cannot be precisely specified in the Flat File. Instead, the monthly values in the Flat 

File output from the postprocessor are computed by multiplying the average summer day and average 

winter day emissions predicted by IPM by the number of days in the respective month. In summary, the 

monthly emission values shown in the Flat File are not intended to represent an actual month-to-month 

emission pattern; instead, they are interim values that have translated IPM’s seasonal projections into 

month-level data that serve as a starting point for the temporal allocation process. 

The monthly emissions within the Flat File undergo a multi-step temporal allocation process to yield the 

hourly emission values at each unit, as is needed for air quality modeling: summer/winter value to month, 

month to day, and day to hour. For sources not matched to unit-specific CEMS data, the first two steps are 

done outside of SMOKE and the third step to get to hourly values is done by SMOKE using daily the 

emissions files created from the first two steps. For each of these three temporal allocation steps, NOx

and SO2 CEMS data are used to allocate NOx and SO2 emissions, while CEMS heat input data are used to 

allocate all other pollutants. The approach defined here gives priority to temporalization based on the base 

year CEMS data to the maximum extent possible. 

 

19 Documentation of this tool can be found at www.epa.gov/powersectormodeling

20 For more information on EPA emission factors see http://www.epa.gov/ttnchie1/ap42/
62

Prior to using the 2011 CEMS data to develop monthly, daily, and hourly profiles, the CEMS data were 

processed through a tool that found data quality flags that indicated the data were measured (see Section 

3.3.2.1). These adjusted CEMS data were used to compute the monthly, daily, and hourly profiles 

described below.

For units in NEEDS that are matched to units in the National Emission Inventory (NEI), and for which 

CEMS data are available, the emissions are temporalized based on the CEMS data for that unit and 

pollutant. For units that are not matched to the NEI or for which CEMS data are not available, the 

allocation of the IPM seasonal emissions to months is done using average fuel-specific season-to-month 

factors generated for each of the 64 IPM regions shown in Figure 3-5. These factors are based on a single 

year of CEMS data for the modeling base year associated with the air quality modeling analysis being 

performed, such as 2011. Note that IPM uses load data (reflecting the shape of demand) corresponding to 

the load in each IPM region that occurred in the base year of the air quality modeling analysis, such as 

2011. The fuels used for creating the profiles for a region are coal, natural gas, and other, where the other 

fuels used include oil and wood and vary by region. Separate profiles are computed for NOx, SO2, and 

heat input. An overall composite profile across all fuels is also computed and can be used in the event that 

a region has too few units of a fuel type to make a reasonable average profile, or in the case when a unit 

changes fuels between the base and future year and there were previously no units with that fuel in the 

region containing the unit. 

The monthly emission values in the Flat File are first reallocated across the months in that season to align 

the month-to-month emission pattern at each stack with historic seasonal emission patterns.21 While this 

reallocation affects the monthly pattern of each unit’s future-year seasonal emissions, the seasonal totals 

are held equal to the IPM projection for that unit and season. Second, the reallocated monthly emission 

values at each stack are disaggregated down to the daily level consistent with historic daily emission 

patterns in the given month at the given stack using separate profiles for NOx, SO2, and heat input. This 

process helps to capture the influence of meteorological episodes that cause electricity demand to vary 

from day-to-day, as well as weekday-weekend effects that change demand during the course of a given 

week. Third, this data set of emission values for each day of the year at each unit is input into SMOKE, 

which uses temporal profiles to disaggregate the daily values into specific values for each hour of the 

year. 

For units without or not matched to CEMS data, or for which the CEMS data are found to be unsuitable 

for use in the future year, emissions are allocated from month to day using IPM-region and fuel-specific 

average month-to-day factors based on CEMS data from the base year of the air quality modeling 

analysis. These instances include units that did not operate in the base year or for which it may not have 

been possible to match the unit in NEEDS with a specific unit in the NEI. EPA uses average emission 

profiles for some units with CEMS data in the base year when one of the following cases is true: (1) units 

are projected to have substantially increased emissions in the future year compared to its emissions in the 

base (historic) year22; (2) CEMS data are only available for a limited number of hours in that base year; 

(3) units change fuels in the future year; (4) the unit is new in the future year; or (5) units experienced 

atypical conditions during the base year, such as lengthy downtimes for maintenance or installation of 

 

21 For example, the total emissions for a unit in May would not typically be the same as the total emissions for the same unit in 

July, even though May and July are both in the summer season and the number of days in those months is the same. This is 

because the weather changes over the course of each season, and thus the operating behavior of a specific unit can also vary 

throughout each season. Therefore, part of the temporal allocation process is intended to create month-specific emissions totals 

that reflect this intra-seasonal variation in unit operation and associated emissions.

22 In such instances, EPA does not use that unit’s CEMS data for temporal allocation in order to avoid assigning large increases 

in emissions over short time periods in the unit’s hourly emission profile.
63

controls. The temporal profiles that map emissions from days to hours are computed based on the region 

and fuel-specific seasonal (i.e., winter and summer) average day-to-hour factors derived from the CEMS 

data for those fuels and regions using only heat input data for that season. Only heat input is used because 

it is the variable that is the most complete in the CEMS data. SMOKE uses these profiles to allocate the 

daily emissions data to hours. 

The emissions from units for which unit-specific profiles are not deemed appropriate, and for units in the 

IPM outputs that are not specifically matched to units in the base year, are temporally allocated to hours 

reflecting patterns typical of the region in which the unit is located. Analysis of CEMS data for units in 

each of the 64 IPM regions revealed that there were differences in the temporal patterns of historic 

emission data that correlate with fuel type (e.g., coal, gas, and other), time of year, pollutant, season (i.e. 

winter versus summer) and region of the country. The correlation of the temporal pattern with fuel type is 

explained by the relationship of units’ operating practices with the fuel burned. For example, coal units 

take longer to ramp up and ramp down than natural gas units, and some oil units are used only when 

electricity demand cannot otherwise be met. Geographically, the patterns were less dependent on state 

location than they were on IPM regional location. For temporal allocation of emissions at these units, 

Figure 3-6 provides an example of daily coal, gas, and composite profiles in one IPM region. EPA 

developed seasonal average emission profiles, each derived from base year CEMS data for each season 

across all units sharing both IPM region and fuel type.23 Figure 3-4 provides an example of seasonal 

profiles that allocate daily emissions to hours in one IPM region. These average day-to-hour temporal 

profiles were also used for sources during seasons of the year for which there were no CEMS data 

available, but for which IPM predicted emissions in that season. This situation can occur for multiple 

reasons, including how the CEMS was run at each source in the base year.

For units that do have CEMS data in the base year and are matched to units in the IPM output, the base 

year CEMS data are scaled so that their seasonal emissions match the IPM-projected totals. In particular, 

the fraction of the unit’s seasonal emissions in the base year is computed for each hour of the season, and 

then applied to the seasonal emissions in the future year. This is accomplished outside of SMOKE by 

creating data in the same format as CEMS data for NOx, SO2, and heat input. Any pollutants other than 

NOX and SO2 are temporalized within SMOKE using heat input as a surrogate. Distinct factors are used 

for the fuels coal, natural gas, and “other”. This procedure yields future-year hourly data that have the 

same temporal pattern as the base year CEMS data while matching future-year seasonal total emissions 

for each stack to IPM’s future-year projections (see example in Figure 3-7).

In cases when the emissions for a particular unit are projected to be substantially higher in the future year 

than in the base year, the proportional scaling method to match the emission patterns in the base year 

described above can yield emissions for a unit that are much higher than the historic maximum emissions 

for that unit. To address this issue for the 2017 case, the maximum measured emissions of NOx and SO2

in the period of 2011-2014 were computed. The temporalized emissions were then evaluated at each hour 

to determine whether they were above this cumulative maximum. The amount of “excess emissions” over 

the maximum was then computed. For units for which the “excess emissions” could be reallocated to 

other hours, those emissions were distributed evenly to hours that were below the maximum. Those 

hourly emissions were then reevaluated against the maximum, and the procedure of reallocating the 

excess emissions to other hours was repeated until all of the hours had emissions below the maximum, 

whenever possible (see example in Figure 3-8). Note: this reallocation technique is new in the 2011v6.2 

 

23 EPA also uses an overall composite profile across all fuels for each IPM region in instances where a unit is projected to burn 

a fuel for which EPA cannot construct an average emission profile (because there were no other units in that IPM region whose 

historic CEMS data represent emissions from burning that fuel).
64

platform and was only used in the 2017eh case, not in the 2025eh case, as it was developed after modeling 

for the 2025eh case was completed. 

Figure 3-7. Future year emissions follow pattern of base year emissions

Figure 3-8. Excess emissions apportioned to hours less than maximum
65

Using the above approach, it was not always possible to reallocate excess emissions to hours below the 

historic maximum, such as when the total seasonal emissions of NOx or SO2 for a unit divided by the 

number of hours of operation are greater than the 2011-2014 maximum emissions level. For these units, 

the regional fuel-specific average profile was applied to all pollutants, including heat input, for that 

season (see example in Figure 3-9). An exception to this is if the fuel for that unit is not gas or coal. In 

that case, the composite (non-fuel-specific) profile was used for that unit. This is because many sources 

that used “other” fuel profiles had very irregular shapes due to a small number of sources in the region, 

and the allocated emissions frequently still exceeded the 2011-2014 maximum. Note that it was not 

possible for SMOKE to use regional profiles for some pollutants and adjusted CEMS data for other 

pollutants for the same unit / season, therefore all pollutants are assigned to regional profiles when 

regional profiles are needed. Also note that for some units, some hours still exceed the 2011-2014 annual 

maximum for the unit even after regional profiles were applied (see example in Figure 3-10). 

For more information on the development of IPM emission estimates and the temporalization of those, 

see http://www.epa.gov/powersectormodeling/psmodel514.html, in particular the Air Quality Modeling 

Flat File Documentation and accompanying inputs. 

Figure 3-9. Adjustment to Hours Less than Maximum not Possible, Regional Profile Applied
66

Figure 3-10. Regional Profile Applied, but Exceeds Maximum in Some Hours

3.3.3 Residential Wood Combustion Temporalization (rwc)

There are many factors that impact the timing of when emissions occur, and for some sectors this includes 

meteorology. The benefits of utilizing meteorology as method for temporalization are: (1) a

meteorological dataset consistent with that used by the AQ model is available (e.g., outputs from WRF); 

(2) the meteorological model data are highly resolved in terms of spatial resolution; and (3) the 

meteorological variables vary at hourly resolution and can therefore be translated into hour-specific 

temporalization.

The SMOKE program GenTPRO provides a method for developing meteorology-based temporalization. 

Currently, the program can utilize three types of temporal algorithms: annual-to-day temporalization for 

residential wood combustion (RWC), month-to-hour temporalization for agricultural livestock ammonia, 

and a generic meteorology-based algorithm for other situations. For the 2011 platform, meteorologicalbased temporalization was used for portions of the rwc sector and for livestock within the ag sector. 

GenTPRO reads in gridded meteorological data (output from MCIP) along with spatial surrogates, and 

uses the specified algorithm to produce a new temporal profile that can be input into SMOKE. The 

meteorological variables and the resolution of the generated temporal profile (hourly, daily, etc.) depend

on the selected algorithm and the run parameters. For more details on the development of these 

algorithms and running GenTPRO, see the GenTPRO documentation and the SMOKE documentation at 

http://www.cmascenter.org/smoke/documentation/3.1/GenTPRO_TechnicalSummary_Aug2012_Final.pd

f and http://www.cmascenter.org/smoke/documentation/3.5.1/html/ch05s03s07.html, respectively.

In the 2011v6.2 platform and in SMOKE 3.6.5, the temporal profile format has been updated. GenTPRO 

now produces separate files including the monthly temporal profiles (ATPRO_MONTHLY) and day-ofmonth temporal profiles (ATPRO_DAILY), instead of a single ATPRO_DAILY with day-of-year 

temporal profiles as it did in SMOKE 3.5. The results are the same either way, so the temporal profiles 
67

themselves are effectively the same in 2011v6.2 as they were in 2011v6.0 since the meteorology is the 

same, but they are formatted differently.

For the RWC algorithm, GenTPRO uses the daily minimum temperature to determine the temporal 

allocation of emissions to days. GenTPRO was used to create an annual-to-day temporal profile for the 

RWC sources. These generated profiles distribute annual RWC emissions to the coldest days of the year. 

On days where the minimum temperature does not drop below a user-defined threshold, RWC emissions

for most sources in the sector are zero. Conversely, the program temporally allocates the largest 

percentage of emissions to the coldest days. Similar to other temporal allocation profiles, the total annual 

emissions do not change, only the distribution of the emissions within the year is affected. The

temperature threshold for rwc emissions was 50  ̊F for most of the country, and 60  ̊F for the following 

states: Alabama, Arizona, California, Florida, Georgia, Louisiana, Mississippi, South Carolina, and 

Texas.

Figure 3-11 illustrates the impact of changing the temperature threshold for a warm climate county. The 

plot shows the temporal fraction by day for Duval County, Florida for the first four months of 2007. The 

default 50  ̊F threshold creates large spikes on a few days, while the 60  ̊F threshold dampens these spikes 

and distributes a small amount of emissions to the days that have a minimum temperature between 50 and 

60  ̊F.

Figure 3-11. Example of RWC temporalization in 2007 using a 50 versus 60  ̊F threshold

The diurnal profile for used for most RWC sources (see Figure 3-12) places more of the RWC emissions 

in the morning and the evening when people are typically using these sources. This profile is based on a 

2004 MANE-VU survey based temporal profiles (see 

http://www.marama.org/publications_folder/ResWoodCombustion/Final_report.pdf). This profile was 

created by averaging three indoor and three RWC outdoor temporal profiles from counties in Delaware 

and aggregating them into a single RWC diurnal profile. This new profile was compared to a 

concentration based analysis of aethalometer measurements in Rochester, NY (Wang et al. 2011) for 

various seasons and day of the week and found that the new RWC profile generally tracked the 

concentration based temporal patterns.
68

Figure 3-12. RWC diurnal temporal profile

The temporalization for “Outdoor Hydronic Heaters” (i.e.,“OHH”, SCC=2104008610) and “Outdoor 

wood burning device, NEC (fire-pits, chimneas, etc.)” (i.e., “recreational RWC”, SCC=21040087000) 

were updated because the meteorological-based temporalization used for the rest of the rwc sector did not 

agree with observations for how these appliances are used. 

For OHH, the annual-to-month, day-of-week and diurnal profiles were modified based on information in 

the New York State Energy Research and Development Authority (NYSERDA) “Environmental, Energy 

Market, and Health Characterization of Wood-Fired Hydronic Heater Technologies, Final Report” 

(NYSERDA, 2012) as well as a Northeast States for Coordinated Air Use Management (NESCAUM) 

report “Assessment of Outdoor Wood-fired Boilers” (NESCAUM, 2006). A Minnesota 2008 Residential 

Fuelwood Assessment Survey of individual household responses (MDNR, 2008) provided additional 

annual-to-month, day-of-week and diurnal activity information for OHH as well as recreational RWC 

usage.

The diurnal profile for OHH, shown in Figure 3-13 is based on a conventional single-stage heat load unit 

burning red oak in Syracuse, New York. As shown in

Figure 3-14, the NESCAUM report describes how for individual units, OHH are highly variable day-today but that in the aggregate, these emissions have no day-of-week variation. In contrast, the day-ofweek profile for recreational RWC follows a typical “recreational” profile with emissions peaked on 

weekends.

Annual-to-month temporalization for OHH as well as recreational RWC were computed from the MN 

DNR survey (MDNR, 2008) and are illustrated in Figure 3-15. OHH emissions still exhibit strong 

seasonal variability, but do not drop to zero because many units operate year round for water and pool 

heating. In contrast to all other RWC appliances, recreational RWC emissions are used far more 

frequently during the warm season.
69

Figure 3-13. Diurnal profile for OHH, based on heat load (BTU/hr)

Figure 3-14. Day-of-week temporal profiles for OHH and Recreational RWC

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

Heat Load (BTU/hr)

0

50

100

150

200

250

300

350

Fire Pits/Chimineas Day-of-Week Profile

Fire Pit/Chimenea

Outdoor Hydronic Heater
70

Figure 3-15. Annual-to-month temporal profiles for OHH and recreational RWC

3.3.4 Agricultural Ammonia Temporal Profiles (ag)

For the agricultural livestock NH3 algorithm, the GenTPRO algorithm is based on an equation derived by 

Jesse Bash of EPA ORD based on the Zhu, Henze, et al. (2013) empirical equation. This equation is based 

on observations from the TES satellite instrument with the GEOS-Chem model and its adjoint to estimate 

diurnal NH3 emission variations from livestock as a function of ambient temperature, aerodynamic 

resistance, and wind speed. The equations are:

Ei,h = [161500/Ti,h x e(-1380/T

i,h

)

] x ARi,h

PEi,h = Ei,h / Sum(Ei,h) 

where

 PEi,h = Percentage of emissions in county i on hour h

 Ei,h = Emission rate in county i on hour h

 Ti,h = Ambient temperature (Kelvin) in county i on hour h

 Vi,h = Wind speed (meter/sec) in county i (minimum wind speed is 0.1 meter/sec) 

 ARi,h = Aerodynamic resistance in county i

GenTPRO was run using the “BASH_NH3” profile method to create month-to-hour temporal profiles for 

these sources. Because these profiles distribute to the hour based on monthly emissions, the monthly 

emissions are obtained from a monthly inventory, or from an annual inventory that has been temporalized 

to the month. Figure 3-16 compares the daily emissions for Minnesota from the “old” approach (uniform 

monthly profile) with the “new” approach (GenTPRO generated month-to-hour profiles). Although the 

GenTPRO profiles show daily (and hourly variability), the monthly total emissions are the same between 

the two approaches.

0

10

20

30

40

50

60

70

80

90

100

JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC

Millions

Monthly Temporal Activity for OHH & Recreational RWC

Fire Pit/Chimenea

Outdoor Hydronic Heater
71

Figure 3-16. Example of animal NH3 emissions temporalization approach, summed to daily emissions

3.3.5 Onroad mobile temporalization (onroad)

For the onroad sector, the temporal distribution of emissions is a combination of more traditional 

temporal profiles and the influence of meteorology. This section will discuss both the meteorological 

influences and the updates to the diurnal temporal profiles for the 2011v6.2 platform.

Meteorology is not used in the development of the temporal profiles, but rather it impacts the calculation 

of the hourly emissions through the program Movesmrg. The result is that the emissions vary at the 

hourly level by grid cell. More specifically, the on-network (RPD) and the off-network parked vehicle 

(RPV, RPH, and RPP) processes use the gridded meteorology (MCIP) directly. Movesmrg determines 

the temperature for each hour and grid cell and uses that information to select the appropriate emission 

factor (EF) for the specified SCC/pollutant/mode combination. In the 2011 platform (and the 

2011NEIv2), RPP was updated to use the gridded minimum and maximum temperature for the day. This 

more spatially resolved temperature range produces more accurate emissions for each grid cell. The 

combination of these four processes (RPD, RPV, RPH, and RPP) is the total onroad sector emissions. 

The onroad sector show a strong meteorological influence on their temporal patterns (see the 2011NEIv2

TSD for more details).

Figure 3-17 illustrates the difference between temporalization of the onroad sector used in the 2005 and 

earlier platforms and the meteorological influence via SMOKE-MOVES. In the plot, the “MOVES” 

inventory is a monthly inventory that is temporalized by SCC to day-of-week and hour. Similar 

temporalization is done for the VMT in SMOKE-MOVES, but the meteorologically varying EFs add an 

additional variation on top of the temporalization. Note, the SMOKE-MOVES run is based on the 2005 

platform and previous temporalization of VMT to facilitate the comparison of the results. In the figure, 

the MOVES emissions have a repeating pattern within the month, while the SMOKE-MOVES shows 

day-to-day (and hour-to-hour) variability. In addition, the MOVES emissions have an artificial jump 

between months which is due to the inventory providing new emissions for each month that are then 

temporalized within the month but not between months. The SMOKE-MOVES emissions have a 

smoother transition between the months.
72

Figure 3-17. Example of SMOKE-MOVES temporal variability of NOX emissions

For the onroad sector, the “inventories” referred to in Table 3-17 actually consist of activity data, not 

emissions. For RPP and RPV processes, the VPOP inventory is annual and does not need temporalization. 

For RPD, the VMT inventory is monthly and was temporalized to days of the week and then to hourly 

VMT through temporal profiles. The RPD processes require a speed profile (SPDPRO) that consists of 

vehicle speed by hour for a typical weekday and weekend day. Unlike other sectors, the temporal profiles 

and SPDPRO will impact not only the distribution of emissions through time but also the total emissions. 

Because SMOKE-MOVES (for RPD) calculates emissions from VMT, speed and meteorology, if one 

shifted the VMT or speed to different hours, it would align with different temperatures and hence 

different EF. In other words, two SMOKE-MOVES runs with identical annual VMT, meteorology, and 

MOVES EF, will have different total emissions if the temporalization of VMT changes. For RPH, the 

HOTELING inventory is monthly and was temporalized to days of the week and to hour of the day 

through temporal profiles. This is an analogous process to RPD except that speed is not included in the 

calculation of RPH.

In previous platforms, the diurnal profile for VMT24 varied by road type but not by vehicle type (see 

Figure 3-18). These profiles were used throughout the nation. 

 

24 These profiles were used in the 2007 platform and proceeding platforms.
73

Figure 3-18. Previous onroad diurnal weekday profiles for urban roads

Diurnal profiles that could differentiate by vehicle type as well as by road type and would potentially vary 

over geography were desired. In the development of the 2011v6.025 platform, the EPA updated these 

profiles to include information submitted by states in their MOVES county databases (CDBs). The 

2011NEIv2 process provided an opportunity to update these diurnal profile with new information 

submitted by states, to supplement the data with additional sources, and to refine the methodology. 

States submitted MOVES county databases (CDBs) that included information on the distribution of VMT 

by hour of day and by day of week26 (see the 2011NEIv2 TSD for details on the submittal process for 

onroad). EPA mined the state submitted MOVES CDBs for non-default diurnal profiles27. The list of 

potential diurnal profiles was then analyzed to see whether the profiles varied by vehicle type, road type, 

weekday vs. weekend, and by county within a state. For the MOVES diurnal profiles, EPA only 

considered the state profiles that varied significantly by both vehicle and road types. Only those profiles 

that passed this criteria were used in that state or used in developing default temporal profiles. The 

Vehicle Travel Information System (VTRIS) is a repository for reported traffic count data to the Federal 

Highway Administration (FHWA). EPA used 2012 VTRIS data to create additional temporal profiles for 

states that did not submit temporal information in their CDBs or where those profiles did not pass the 

variance criteria. The VTRIS data were used to create state specific diurnal profiles by HPMS vehicle and 

road type. EPA created distinct diurnal profiles for weekdays, Saturday and Sunday along with day of the 

week profiles28. 

EPA attempted to maximize the use of state and/or county specific diurnal profiles (either from MOVES 

or VTRIS). Where there was no MOVES or VTRIS data, then a new default profile would be used (see 

below for description of new profiles). This analysis was done separately for weekdays and for 

weekends, therefore some areas had submitted profiles for weekdays but defaults for weekends. The 

 

25 These profiles that were generated from MOVES submittals only were used for the v6 and v6.1 platforms. See their 

respective TSDs for more details.

26 The MOVES tables are the hourvmtfraction and the dayvmtfraction.

27 Further QA was done to remove duplicates and profiles that were missing two or more hours. If they were missing a single 

hour, the missing hour could be calculated by subtracting all other hours fractions from 1.

28 Note, the day of the week profiles (ie. Monday vs Tuesday vs etc) are only from the VTRIS data. The MOVES CDBs only 

have weekday vs weekend profiles so they were not included in calculating a new national default day of the week profile.
74

result was a set of profiles that varied geographically depending on the source of the profile and the 

characteristics of the profiles (see Figure 3-19).

Figure 3-19. Use of submitted versus new national default profiles

A new set of diurnal profiles was developed from the submitted profiles that varied by both vehicle type 

and road type. For the purposes of constructing the national default diurnal profiles, EPA created 

individual profiles for each state (averaging over the counties within) to create a single profile by state, 

vehicle type, road type, and the day (i.e. weekday vs Saturday vs Sunday). The source of the underlying 

profiles was either MOVES or VTRIS data (see Figure 3-19). The states individual profiles were averaged 

together to create a new default profile29. Figure 3-20 shows two new national default profiles for light 

duty gas vehicles (LDGV, SCC6 220121) and combination long-haul diesel trucks (HHDDV, SCC6

220262) on restricted urban roadways (interstates and freeways). The blue lines indicate the weekday 

profile, the green the Saturday profile, and the red the Sunday profile. In comparison, the new default 

profiles for weekdays places more LDGV VMT (upper plot) in the rush hours while placing HHDDV 

VMT (lower plot) predominately in the middle of the day with a longer tail into the evening hours and 

early morning. 

 

29 Note that the states were weighted equally in the average independent of the size of the state or the variation in submitted 

county data. 
75

Figure 3-20. Updated national default profiles for LDGV vs. HHDDV, urban restricted 

In addition to creating diurnal profiles, EPA developed day of week profiles using the VTRIS data. The 

creation of the state and national profiles was similar to the diurnal profiles (described above). Figure 
76

3-21 shows a set of national default profiles for rural restricted roads (top plot) and urban unrestricted 

roads (lower plot). Each vehicle type is a different color on the plots.

Figure 3-21. Updated national default profiles for day of week

In addition to creating diurnal profiles for VMT, EPA developed a national profile for hoteling. EPA 

averaged all the combination long-haul truck profiles on restricted roads (urban and rural) for weekdays to 

create a single national restricted profile (blue line in Figure 3-22). This was then inverted to create a 

profile for hoteling (green line in Figure 3-22). This single national profile was used for hoteling 
77

irrespective of location. 

Figure 3-22. Combination long-haul truck restricted and hoteling profile

For California, CARB supplied diurnal profiles that varied by vehicle type, day of the week30, and air 

basin. These CARB specific profiles were used in developing EPA estimates for California. Although 

EPA adjusted the total emissions to match California’s submittal to the 2011NEIv2, the temporalization 

of these emissions took into account both the state-specific VMT profiles and the SMOKE-MOVES 

process of incorporating meteorology. For more details on the adjustments to California’s onroad 

emissions, see Section 2.3.1 and the 2011NEIv2 TSD.

3.3.6 Additional sector specific details (afdust, beis, c1c2rail, c3marine, nonpt, 

ptnonipm, ptfire, np_oilgas)

For the afdust sector, meteorology is not used in the development of the temporal profiles, but it is used to 

reduce the total emissions based on meteorological conditions. These adjustments are applied through 

sector-specific scripts, beginning with the application of land use-based gridded transport fractions and 

then subsequent zero-outs for hours during which precipitation occurs or there is snow cover on the 

ground. The land use data used to reduce the NEI emissions explains the amount of emissions that are 

subject to transport. This methodology is discussed in (Pouliot, et al., 2010, 

http://www.epa.gov/ttn/chief/conference/ei19/session9/pouliot_pres.pdf, and in “Fugitive Dust Modeling 

for the 2008 Emissions Modeling Platform” (Adelman, 2012). The precipitation adjustment is applied to 

remove all emissions for days where measureable rain occurs. Therefore, the afdust emissions vary dayto-day based on the precipitation and/or snow cover for that grid cell and day. Both the transport fraction 

and meteorological adjustments are based on the gridded resolution of the platform; therefore, somewhat 

 

30 California’s diurnal profiles varied within the week. Monday, Friday, Saturday, and Sunday had unique profiles and 

Tuesday, Wednesday, Thursday had the same profile.
78

different emissions will result from different grid resolutions. Application of the transport fraction and 

meteorological adjustments prevents the overestimation of fugitive dust impacts in the grid modeling as 

compared to ambient samples.

Biogenic emissions in the beis sector vary by every day of the year because they are developed using 

meteorological data including temperature, surface pressure, and radiation/cloud data. The emissions are 

computed using appropriate emission factors according to the vegetation in each model grid cell, while 

taking the meteorological data into account.

For the c1c2rail and c3marine sectors, emissions are allocated with flat monthly and day of week profiles, 

and most emissions are also allocated with flat hourly profiles.

For the agfire sector, the emissions were allocated to months by adding up the available values for each 

day of the month. For all agricultural burning, the diurnal temporal profile used reflected the fact that 

burning occurs during the daylight hours - see Figure 3-23 (McCarty et al., 2009). This puts most of the 

emissions during the work day and suppresses the emissions during the middle of the night. A uniform 

profile for each day of the week was used for all agricultural burning emissions in all states, except for the 

following states that for which EPA used state-specific day of week profiles: Arkansas, Kansas, 

Louisiana, Minnesota, Missouri, Nebraska, Oklahoma, and Texas. 

Updates were made to temporal profiles for the ptnonipm sector in the 2011v6.2 platform based on 

comments and data review by EPA staff. Temporal profiles for small airports (i.e., non-commercial) were 

updated to eliminate emissions between 10pm and 6am due to a lack of tower operations. Industrial 

process that are not likely to shut down on Sundays such as those at cement plants were assigned to other 

more realistic profiles that included emissions on Sundays. This also affected emissions on holidays 

because Sunday emissions are also used on holidays.

Figure 3-23. Agricultural burning diurnal temporal profile
79

For the ptwildfire and ptprescfire sectors, the inventories are in the daily point fire format ORL PTDAY. 

The ptfire sector is used in the model evaluation case (2011eh and in the future base case (2017eh). The 

2007 and earlier platforms had additional regulatory cases that used averaged fires and temporally 

averaged EGU emissions, but the 2011 platform uses base year-specific (i.e., 2011) data for both cases.

For the nonroad sector, while the NEI only stores the annual totals, the modeling platform uses monthly 

inventories from output from NMIM. For California, a monthly inventory was created from CARB’s 

annual inventory using EPA-estimated NMIM monthly results to compute monthly ratios by pollutant and 

SCC7 and these ratios were applied to the CARB inventory to create a monthly inventory.

Some cross reference updates for temporalization of the np_oilgas sector were made in the 2011v6.2 

platform to assign np_oilgas sources to 24 hour per day, 7 days a week based on comments received.

3.4 Spatial Allocation

The methods used to perform spatial allocation are summarized in this section. For the modeling 

platform, spatial factors are typically applied by county and SCC. As described in Section 3.1, spatial 

allocation was performed for a national 12-km domain. To accomplish this, SMOKE used national 12-km

spatial surrogates and a SMOKE area-to-point data file. For the U.S., EPA updated surrogates to use circa 

2010-2011 data wherever possible. For Mexico, updated spatial surrogates were used as described below. 

For Canada surrogates provided by Environment Canada were used and are unchanged from the 2007 

platform. The U.S., Mexican, and Canadian 12-km surrogates cover the entire CONUS domain 12US1

shown in Figure 3-1. 

The details regarding how the 2011v6.2 platform surrogates were created are available from 

ftp://ftp.epa.gov/EmisInventory/2011v6/v2platform/spatial_surrogates/ in the files 

US_SpatialSurrogate_Workbook_v072115.xlsx and US_SpatialSurrogate_Documentation_v070115.pdf, 

and SurrogateTools_Scripts_2014.zip available. The remainder of this subsection provides further detail 

on the origin of the data used for the spatial surrogates and the area-to-point data.

3.4.1 Spatial Surrogates for U.S. emissions

There are more than 100 spatial surrogates available for spatially allocating U.S. county-level emissions 

to the 12-km grid cells used by the air quality model. As described in Section 3.4.2, an area-to-point 

approach overrides the use of surrogates for a limited set of sources. Table 3-18 lists the codes and 

descriptions of the surrogates. Surrogate names and codes listed in italics are not directly assigned to any 

sources for the 2011v6.2 platform, but they are sometimes used to gapfill other surrogates, or as an input 

for merging two surrogates to create a new surrogate that is used.

Many surrogates use circa 2010-based data, including 2010 census data at the block group level, 2010 

American Community Survey Data for heating fuels, 2010 TIGER/Line data for railroads and roads, the 

2006 National Land Cover Database, 2011 gas station and dry cleaner data, and the 2012 National 

Transportation Atlas Data for rail-lines, ports and navigable waterways. Surrogates for ports (801) and 

shipping lanes (802) were developed based on the 2011NEIv2 shapefiles: Ports_032310_wrf and 

ShippingLanes_111309FINAL_wrf, but also included shipping lane data in the Great Lakes and support 

vessel activity data in the Gulf of Mexico. The creation of surrogates and shapefiles for the U.S. was 

generated via the Surrogate Tool. The tool and documentation for it is available at 

http://www.ie.unc.edu/cempd/projects/mims/spatial/ and https://www.cmascenter.org/satools/documentation/4.2/html/srgtool/SurrogateToolUserGuide_4_2.htm. 
80

Table 3-18. U.S. Surrogates available for the 2011 modeling platform.

Code Surrogate Description Code Surrogate Description

N/A Area-to-point approach (see 3.3.1.2) 507 Heavy Light Construction Industrial Land

100 Population 510 Commercial plus Industrial

110 Housing 515 Commercial plus Institutional Land

120 Urban Population 520 Commercial plus Industrial plus Institutional

130 Rural Population 525

Golf Courses + Institutional +Industrial + 

Commercial

137 Housing Change 526 Residential Non-Institutional

140 Housing Change and Population 527 Single Family Residential

150 Residential Heating - Natural Gas 530 Residential - High Density

160 Residential Heating – Wood 535

Residential + Commercial + Industrial + 

Institutional + Government

165

0.5 Residential Heating - Wood plus 0.5 Low 

Intensity Residential 540 Retail Trade 

170 Residential Heating - Distillate Oil 545 Personal Repair 

180 Residential Heating – Coal 550 Retail Trade plus Personal Repair 

190 Residential Heating - LP Gas 555

Professional/Technical plus General 

Government 

200 Urban Primary Road Miles 560 Hospitals

205 Extended Idle Locations 565 Medical Offices/Clinics

210 Rural Primary Road Miles 570 Heavy and High Tech Industrial 

220 Urban Secondary Road Miles 575 Light and High Tech Industrial 

221 Urban Unrestricted Roads 580 Food, Drug, Chemical Industrial

230 Rural Secondary Road Miles 585 Metals and Minerals Industrial

231 Rural Unrestricted Roads 590 Heavy Industrial 

240 Total Road Miles 595 Light Industrial 

250 Urban Primary plus Rural Primary 596 Industrial plus Institutional plus Hospitals

255 0.75 Total Roadway Miles plus 0.25 Population 600 Gas Stations

256 Off-Network Short-Haul Trucks 650 Refineries and Tank Farms

257 Off-Network Long-Haul Trucks 675 Refineries and Tank Farms and Gas Stations

258 Intercity Bus Terminals 680

Oil & Gas Wells, IHS Energy, Inc. and 

USGS (see updated surrogates in Table 3-19)

259 Transit Bus Terminals 700 Airport Areas

260 Total Railroad Miles 710 Airport Points

261 NTAD Total Railroad Density 720 Military Airports

270 Class 1 Railroad Miles 800 Marine Ports

271 NTAD Class 1, 2, 3 Railroad Density 801 NEI Ports

280 Class 2 and 3 Railroad Miles 802 NEI Shipping Lanes 

300 Low Intensity Residential 806 Offshore Shipping NEI NOx

310 Total Agriculture 807 Navigable Waterway Miles

312 Orchards/Vineyards 808 Gulf Tug Zone Area

320 Forest Land 810 Navigable Waterway Activity

330 Strip Mines/Quarries 812 Midwest Shipping Lanes

340 Land 820 Ports NEI NOx

350 Water 850 Golf Courses

400 Rural Land Area 860 Mines

500 Commercial Land 870 Wastewater Treatment Facilities

505 Industrial Land 880 Drycleaners

506 Education 890 Commercial Timber
81

For the onroad sector, the on-network (RPD) emissions were spatially allocated to roadways, and the offnetwork (RPP and RPV) emissions were allocated to population. The refueling emissions were spatially 

allocated to gas station locations (surrogate 600). On-network (i.e., on-roadway) mobile source emissions 

were assigned to the following surrogates: rural restricted access to rural primary road miles (210), rural 

unrestricted access to 231, urban restricted access to urban primary road miles (200), and urban 

unrestricted access to 221. Off-network emissions were spatially allocated according to the mapping in

Table 3-19. In the 2011v6.2 platform, emissions from the extended (i.e., overnight) idling of trucks were 

assigned to a new surrogate 205 that is based on locations of overnight truck parking spaces.

Table 3-19. Off-Network Mobile Source Surrogates

Source type Source Type name Surrogate ID

11 Motorcycle 535

21 Passenger Car 535

31 Passenger Truck 535

32 Light Commercial Truck 510

41 Intercity Bus 258

42 Transit Bus 259

43 School Bus 506

51 Refuse Truck 507

52 Single Unit Short-haul Truck 256

53 Single Unit Long-haul Truck 257

54 Motor Home 526

61 Combination Short-haul Truck 256

62 Combination Long-haul Truck 257

For the oil and gas sources in the np_oilgas sector, the spatial surrogates were updated to those shown in 

Table 3-20 using 2011 data consistent with what was used to develop the 2011NEI nonpoint oil and gas 

emissions. Note that the “Oil & Gas Wells, IHS Energy, Inc. and USGS” (680) is older and based on 

circa-2005 data. These surrogates were based on the same GIS data of well locations and related 

attributes as was used to develop the 2011NEIv2 data for the oil and gas sector. The data sources include

Drilling Info (DI) Desktop’s HPDI database (Drilling Info, 2012) aggregated to grid cell levels, along 

with data from Oil and Gas Commission (OGC) websites. Well completion data from HPDI was 

supplemented by implementing the methodology for counting oil and gas well completions developed for 

the U.S. National Greenhouse Gas Inventory. Under that methodology, both completion date and date of 

first production from HPDI were used to identify wells completed during 2011. In total, over 1.08 million 

unique well locations were compiled from the various data sources. The well locations cover 33 states and 

1,193 counties (ERG, 2014b). Although basically the same surrogates were used, some minor updates to 

the oil and gas surrogates were made in the 2011v6.2 platform to correct some mis-located emissions.

Table 3-20. Spatial Surrogates for Oil and Gas Sources

Surrogate Code Surrogate Description

681 Spud count - Oil Wells

682 Spud count - Horizontally-drilled wells

683 Produced Water at all wells

684 Completions at Gas and CBM Wells

685 Completions at Oil Wells
82

686 Completions at all wells

687 Feet drilled at all wells

688 Spud count - Gas and CBM Wells

689 Gas production at all wells

692 Spud count - All Wells

693 Well count - all wells

694 Oil production at oil wells

695 Well count - oil wells

697 Oil production at Gas and CBM Wells

698 Well counts - Gas and CBM Wells

Some spatial surrogate cross reference updates were made between the 2011v6.1 platform and the 

2011v6.2 platform aside from the reworking of the onroad mobile source surrogates described above. 

These updates included the following: 

 Nonroad SCCs using spatial surrogate 525 (50% commercial + industrial + institutional, 50% golf 

courses) were changed to 520 (100% commercial + industrial + institutional). The golf course 

surrogate 850, upon which 525 is partially based, is incomplete and subject to hot spots;

 Some nonroad SCCs for commercial equipment in New York County had assignments updated to 

surrogate 340;

 Commercial lawn and garden equipment was updated to use surrogate 520; and

 Some county-specific assignments for RWC were updated to use surrogate 300.

Not all of the available surrogates are used to spatially allocate sources in the modeling platform; that is, 

some surrogates shown in Table 3-18 were not assigned to any SCCs, although many of the “unused” 

surrogates are actually used to “gap fill” other surrogates that are used. When the source data for a 

surrogate has no values for a particular county, gap filling is used to provide values for the surrogate in 

those counties to ensure that no emissions are dropped when the spatial surrogates are applied to the 

emission inventories. Table 3-21 shows the CAP emissions (i.e., NH3, NOx, PM2.5, SO2, and VOC) by 

sector, with rows for each sector listed in order of most emissions to least CAP emissions. 

Table 3-21. Selected 2011 CAP emissions by sector for U.S. Surrogates*

Sector ID Description NH3 NOX PM2_5 SO2 VOC

afdust 130 Rural Population 0 0 1,089,422 0 0

afdust 310 T0otal Agriculture 0 0 895,786 0 0

afdust 240 Total Road Miles 0 0 286,188 0 0

afdust 140

Housing Change and 

Population 0 0 159,485 0 0

afdust 330 Strip Mines/Quarries 0 0 58,959 0 0

afdust 400 Rural Land Area 0 0 1 0 0

ag 310 Total Agriculture 3,502,246 0 0 0 0

agfire 310 Total Agriculture 3,287 42,326 92,754 15,470 73,858

agfire 312 Orchards/Vineyards 27 432 1,082 753 799

agfire 320 Forest Land 7 8 121 0 124

c1c2rail 271

NTAD Class 1 2 3 Railroad 

Density 332 734,683 22,636 7,390 38,304
83

Sector ID Description NH3 NOX PM2_5 SO2 VOC

c1c2rail 806

Offshore Shipping NEI2011 

NOx 329 504,779 16,146 7,272 12,151

c1c2rail 820 Ports NEI2011 NOx 19 56,363 1,866 834 1,666

c1c2rail 280 Class 2 and 3 Railroad Miles 13 41,963 948 287 1,622

c1c2rail 261 NTAD Total Railroad Density 2 16,636 379 260 925

c3marine 806

Offshore Shipping NEI2011 

NOx 27 77,281 5,143 50,309 3,150

c3marine 820 Ports NEI2011 NOx 41 54,101 3,900 36,064 1,998

nonpt 100 Population 4,137 0 0 0 1,196,465

nonpt 505 Industrial Land 35,360 195,282 124,150 111,849 114,391

nonpt 600 Gas Stations 0 0 0 0 416,448

nonpt 310 Total Agriculture 0 0 614 0 363,385

nonpt 535

Residential + Commercial + 

Industrial + Institutional + 

Government 23 366 1,283 0 327,986

nonpt 515

Commercial plus Institutional 

Land 1,408 177,903 18,637 58,287 21,915

nonpt 150

Residential Heating - Natural 

Gas 40,775 217,560 4,785 1,443 13,031

nonpt 510 Commercial plus Industrial 4 178 27 109 224,110

nonpt 140

Housing Change and 

Population 3 23,423 65,897 29 134,887

nonpt 300 Low Intensity Residential 3,847 18,334 90,706 3,048 40,003

nonpt 527 Single Family Residential 0 0 0 0 153,528

nonpt 590 Heavy Industrial (IND1) 10 4,373 5,419 1,131 138,575

nonpt 170

Residential Heating - Distillate 

Oil 2,045 40,842 4,523 88,432 1,394

nonpt 650 Refineries and Tank Farms 0 0 0 0 129,572

nonpt 500 Commercial Land 2,367 2 85,404 585 26,183

nonpt 250

Urban Primary plus Rural 

Primary 0 0 0 0 102,207

nonpt 595 Light Industrial (IND2) 0 1 244 0 79,169

nonpt 545 Personal Repair (COM3) 0 0 93 0 60,289

nonpt 190 Residential Heating - LP Gas 136 38,705 224 705 1,432

nonpt 240 Total Road Miles 0 27 602 0 32,152

nonpt 520

Commercial plus Industrial plus 

Institutional 0 0 0 0 14,965

nonpt 801 Port Areas 0 0 0 0 12,469

nonpt 580

Food, Drug, Chemical 

Industrial (IND3) 0 610 313 171 10,535

nonpt 180 Residential Heating – Coal 247 1,033 605 7,931 1,233

nonpt 880 Drycleaners 0 0 0 0 7,053

nonpt 870

Wastewater Treatment 

Facilities 1,003 0 0 0 4,671

nonpt 555

Professional/Technical (COM4) 

plus General Government 

(GOV1) 0 0 0 0 2,865

nonpt 400 Rural Land Area 2,855 0 0 0 0

nonpt 312 Orchards/Vineyards 0 441 117 1,806 262

nonpt 575

Light and High Tech Industrial 

(IND2 + IND5) 0 0 0 0 2,538
84

Sector ID Description NH3 NOX PM2_5 SO2 VOC

nonpt 260 Total Railroad Miles 0 0 0 0 2,195

nonpt 700 Airport area 0 0 0 0 1,956

nonpt 540 Retail Trade (COM1) 0 0 0 0 1,371

nonpt 675

Refineries and Tank Farms and 

Gas Stations 0 0 0 0 1,203

nonpt 585

Metals and Minerals Industrial 

(IND4) 0 23 140 8 443

nonpt 320 Forest Land 0 85 287 0 97

nonpt 330 Strip Mines/Quarries 0 4 0 0 48

nonpt 560 Hospital (COM6) 0 0 0 0 10

nonroad 350 Water 213 143,096 12,395 337 614,637

nonroad 400 Rural Land Area 157 25,658 16,711 194 620,786

nonroad 140

Housing Change and 

Population 554 537,250 45,058 1,255 78,526

nonroad 310 Total Agriculture 481 488,224 39,037 910 57,473

nonroad 520

Commercial plus Industrial plus 

Institutional 205 70,541 16,361 288 255,836

nonroad 510 Commercial plus Industrial 382 131,572 9,888 348 139,291

nonroad 300 Low Intensity Residential 106 26,637 4,324 138 202,928

nonroad 505 Industrial Land 452 146,871 5,809 411 32,978

nonroad 100 Population 40 39,475 2,824 85 5,030

nonroad 890 Commercial Timber 19 12,979 1,486 38 8,680

nonroad 850 Golf Courses 12 2,394 112 17 7,092

nonroad 860 Mines 2 2,931 341 5 594

nonroad 261 NTAD Total Railroad Density 2 2,673 310 5 568

np_oilgas 698

Well count - gas and CBM 

wells 0 378,342 6,608 2,636 566,281

np_oilgas 694 Oil production at oil wells 0 1,847 0 12,602 729,489

np_oilgas 695 Well count - oil wells 0 103,585 3,299 96 452,404

np_oilgas 697

Oil production at gas and CBM 

wells 0 3,275 203 35 465,498

np_oilgas 686 Completions at all wells 0 8,926 333 44 106,170

np_oilgas 689 Gas production at all wells 0 39,256 2,323 225 62,716

np_oilgas 693 Well count - all wells 0 29,867 436 141 51,389

np_oilgas 687 Feet drilled at all wells 0 44,820 1,449 119 9,714

np_oilgas 683 Produced Water at all wells 0 0 0 0 45,033

np_oilgas 692 Spud count - all wells 0 29,816 417 520 4,686

np_oilgas 685 Completions at Oil Wells 0 360 11 381 28,194

np_oilgas 688

Spud count - Gas and CBM 

Wells 0 0 0 0 16,115

np_oilgas 684

Completions at Gas and CBM 

Wells 0 1,532 46 1,497 11,706

np_oilgas 681 Spud count - Oil Wells 0 0 0 0 6,700

np_oilgas 682

Spud count - Horizontallydrilled wells 0 5,526 208 9 349

np_oilgas 680 Oil and Gas Wells 0 10 0 0 55

np_oilgas 400 Rural Land Area 0 0 0 0 50

onroad 221 Urban Unrestricted Roads 49,896 1,580,588 66,861 12,781 407,127
85

Sector ID Description NH3 NOX PM2_5 SO2 VOC

onroad 535

Residential + Commercial + 

Industrial + Institutional + 

Government 675,029 13,884 982 1,349,381

onroad 231 Rural Unrestricted Roads 30,644 1,245,765 42,117 6,945 224,361

onroad 200 Urban Primary Road Miles 26,961 938,015 37,845 5,855 150,425

onroad 210 Rural Primary Road Miles 12,396 799,645 24,520 2,811 76,295

onroad 205 Extended Idle Locations 908 336,235 6,874 119 75,323

onroad 510 Commercial plus Industrial 132,109 2,225 156 213,658

onroad 600 Gas Stations 190,698

onroad 256

Off-Network Short-Haul 

Trucks 11,019 271 10 17,088

onroad 526 Residential - Non-Institutional 741 19 1 2,415

onroad 257 Off-Network Long-Haul Trucks 431 38 2 1,423

onroad 506 Education 346 28 1 1,050

onroad 507

Heavy Light Construction 

Industrial Land 33 2 0 98

onroad 259 Transit Bus Terminals 8 4 0 101

onroad 258 Intercity Bus Terminals 18 1 0 27

rwc 165

0.5 Residential Heating - Wood 

plus 0.5 Low Intensity 

Residential 19,260 33,660 374,085 8,838 433,797

rwc 300 Low Intensity Residential 412 745 6,742 107 8,301

3.4.2 Allocation method for airport-related sources in the U.S. 

There are numerous airport-related emission sources in the NEI, such as aircraft, airport ground support 

equipment, and jet refueling. The modeling platform includes the aircraft and airport ground support 

equipment emissions as point sources. For the modeling platform, EPA used the SMOKE “area-to-point” 

approach for only jet refueling in the nonpt sector. The following SCCs use this approach: 2501080050 

and 2501080100 (petroleum storage at airports), and 2810040000 (aircraft/rocket engine firing and 

testing). The ARTOPNT approach is described in detail in the 2002 platform documentation: 

http://www.epa.gov/scram001/reports/Emissions%20TSD%20Vol1_02-28-08.pdf. The ARTOPNT file 

that lists the nonpoint sources to locate using point data were unchanged from the 2005-based platform. 

3.4.3 Surrogates for Canada and Mexico emission inventories

The surrogates for Canada to spatially allocate the 2010 Canadian emissions have been updated in the 

2011v6.2 platform. The spatial surrogate data came from Environment Canada, along with cross 

references. The surrogates they provided were outputs from the Surrogate Tool (previously referenced). 

The Canadian surrogates used for this platform are listed in Table 3-22. The leading “9” was added to the 

surrogate codes to avoid duplicate surrogate numbers with U.S. surrogates. Surrogates for Mexico are 

circa 1999 and 2000 and were based on data obtained from the Sistema Municpal de Bases de Datos 

(SIMBAD) de INEGI and the Bases de datos del Censo Economico 1999. Most of the CAPs allocated to 

the Mexico and Canada surrogates are shown in Table 3-23. The entries in this table are for the othar 

sector except for the “MEX Total Road Miles” and the “CAN traffic” rows, which are for the othon 

sector.
86

Table 3-22. Canadian Spatial Surrogates 

Code Canadian Surrogate Description Code Description

9100 Population 92424 BARLEY

9101 total dwelling 92425 BUCWHT

9103 rural dwelling 92426 CANARY

9106 ALL_INDUST 92427 CANOLA

9111 Farms 92428 CHICPEA

9113 Forestry and logging 92429 CORNGR

9211 Oil and Gas Extraction 92425 BUCWHT

9212 Mining except oil and gas 92430 CORNSI

9221 Total Mining 92431 DFPEAS

9222 Utilities 92432 FLAXSD

9233 Total Land Development 92433 FORAGE

9308 Food manufacturing 92434 LENTIL

9321 Wood product manufacturing 92435 MUSTSD

9323 Printing and related support activities 92436 MXDGRN

9324 Petroleum and coal products manufacturing 92437 OATS

9327 Non-metallic mineral product manufacturing 92438 ODFBNS

9331 Primary Metal Manufacturing 92439 OTTAME

9412 Petroleum product wholesaler-distributors 92440 POTATS

9416

Building material and supplies wholesalerdistributors 92441 RYEFAL

9447 Gasoline stations 92442 RYESPG

9448 clothing and clothing accessories stores 92443 SOYBNS

9481 Air transportation 92444 SUGARB

9482 Rail transportation 92445 SUNFLS

9562 Waste management and remediation services 92446 TOBACO

9921 Commercial Fuel Combustion 92447 TRITCL

9924 Primary Industry 92448 WHITBN

9925 Manufacturing and Assembly 92449 WHTDUR

9932 CANRAIL 92450 WHTSPG

9941 PAVED ROADS 92451 WHTWIN

9942 UNPAVED ROADS 92452 BEANS

9945 Commercial Marine Vessels 92453 CARROT

9946 Construction and mining 92454 GRPEAS

9948 Forest 92455 OTHVEG

9950 Combination of Forest and Dwelling 92456 SWCORN

9955 UNPAVED_ROADS_AND_TRAILS 92457 TOMATO

9960 TOTBEEF 92430 CORNSI

9970 TOTPOUL 92431 DFPEAS

9980 TOTSWIN 92432 FLAXSD

9990 TOTFERT 92433 FORAGE

9996 urban_area 92434 LENTIL

9997 CHBOISQC 92435 MUSTSD

91201 traffic_bcw 92436 MXDGRN
87

Code Canadian Surrogate Description Code Description

92401 BULLS 92437 OATS

92402 BFCOWS 92438 ODFBNS

92403 BFHEIF 92439 OTTAME

92404 CALFU1 92440 POTATS

92405 FDHEIF 92441 RYEFAL

92406 STEERS 92442 RYESPG

92407 MLKCOW 92443 SOYBNS

92408 MLKHEIF 92444 SUGARB

92409 MBULLS 92445 SUNFLS

92410 MCALFU1 92446 TOBACO

92412 BROILER 92447 TRITCL

92413 LAYHEN 92448 WHITBN

92414 TURKEY 92449 WHTDUR

92416 BOARS 92450 WHTSPG

92417 GRWPIG 92451 WHTWIN

92418 NURPIG 92452 BEANS

92419 SOWS 92453 CARROT

92421 IMPAST 92454 GRPEAS

92422 UNIMPAST 92455 OTHVEG

92423 ALFALFA 92456 SWCORN

92457 TOMATO

Table 3-23. CAPs Allocated to Mexican and Canadian Spatial Surrogates 

Code Mexican or Canadian Surrogate Description NH3 NOX PM 2_5 SO2 VOC

22 MEX Total Road Miles 15,965 370,867 34,396 13,713 375,276

10 MEX Population 0 0 0 0 431,231

12 MEX Housing 0 161,013 17,483 2,123 452,685

14 MEX Residential Heating - Wood 0 20,093 211,525 2,859 380,572

16 MEX Residential Heating - Distillate Oil 0 38 0 11 2

20 MEX Residential Heating - LP Gas 0 25,303 787 63 614

22 MEX Total Road Miles 0 0 0 0 3,513

24 MEX Total Railroads Miles 0 74,969 1,669 663 2,824

26 MEX Total Agriculture 679,212 164,144 72,372 2,127 43,958

28 MEX Forest Land 0 16,224 67,683 660 79,018

32 MEX Commercial Land 0 125,211 7,726 0 286,982

34 MEX Industrial Land 0 45,831 5,684 59,201 133,440

36 MEX Commercial plus Industrial Land 0 0 0 0 332,495

38 MEX Commercial plus Institutional Land 0 6,400 216 84 28,293

40

Residential (RES1-4)+Commercial+Industrial+

Institutional+ Government 0 8 20 0 241,710

42 MEX Personal Repair (COM3) 0 0 0 0 33,616

44 MEX Airports Area 0 14,639 0 1,149 6,857

46 MEX Marine Ports 0 124,951 2,991 1,482 1,099
88

Code Mexican or Canadian Surrogate Description NH3 NOX PM 2_5 SO2 VOC

48 Brick Kilns - Mexico 0 776 6,691 0 10,244

50 Mobile sources - Border Crossing - Mexico 0 454 0 0 2,668

9100 CAN Population 603 0 276 0 304

9101 CAN total dwelling 643 46,256 12,783 14,698 32,944

9106 CAN ALL_INDUST 133 21,526 381 3,921 2

9113 CAN Forestry and logging 1,582 8,561 28,622 1,809 36,114

9115 CAN Agriculture and forestry activities 160 239,553 25,318 9,092 26,526

9116 CAN Total Resources 0 17 0 0 5

9212 CAN Mining except oil and gas 0 0 5,391 0 0

9221 CAN Total Mining 42 2,292 45,374 728 26

9222 CAN Utilities 189 14,882 369 1,124 255

9233 CAN Total Land Development 17 20,789 1,928 981 2,551

9308 CAN Food manufacturing 0 0 0 0 4,535

9323 CAN Printing and related support activities 0 0 0 0 25,203

9324

CAN Petroleum and coal products 

manufacturing 0 0 2,402 0 0

9327

CAN Non-metallic mineral product 

manufacturing 0 238 7,708 2,941 1,218

9331 CAN Primary Metal Manufacturing 0 98 5,062 12 6

9412 CAN Petroleum product wholesaler-distributors 0 0 0 0 70,125

9416

CAN Building material and supplies 

wholesaler-distributors 2 0 1,461 3,259 560

9448 CAN clothing and clothing accessories stores 0 0 0 0 328

9562

CAN Waste management and remediation 

services 165 893 1,596 1,998 16,551

9921 CAN Commercial Fuel Combustion 494 33,816 2,750 35,471 850

9924 CAN Primary Industry 0 0 0 0 219,282

9925 CAN Manufacturing and Assembly 0 0 0 0 139,227

9931 CAN OTHERJET 9 14,388 548 1,139 7,629

9932 CAN CANRAIL 109 122,694 4,093 5,737 3,304

9942 CAN UNPAVED ROADS 40 3,462 3,499 48 152,674

9945 CAN Commercial Marine Vessels 28 45,454 6,404 14,325 61,139

9946 CAN Construction and mining 247 156,770 10,070 5,667 17,180

9947 CAN Agriculture Construction and mining 19 37,452 536 26 32,683

9950 CAN Intersection of Forest and Housing 1,053 11,700 120,045 1,671 173,130

9960 CAN TOTBEEF 176,156 0 7,420 0 317,394

9970 CAN TOTPOUL 74,204 0 2 0 264

9980 CAN TOTSWIN 122,094 0 996 0 3,186

9990 CAN TOTFERT 178,791 0 9,279 0 0

9991 CAN traffic 22,294 550,896 10,888 5,548 285,104

9994 CAN ALLROADS 0 0 55,468 0 0

9995 CAN 30UNPAVED_70trail 0 0 106,707 0 0

9996 CAN urban_area 0 0 284 0 0
89

4 Development of 2017 and 2025 Base-Case Emissions

The emission inventories for the future years of 2017 and 2025 have been developed using projection methods 

that are specific to the type of emission source. Future emissions are projected from the 2011 base case either by 

running models to estimate future year emissions from specific types of emission sources (e.g., EGUs, and 

onroad and nonroad mobile sources), or for other types of sources by adjusting the base year emissions 

according to the best estimate of changes expected to occur in the intervening years (e.g., non-EGU point and 

nonpoint sources). For some sectors, the same emissions are used in the base and future years, such as biogenic, 

fire, and Canadian emissions. For the remaining sectors, rules and specific legal obligations that go into effect in 

the intervening years, along with changes in activity for the sector, are considered when possible. The 2017 and 

2025 base case emission inventories represent predicted emissions that account for Federal and State measures 

promulgated or under reconsideration by December, 2014.

Emissions inventories for neighboring countries used in our modeling are included in the 2011v6.2 platform, 

specifically 2008, 2018, and 2025 emissions inventories for Mexico, and 2010 emissions inventories for 

Canada. The meteorological data used to create and temporalize emissions for the future year cases is held 

constant and represents the year 2011. With the exception of speciation profiles for mobile sources and 

temporal profiles for EGUs, the same ancillary data files are used to prepare the future year emissions 

inventories for air quality modeling as were used to prepare the 2011 base year inventories.

Emission projections for EGUs were developed using IPM version 5.14 and are reflected in an air quality 

modeling-ready flat file taken from the EPA Base Case v.5.14. The NEEDS database is an important input to 

IPM in that contains the generation unit records used for the model plants that represent existing and 

planned/committed units in EPA modeling applications of IPM. NEEDS includes basic geographic, operating, 

air emissions, and other data on these generating units and has been updated for the EPA’s version 5.14 power 

sector modeling platform based on comments received on the notices of data availability for the 2011 and 2018 

emissions modeling platforms and through other sources of data. The EGU emission projections in the flat file 

format, the corresponding NEEDS database, and user guides and documentation are available with the 

information for the EPA’s Power Sector Modeling Platform v.5.14 at http://www.epa.gov/powersectormodeling

Note: after October 1, 2015, the new site will be http://www.epa.gov/airmarkets/powersectormodeling.html. 

The projected EGU emissions include the Final Mercury and Air Toxics (MATS) rule announced on December 

21, 2011 and the Cross-State Air Pollution Rule (CSAPR) issued July 6, 2011. Note that the Clean Power Plan 

is not included in the 2017 or 2025 base cases.

To project future emissions for onroad and nonroad mobile sources, the EPA used MOVES2014 and NMIM,

respectively. The EPA obtained future year projected emissions for these sectors by running the MOVES and 

NMIM models using year-specific information about fuel mixtures, activity data, and the impacts of national 

and state-level rules and control programs. Development of the future year onroad and nonroad emissions 

requires a substantial amount of lead time and resources. EPA had already prepared the emissions projections 

for 2018 when EPA revised the attainment deadline for Moderate nonattainment areas to July 2018 in the 2008 

Ozone SIP Requirements Rule, as discussed above, which effectively required the agency to adjust its 

projection year for this rulemaking to 2017. Thus, for purposes of the 2011v6.2 platform, the EPA calculated 

the 2017 emissions from mobile sources by adjusting the 2018 emissions to represent 2017 using factors 

derived from national scale runs of MOVES and NMIM, respectively. The agency anticipates that for the final 

rule to address interstate transport for the 2008 ozone standard, the mobile source emissions for 2017 that will 

be used in the air quality modeling will be generated by running these for models the year 2017. 
90

For non-EGU point and nonpoint sources, projections of 2017 emissions were developed by starting with the 

2011 emissions inventories and applying adjustments that represent the impact of national, state, and local rules 

coming into effect in the years 2012 through 2017, along with the impacts of planned shutdowns, the 

construction of new plants, specific information provided by states, and specific legal obligations resolving 

alleged environmental violations, such as consent decrees. Changes in activity are considered for sectors such as

oil and gas, residential wood combustion, cement kilns, livestock, aircraft, commercial marine vessels and 

locomotives. Efforts were made to include some regional haze and state-reported local controls as part of a 

larger effort to include more local control information on stationary non-EGU sources are described further in 

Section 4.2. 

The following bullets summarize the projection methods used for sources in the various sectors, while 

additional details and data sources are given in the following subsections and in Table 4-1.

 EGU sector (ptegu): Unit-specific estimates from IPM version 5.14, including CASPR, Final MATS, 

Regional Haze rule, and Cooling Water Intakes Rule.

 Non-IPM sector (ptnonipm): Closures, projection factors and percent reductions reflect comments 

received from the notices of data availability for the 2011 and 2018 emissions modeling platforms, along 

with emission reductions due to national and local rules, control programs, plant closures, consent 

decrees and settlements. Projection for corn ethanol and biodiesel plants, refineries and upstream 

impacts take into account Annual Energy Outlook (AEO) fuel volume projections. Airport-specific 

terminal area forecast (TAF) data were used for aircraft to account for projected changes in 

landing/takeoff activity. For year 2017, due to the late change of modeling years from 2018 to 2017, 

most projection information was obtained for year 2018 but projections were processed for the year 

2017, meaning that controls with known compliance dates in year 2018 were not applied.

 Point and nonpoint oil and gas sectors (pt_oilgas and np_oilgas): Regional projection factors by product 

and consumption indicators using information from AEO 2014 projections to years 2018 and 2025, as 

well as comments received on the notices of data availability for the 2011 and 2018 emissions modeling 

platforms. Cobenefits of stationary engines CAP-cobenefit reductions (RICE NESHAP) and controls 

from New Source Performance Standards (NSPS) are reflected for select source categories. 

 Biogenic (beis): 2011 emissions are used for all future-year scenarios and are computed with the same 

“11g” meteorology as is used for the air quality modeling.

 Fires sectors (ptwildfire, ptprescfire, agfire): No growth or control – 2011 estimates are used directly.

 Agricultural sector (ag): Year 2017 and 2025 projection factors for livestock estimates based on 

expected changes in animal population from 2005 Department of Agriculture data, updated according to

EPA experts in July 2012.

 Area fugitive dust sector (afdust): For livestock PM emissions, projection factors for dust categories 

related to livestock estimates based on expected changes in animal population. For unpaved and paved 

road dust, county-level VMT projections to 2017 and 2025 were considered.

 Remaining Nonpoint sector (nonpt): Projection factors and percent reductions reflect comments received 

from the notices of data availability for the 2011 and 2018 emissions modeling platforms, along with 

emission reductions due to national and local rules/control programs. PFC projection factors reflecting 

impact of the final Mobile Source Air Toxics (MSAT2) rule. Upstream impacts from AEO fuel volume, 

including cellulosic ethanol plants, are reflected. For year 2017, due to the late change of modeling years 

from 2018 to 2017, most projection information was obtained for year 2018 and used as-is without 

interpolation to 2017.

 Residential Wood Combustion (rwc): Year 2017 and 2025 projection factors reflect assumed growth of 

wood burning appliances based on sales data, equipment replacement rates and change outs. These 
91

changes include the 2-stage NSPS for Residential Wood Heaters, resulting in growth in lower-emitting 

stoves and a reduction in higher emitting stoves.

 Locomotive, and non-Category 3 commercial marine sector (c1c2rail): Year 2017 and 2025 projection 

factors for Category 1 and Category 2 commercial marine and locomotives reflect final locomotivemarine controls.

 Category 3 commercial marine vessel (c3marine): Base-year 2011 emissions grown and controlled to 

2017 and 2025, incorporating controls based on Emissions Control Area (ECA) and International 

Marine Organization (IMO) global NOX and SO2 controls.

 Nonroad mobile sector (nonroad): Other than for California and Texas, this sector uses data from a run 

of NMIM that utilized NONROAD2008a, using future-year equipment population estimates and control 

programs to years 2018 and 2025. The year 2018 data were adjusted to 2017 using national adjustment 

factors. The inputs were either state-supplied as part of the 2011NEIv2 process or using national level 

inputs, with only minor updates for 2011NEIv2. Final controls from the final locomotive-marine and 

small spark ignition rules are included. California and Texas-specific data were provided by CARB and 

TCEQ, respectively.

 Onroad mobile (onroad): MOVES2014-based emissions factors for years 2018 and 2025 were 

developed using the same representative counties, state-supplied data, meteorology, and procedures that 

were used to produce the 2011 emission factors described in Section 2.3.1.The 2018 emissions were 

adjusted to 2017 using national adjustment factors. Data for California were provided by the California 

Air Resources Board. 

 Other point (othpt), nonpoint/nonroad (othar), onroad (othon): For Canada, year 2010 inventories were 

used for 2017 and 2025 because no future year projected inventories were available. Mexico inventory 

data were projected from year 2008 to 2018 (used for 2017) and 2025. C3 CMV data projected using 

the same methodology as the c3marine sector. Offshore oil platforms emission held constant at 2011 

levels.

Table 4-1 summarizes the growth and control assumptions by source type that were used to create the U.S. 2017

and 2025 base-case emissions from the 2011v6.2 base year inventories. The control, closures and projection 

packets (i.e., data sets) used to create the 2017 and 2025 future year base-case scenario inventories from the 

2011 base case are provided on the EMCH web site and are discussed in more detail in the sections listed in 

Table 4-1. These packets were processed through EPA’s Control Strategy Tool (CoST) to create future year 

emission inventories. CoST is described here: http://www.epa.gov/ttnecas1/cost.htm and discussed in context to 

this emissions modeling platform in Section 4.2.1. The last column in Table 4-1 indicates the order of the CoST 

strategy used for the source/packet type. For some sectors (e.g., ptnonipm), multiple CoST strategies are needed 

to produce the future year inventory because the same source category may be subject to multiple projection or 

control packets. For example, the “Loco-marine” projection factors are applied in a second control strategy for 

the ptnonipm sector, while for the c1c2rail sector, these same projection factors can be applied in the first (and 

only) control strategy. Thus, in Table 4-1, packets with a “1” in the CoST strategy column are applied in the 

first strategy, while packets with a “2” in the CoST strategy column are applied in a second strategy that is run 

on an intermediate inventory output from the first strategy.

The remainder of this section is organized by broad NEI sectors with further stratification by the types of 

packets (e.g., projection, control, closure packets) and whether emissions are projected via a stand-alone model 

(e.g., EGUs use the IPM model and onroad mobile uses MOVES), using CoST, or by other mechanisms. EGU 

projections are discussed in Section 4.1. All NEI non-EGU Point and Nonpoint sector projections (including all 

commercial marine vessels, locomotives and aircraft) are described in Section 4.2, along with some background 

on CoST. Onroad and nonroad mobile projections are discussed in Sections 4.3 and 4.4, respectively. Finally, 

projections for all “other” sources, primarily outside the U.S., are described in Section 4.5.
92

Table 4-1. Control strategies and growth assumptions for creating the 2017 and 2025 base-case emissions 

inventories from the 2011 base case

Description of growth, control, closure data, or, new 

inventory Sector(s) Packet Type

CAPs 

impacted Section(s)

CoST 

Strategy

Non-EGU Point (ptnonipm and pt_oilgas sectors) Controls and Growth Assumptions

Facility, unit and stack closures, primarily from the Emissions 

Inventory System (EIS)

ptnonipm, 

pt_oilgas CLOSURE All 4.2.2 1

"Loco-marine rule": Growth and control to years 2017 and 

2025 from Locomotives and Marine Compression-Ignition 

Engines Less than 30 Liters per Cylinder: March, 2008

ptnonipm, 

c1c2rail PROJECTION All 4.2.3.3

2,

1

Upstream RFS2/EISA/LDGHG impacts on gas distribution, 

pipelines and refineries to years 2018 and 2025

ptnonipm, 

pt_oilgas, 

nonpt PROJECTION All 4.2.3.5 2

AEO growth to 2018 and 2025: industrial sources, including 

oil and gas play-level projections

ptnonipm, 

pt_oilgas, 

nonpt, 

np_oilgas PROJECTION All 4.2.3.6 1

Aircraft growth via Itinerant (ITN) operations at airports to 

2017 and 2025 ptnonipm PROJECTION All 4.2.3.8 1

Corn Ethanol plants adjusted via AEO volume projections to 

2017 and 2025 ptnonipm PROJECTION All 4.2.3.10 1

NESHAP: Portland Cement census-division level based on 

Industrial Sector Integrated Solutions (ISIS) policy emissions 

to years 2018 and 2025. The ISIS results are from the ISISCement model runs for the NESHAP and NSPS analysis of 

August 2013 and include closures and growth.

ptnonipm, 

nonpt

PROJECTION 

& new 

inventories for 

new kilns All

4.2.3.9 & 

4.2.5.4

1 &

n/a

NESHAP: RICE (reciprocating internal combustion engines) 

with reconsideration amendments

ptnonipm, 

pt_oilgas, 

nonpt, 

np_oilgas CONTROL

CO, 

NOX, 

PM, SO2, 

VOC 4.2.4.2 1

NSPS: oil and gas pt_oilgas, 

np_oilgas CONTROL VOC 4.2.4.1 1

NSPS: RICE

ptnonipm, 

pt_oilgas, 

nonpt, 

np_oilgas CONTROL

CO, 

NOX, 

VOC 4.2.4.3 2

NSPS: Gas turbines ptnonipm, 

pt_oilgas CONTROL NOX 4.2.4.6 1

NSPS: Process heaters ptnonipm, 

pt_oilgas CONTROL NOX 4.2.4.7 1

Industrial/Commercial/Institutional Boiler MACT with 

Reconsideration Amendments + local programs

nonpt, 

ptnonipm, 

pt_oilgas CONTROL

CO, 

NOX, 

PM, SO2, 

VOC 4.2.4.4 1

State fuel sulfur content rules for fuel oil – via 2018 NODA 

comments, effective only in most northeast states

nonpt, 

ptnonipm, 

pt_oilgas CONTROL SO2 4.2.4.5 1

State comments: from previous platforms (including consent 

decrees) and 2018 NODA (search for ‘EPA-HQ-OAR-2013-

0809’ at regulations.gov)

nonpt, 

ptnonipm, 

pt_oilgas

PROJECTION 

&

CONTROL All

4.2.3.6, 

4.2.3.7, 

4.2.4.10 1

Commercial and Industrial Solid Waste Incineration (CISWI) 

revised NSPS ptnonipm CONTROL SO2 4.2.4.9 1

Arizona Regional haze controls ptnonipm CONTROL NOX,SO2 4.2.4.8 1

New biodiesel plants in year 2018 ptnonipm new inventory All 4.2.5.2 n/a

Nonpoint (afdust, ag, nonpt, np_oilgas and rwc sectors) Controls and Growth Assumptions

AEO-based VMT growth for paved and unpaved roads afdust PROJECTION PM 4.2.3.1 1
93

Description of growth, control, closure data, or, new 

inventory Sector(s) Packet Type

CAPs 

impacted Section(s)

CoST 

Strategy

Livestock emissions growth from year 2011 to years 2017 and 

2025 ag PROJECTION NH3 4.2.3.2 1

Upstream RFS2/EISA/LDGHG impacts on gas distribution, 

pipelines and refineries to years 2018 and 2025

ptnonipm, 

pt_oilgas, 

nonpt PROJECTION All 4.2.3.5 2

AEO growth to 2018 and 2025: industrial sources, including 

oil and gas play-level projections

ptnonipm, 

pt_oilgas, 

nonpt, 

np_oilgas PROJECTION All 4.2.3.6 1

NESHAP: RICE (reciprocating internal combustion engines) 

with reconsideration amendments

ptnonipm, 

pt_oilgas, 

nonpt, 

np_oilgas CONTROL

CO, 

NOX, 

PM, SO2, 

VOC 4.2.4.2 1

NSPS: oil and gas

pt_oilgas, 

np_oilgas CONTROL VOC 4.2.4.1 1

NSPS: RICE

ptnonipm, 

pt_oilgas, 

nonpt, 

np_oilgas CONTROL

CO, 

NOX, 

VOC 4.2.4.3 2

Residential wood combustion growth and change-outs from 

year 2011 to years 2018 and 2025 rwc PROJECTION All 4.2.3.11 1

Industrial/Commercial/Institutional Boiler MACT with 

Reconsideration Amendments + local programs

nonpt, 

ptnonipm, 

pt_oilgas CONTROL

CO, 

NOX, 

PM, SO2, 

VOC 4.2.4.4 1

State fuel sulfur content rules for fuel oil – via 2018 NODA 

comments, effective only in most northeast states

nonpt, 

ptnonipm, 

pt_oilgas CONTROL SO2 4.2.4.5 1

State comments: from previous platforms (including consent 

decrees) and 2018 NODA (search for ‘EPA-HQ-OAR-2013-

0809’ at regulations.gov)

nonpt, 

ptnonipm, 

pt_oilgas

PROJECTION 

&

CONTROL All

4.2.3.6, 

4.2.3.7, 

4.2.4.10 1

MSAT2 and RFS2 impacts with state comments on PFC 

(portable fuel container) growth and control from 2011 to years 

2018 and 2025 nonpt new inventory All 4.2.5.1 n/a

New cellulosic plants in year 2018 nonpt new inventory All 4.2.5.3 n/a

Onroad Mobile (onroad sector) Controls and Growth Assumptions

All national in-force regulations are modeled. The list includes recent key mobile source regulations but is not exhaustive.

National Onroad Rules:

All onroad control programs finalized as of the date of the 

model run, including most recently:

onroad n/a All 4.3 n/a

Tier-3 Vehicle Emissions and Fuel Standards Program: March, 

2014

2017 and Later Model Year Light-Duty Vehicle Greenhouse 

Gas Emissions and Corporate Average Fuel Economy 

Standards: October, 2012

Greenhouse Gas Emissions Standards and Fuel Efficiency 

Standards for Medium- and Heavy-Duty Engines and

Vehicles: September, 2011

Regulation of Fuels and Fuel Additives: Modifications to 

Renewable Fuel Standard Program (RFS2): December, 2010

Light-Duty Vehicle Greenhouse Gas Emission Standards and 

Corporate Average Fuel Economy Standards;

Final Rule for Model-Year 2012-2016: May, 2010

Final Mobile Source Air Toxics Rule (MSAT2): February, 

2007
94

Description of growth, control, closure data, or, new 

inventory Sector(s) Packet Type

CAPs 

impacted Section(s)

CoST 

Strategy

Local Onroad Programs:

California LEVIII Program

onroad n/a All 4.3 n/a

Ozone Transport Commission (OTC) LEV Program: 

January,1995

Inspection and Maintenance programs

Fuel programs (also affect gasoline nonroad equipment)

Stage II refueling control programs

Nonroad Mobile (c1c2rail, c3marine, nonroad sectors) Controls and Growth Assumptions

All national in-force regulations are modeled. The list includes recent key mobile source regulations but is not exhaustive.

National Nonroad Controls:

All nonroad control programs finalized as of the date of the 

model run, including most recently:

nonroad n/a All 4.4 n/a

Emissions Standards for New Nonroad Spark-Ignition Engines, 

Equipment, and Vessels: October, 2008

Growth and control to years 2017 and 2025 from Locomotives 

and Marine Compression-Ignition Engines Less than 30 Liters 

per Cylinder: March, 2008

Clean Air Nonroad Diesel Final Rule – Tier 4: May, 2004

Locomotives:

Growth and control to years 2017 and 2025 from Locomotives 

and Marine Compression-Ignition Engines Less than 30 Liters 

per Cylinder: March, 2008

c1c2rail, 

ptnonipm PROJECTION All 4.2.3.3

1,

2

Clean Air Nonroad Diesel Final Rule – Tier 4: May, 2004 c1c2rail n/a All 4.4 n/a

Commercial Marine:

Category 3 marine diesel engines Clean Air Act and 

International Maritime Organization standards: April, 2010 c3marine PROJECTION All 4.2.3.4 1

Growth and control to years 2017 and 2025 from Locomotives 

and Marine Compression-Ignition Engines Less than 30 Liters 

per Cylinder: March, 2008

c1c2rail, 

ptnonipm PROJECTION All 4.2.3.3

1, 

2

Clean Air Nonroad Diesel Final Rule – Tier 4: May, 2004 nonroad n/a All 4.4 n/a

4.1 EGU sector projections: ptegu

The future-year data for the ptegu sector used in the air quality modeling were created by the Integrated 

Planning Model (IPM) version 5.14 (v5.14). The IPM is a multiregional, dynamic, deterministic linear 

programming model of the U.S. electric power sector. IPM version 5.14 reflects state rules, consent decrees 

and announced shutdowns through December, 2014, in addition the NEEDS database was updated based on

comments received on the notices of data availability for the 2011 and 2018 emissions modeling platforms. IPM 

5.14 was updated from the previous version 5.13 and represents electricity demand projections for the Annual 

Energy Outlook (AEO) 2014. The scenario used for this modeling represents the implementation of the CrossState Air Pollution Rule (CSAPR), the Mercury and Air Toxics Standards (MATS), the final actions EPA has 

taken to implement the Regional Haze Rule, and the Cooling Water Intakes Rule and Combustion Residuals 

from Electric Utilities (CCR). More details on the IPM v5.14 base case scenarios can be found at 

http://epa.gov/powersectormodeling/psmodel514.html. 

Directly emitted PM emissions (i.e., PM2.5 and PM10) from the EGU sector are computed via a post processing 

routine that applies emission factors to the IPM-estimated fuel throughput based on fuel, configuration and 

controls to compute the filterable and condensable components of PM. This postprocessing step also apportions 
95

the regional emissions down to the unit-level emissions used for air quality modeling. A single IPM run was

postprocessed once for each output year to get results for 2018 and 2025. For information on how the 2018 

emissions were adjusted to represent 2017, see: 

http://www.epa.gov/airmarkets/documents/ipm/Adjusted2017.pdf. 

From the unit-level parsed file, a flat file is created that is used as the input to SMOKE and processed into the 

format needed by the air quality model. As part of the development of the flat file, a cross reference between the 

2011NEIv2 and IPM is used to populate stack parameters and other related information for matched sources. 

The flat file creation methodology is documented in the air quality modeling flat file documentation available 

here: http://www.epa.gov/airmarkets/documents/ipm/FlatFile_Methodology.pdf. The cross reference is 

available from http://www.epa.gov/airmarkets/documents/ipm/FlatFile_Inputs.xls, with additional information 

available in ftp://ftp.epa.gov/EmisInventory/2011v6/v2platform/reports/ 

ipm_to_flat_file_xref_2011NEIv2_IPM5.14_20150113.xlsx. The emissions in the flat file created based on the 

IPM outputs are temporalized into the hourly emissions needed by the air quality model as described in Section 

3.3.2.

4.2 Non-EGU Point and NEI Nonpoint sector projections: afdust, ag, c1c2rail, 

c3marine, nonpt, np_oilgas, ptnonipm, pt_oilgas, rwc

To project all U.S. non-EGU stationary sources, facility/unit closures information, and growth (PROJECTION) 

factors and/or controls were applied to certain categories within the afdust, ag, c1c2rail, c3marine, nonpt, 

np_oilgas, ptnonipm, pt_oilgas and rwc platform sectors. Some facility or sub-facility-level closure information 

was also applied to the point sources. There are also a handful of situations where new inventories were 

generated for sources that did not exist in the 2011 NEI (e.g., biodiesel and cellulosic plants, yet-to-be 

constructed cement kilns). This subsection provides details on the data and projection methods used for these 

sectors. 

In recent platforms, EPA has assumed that emissions growth for most industrial sources did not track with 

economic growth for most stationary non-IPM sources (EPA, 2006b). This “no-growth” assumption was based 

on an examination of historical emissions and economic data. Recently however, EPA has received growth (and 

control) data from numerous states and regional planning organizations for many industrial sources, including 

the rapidly-changing oil and gas sector. EPA provided a Notice of Data Availability for the 2011v6.0 emissions 

modeling platform and projected 2018 inventory in January, 2014 (docket EPA-HQ-OAR-2013-0809). EPA 

requested comment on the future year growth and control assumptions used to develop the 2018 inventories. 

One of the most frequent comments EPA received was to use the growth factors information that numerous 

states either provided or deferred to growth factors provided by broader region-level efforts. In an attempt to 

make the projections approach as consistent as possible across all states, EPA decided to expand this effort to 

all states for some of the most-significant industrial sources (see Section 4.2.3.6). 

Because much of the projections and controls data are developed independently from how EPA defines its 

emissions modeling sectors, this section is organized primarily by the type of projections data, with secondary 

consideration given to the emissions modeling sector. For example, industrial source growth factors are 

applicable to 4 emissions modeling sectors. The rest of this section is organized in the order that the EPA uses 

CoST in combination with other methods to produce future year inventories: 1) for point sources, apply plant

(facility or sub-facility-level) closure information via CoST, 2) apply all PROJECTION packets via CoST

(multiplicative factors that could cause increases or decreases), 3) apply all percent reduction-based CONTROL 

packets via CoST, and 4) append all other future-year inventories not generated via CoST. This organization 

allows consolidation of the discussion of the emissions categories that are contained in multiple sectors, because 

the data and approaches used across the sectors are consistent and do not need to be repeated. Sector names 

associated with the CoST packets are provided in parentheses.
96

4.2.1 CoST Background: Used for NEI non-EGU Point and Nonpoint sectors

CoST is used to apply most non-EGU projection/growth factors, controls and facility/unit/stack-level closures 

to the 2011 NEI-based emissions modeling inventories to create inventories for years 2017 and 2025 for the 

following sectors: afdust, ag, c1c2rail, c3marine, nonpt, np_oilgas, ptnonipm, pt_oilgas and rwc. The CoST 

training manual is available at: http://www.cmascenter.org/help/model_docs/cost/2.5/CoST_UsersGuide_2012-

08-01_Final.pdf. The CoST development document, which is a more thorough albeit dated document of how to 

build and format CoST input files (packets) is available at: 

http://www.epa.gov/ttnecas1/models/CoST_Development%20Document_2010-06-09.pdf. 

CoST allows the user to apply projection (growth) factors, controls and closures at various geographic and 

inventory key field resolutions. Each of these CoST datasets, also called “packets” or “programs”, provides the 

user with the ability to perform numerous quality assurance assessments as well as create SMOKE-ready future 

year inventories. Future year inventories are created for each emissions modeling sector via a CoST “strategy” 

and each strategy includes all 2011 inventories and applicable CoST packets. For reasons discussed later, some 

emissions modeling sectors require multiple CoST strategies to account for the compounding of control 

programs that impact the same type of sources. There are also available linkages to existing and user-defined 

control measures databases and it is up to the user to determine how control strategies are developed and 

applied. EPA typically creates individual CoST packets that represent specific intended purposes. For example, 

aircraft projections for airports are in a separate PROJECTION packet from residential wood combustion 

sales/appliance turnover-based projections. CoST uses three packet types as described below:

1. CLOSURE: Applied first in CoST. This packet can be used to zero-out (close) point source emissions at 

resolutions as broad as a facility to as specific as a stack. EPA uses these types of packets for known 

post-2011 controls as well as information on closures provided by states on specific facilities, units or 

stacks. This packet type is only used in the ptnonipm and pt_oilgas sectors.

2. PROJECTION: This packet allows the user to increase or decrease emissions for virtually any 

geographic and/or inventory source level. Projection factors are applied as multiplicative factors to the 

2011 emissions inventories prior to the application of any possible subsequent CONTROLs. A 

PROJECTION packet is necessary whenever emissions increase from 2011 and is also desirable when 

information is based more on activity assumptions rather than known control measures. EPA uses

PROJECTION packet(s) in every non-EGU modeling sector.

3. CONTROL: These packets are applied after any/all CLOSURE and PROJECTION packet entries. The 

user has similar level of control as PROJECTION packets regarding specificity of geographic and/or 

inventory source level application. Control factors are expressed as a percent reduction (0 to 100) and 

can be applied in addition to any pre-existing inventory control, or as a replacement control where 

inventory controls are first backed out prior to the application of a more-stringent replacement control. 

All of these packets are stored as data sets within the Emissions Modeling Framework (EMF) and use commadelimited formats. As mentioned above, CoST first applies any/all CLOSURE information for point sources, 

then applies PROJECTION packet information, followed by CONTROL packets. A hierarchy is used by CoST 

to separately apply PROJECTION and CONTROL packets. In short, in a separate process for PROJECTION 

and CONTROL packets, more specific information is applied in lieu of less-specific information in ANY other 

packets. For example, a facility-level PROJECTION factor will be replaced by a unit-level, or facility and 

pollutant-level PROJECTION factor. It is important to note that this hierarchy does not apply between packet 

types; for example, CONTROL packet entries are applied irrespective of PROJECTION packet hierarchies. A 

more specific example: a state/SCC-level PROJECTION factor will be applied before a stack/pollutant-level 

CONTROL factor that impacts the same inventory record. However, an inventory source that is subject to a 

CLOSURE packet record is removed from consideration of subsequent PROJECTION and CONTROL packets. 
97

The implication for this hierarchy and intra-packet independence is important to understand and quality assure 

when creating future year strategies. For example, with consent decrees, settlements and state comments, the 

goal is typically to achieve a targeted reduction (from the 2011NEI) or a targeted future-year emissions value.

Therefore, as encountered with this 2017 base case, consent decrees and state comments for specific cement 

kilns (expressed as CONTROL packet entries), needed to be applied instead of (not in addition to) the more 

general approach of the PROJECTION packet entries for cement manufacturing. By processing CoST control 

strategies with PROJECTION and CONTROL packets separated by the type of broad measure/program, it is 

possible to show actual changes from the 2011 inventory to the 2017 and 2025 inventory due to each packet.

Ultimately, CoST concatenates all PROJECTION packets into one PROJECTION dataset and uses a hierarchal 

matching approach to assign PROJECTION factors to the inventory. For example, a packet entry with 

Ranking=1 will supersede all other potential inventory matches from other packets. CoST then computes the 

projected emissions from all PROJECTION packet matches and then performs a similar routine for all 

CONTROL packets. Therefore, when summarizing “emissions reduced” from CONTROL packets, it is 

important to note that these reductions are not relative to the 2011 inventory, but rather, to the intermediate 

inventory after application of any/all PROJECTION packet matches (and CLOSURES). A subset of the more 

than 70 hierarchy options is shown in Table 4-2, although the fields in Table 4-2 are not necessarily named the 

same in CoST, but rather are similar to those in the SMOKE FF10 inventories. For example, “REGION_CD” is 

the county-state-county FIPS code (e.g., Harris county Texas is 48201) and “STATE” would be the 2-digit state 

FIPS code with three trailing zeroes (e.g., Texas is 48000).

Table 4-2. Subset of CoST Packet Matching Hierarchy

Rank Matching Hierarchy Inventory Type

1 REGION_CD, FACILITY_ID, UNIT_ID, REL_POINT_ID, PROCESS_ID, SCC, POLL point

2 REGION_CD, FACILITY_ID, UNIT_ID, REL_POINT_ID, PROCESS_ID, POLL point

3 REGION_CD, FACILITY_ID, UNIT_ID, REL_POINT_ID, SCC, POLL point

4 REGION_CD, FACILITY_ID, UNIT_ID, REL_POINT_ID, POLL point

5 REGION_CD, FACILITY_ID, UNIT_ID, SCC, POLL point

6 REGION_CD, FACILITY_ID, UNIT_ID, POLL point

7 REGION_CD, FACILITY_ID, SCC, POLL point

8 REGION_CD, FACILITY_ID, POLL point

9 REGION_CD, FACILITY_ID, UNIT_ID, REL_POINT_ID, PROCESS_ID point

10 REGION_CD, FACILITY_ID, UNIT_ID, REL_POINT_ID point

11 REGION_CD, FACILITY_ID, UNIT_ID point

12 REGION_CD, FACILITY_ID point

13 REGION_CD, NAICS, SCC, POLL point, nonpoint

14 REGION_CD, NAICS, POLL point, nonpoint

15 STATE, NAICS, POLL point, nonpoint

16 REGION_CD, NAICS point, nonpoint

17 NAICS point, nonpoint

18 REGION_CD, SCC, POLL point, nonpoint

19 STATE, SCC, POLL point, nonpoint

20 SCC, POLL point, nonpoint

21 REGION_CD, SCC point, nonpoint

22 STATE, SCC point, nonpoint

23 SCC point, nonpoint

24 REGION_CD, POLL point, nonpoint

25 REGION_CD point, nonpoint

26 STATE, POLL point, nonpoint
98

Rank Matching Hierarchy Inventory Type

27 STATE point, nonpoint

28 POLL point, nonpoint

The contents of the controls, local adjustments and closures for the 2017 and 2025 base cases are described in 

the following subsections. Year-specific projection factors (PROJECTION packets) for years 2017 and 2025 

were used for creating the 2017 and 2025 base cases unless noted otherwise. The contents of a few of these 

projection packets (and control reductions) are provided in the following subsections where feasible. However, 

most sectors used growth or control factors that varied geographically and their contents could not be provided 

in the following sections (e.g., facilities and units subject to the Boiler MACT reconsideration has thousands of 

records). The remainder of Section 4.2 is divided into several subsections that are summarized in Table 4-3. 

Note that future year inventories were used rather than projection or control packets for some sources.

Table 4-3. Summary of non-EGU stationary projections subsections

Subsection Title Sector(s) Brief Description

4.2.2 CoST Plant CLOSURE 

packet

ptnonipm, 

pt_oilgas

All facility/unit/stack closures information, 

primarily from Emissions Inventory System (EIS), 

but also includes information from states and other 

organizations.

4.2.3 CoST PROJECTION 

packets

All Introduces and summarizes national impacts of all 

CoST PROJECTION packets to years 2017 and 

2025.

4.2.3.1 Paved and unpaved roads 

VMT growth

Afdust PROJECTION packet: county-level resolution, 

based on VMT growth.

4.2.3.2 Livestock population 

growth

Ag PROJECTION packet: national, by-animal type 

resolution, based on animal population projections.

4.2.3.3 Locomotives and Category 

1 & 2 commercial marine 

vessels

c1c2rail, 

ptnonipm

PROJECTION packet: national, by-equipment type 

and pollutant, based on cumulative growth and 

control impacts from rulemaking.

4.2.3.4 Category 3 commercial 

marine vessels

c3marine PROJECTION packet: region-level by-pollutant, 

based on cumulative growth and control impacts 

from rulemaking.

4.2.3.5 OTAQ upstream 

distribution, pipelines and 

refineries

nonpt, 

ptnonipm, 

pt_oilgas

PROJECTION packet: national, by-broad source 

category, based on upstream impacts from mobile 

source rulemakings.

4.2.3.6 Oil and gas and industrial 

source growth

nonpt, 

np_oilgas, 

ptnonipm, 

pt_oilgas

Several PROJECTION packets: varying geographic 

resolutions from state, county, to oil/gas play-level 

and by-process/fuel-type applications. Data derived 

from AEO2014 with several modifications.

4.2.3.7 Data from comments on 

previous platforms

nonpt, 

ptnonipm

Several PROJECTION packets: varying geographic 

resolutions and by-process/fuel-type applications. 

Data derived from various sources in response to the 

previous (2011v6.0) version of the emissions 

modeling platform.

4.2.3.8 Aircraft ptnonipm PROJECTION packet: by-airport for all direct 

matches to FAA Terminal Area Forecast data, with 

state-level factors for non-matching NEI airports.
99

Subsection Title Sector(s) Brief Description

4.2.3.9 Cement manufacturing ptnonipm PROJECTION packet: by-kiln projections based on 

Industrial Sectors Integrated Solutions (ISIS) model

of demand growth and Portland Cement NESHAP.

4.2.3.10 Corn ethanol plants ptnonipm PROJECTION packet: national, based on 2014 

AEO renewable fuel production forecast.

4.2.3.11 Residential wood 

combustion

rwc PROJECTION packet: national with exceptions, 

based on appliance type sales growth estimates and 

retirement assumptions and impacts of recent NSPS.

4.2.4 CoST CONTROL packets nonpt, 

np_oilgas, 

ptnonipm, 

pt_oilgas

Introduces and summarizes national impacts of all 

CoST CONTROL packets to years 2017 and 2025.

4.2.4.1 Oil and gas NSPS np_oilgas, 

pt_oilgas

CONTROL packet: national, oil and gas NSPS 

impacting VOC only for some activities.

4.2.4.2 RICE NESHAP nonpt, 

np_oilgas, 

ptnonipm, 

pt_oilgas

CONTROL packet: national, reflects NESHAP 

amendments on compression and spark ignition 

stationary reciprocating internal combustion engines 

(RICE).

4.2.4.3 RICE NSPS nonpt, 

np_oilgas, 

ptnonipm, 

pt_oilgas

CONTROL packet: state and county-level new 

source RICE controls, whose reductions bydefinition, are a function of growth factors and also 

equipment retirement assumptions.

4.2.4.4 ICI Boilers nonpt, 

ptnonipm, 

pt_oilgas

CONTROL packet: by-fuel, and for point sources, 

by-facility-type controls impacting Industrial and 

Commercial/Institutional boilers from rulemaking 

and state-provided information.

4.2.4.5 Fuel sulfur rules nonpt, 

ptnonipm, 

pt_oilgas

CONTROL packet: state and MSA-level fuel sulfur 

control programs provided by several northeastern 

U.S. states.

4.2.4.6 Natural gas turbines NSPS ptnonipm, 

pt_oilgas

CONTROL packet: state and county-level new 

source natural gas turbine controls, whose 

reductions by-definition, are a function of growth 

factors and also equipment retirement assumptions.

4.2.4.7 Process heaters NSPS ptnonipm, 

pt_oilgas

CONTROL packet: state and county-level new 

source process heaters controls, whose reductions 

by-definition, are a function of growth factors and 

also equipment retirement assumptions.

4.2.4.8 Arizona Regional Haze ptnonipm CONTROL packet: Regional haze controls for 

Arizona provided by Region 9.

4.2.4.9 CISWI ptnonipm CONTROL packet reflecting EPA solid waste rule 

cobenefits.

4.2.4.10 Data from comments on 

previous platforms

nonpt, 

ptnonipm, 

pt_oilgas

CONTROL packets for all other programs, 

including Regional Haze, consent 

decrees/settlements, and other information from 

states/other agencies in prior platforms.

4.2.5 Stand-alone future year 

inventories

nonpt, 

ptnonipm

Introduction to future-year inventories not generated 

via CoST strategies/packets.
100

Subsection Title Sector(s) Brief Description

4.2.5.1 Portable fuel containers nonpt Reflects impacts of Mobile Source Air Toxics

(MSAT2) on PFCs.

4.2.5.2 Biodiesel plants ptnonipm Year 2018 new biodiesel plants provided by OTAQ 

reflecting planned sited-plants production volumes.

4.2.5.3 Cellulosic plants nonpt Year 2018 new cellulosic ethanol plants based on 

cellulosic biofuel refinery siting provided by OTAQ 

and 2018 NODA.

4.2.5.4 New cement plants nonpt, 

ptnonipm

Year 2018 and 2025 ISIS policy case-derived new 

cement kilns, permitted (point) and model-generated 

based on shifted capacity from some closed units to 

open units (nonpt)

4.2.2 CoST Plant CLOSURE packet (ptnonipm, pt_oilgas)

Packet: “CLOSURES_2011v6.2_v3_23feb2015.txt”

This packet contains facility, unit and stack-level closure information derived from the following sources:

1. Emissions Inventory System (EIS) facilities report from December 20, 2014 with closure status equal to 

“PS” (permanent shutdown)

2. EIS unit-level report from November 29, 2014 with status = ‘PS’

3. Concatenation of all 2011v6.0 closures information; see Section 4.2.11.3 at: 

http://www.epa.gov/ttn/chief/emch/2011v6/outreach/2011v6_2018base_EmisMod_TSD_26feb2014.pdf

4. Comments from states and regional planning organizations.

The EIS sources, accessible at http://www.epa.gov/ttnchie1/eis/gateway/, report post-2011 permanent 

facility/unit shutdowns through the date of the EIS report, assuming reporting agencies provided the 

information. The 2011v6.0 closure information is from a concatenation of previous facility and unit-level 

closure information used in the 2008 NEI-based emissions modeling platform 

(http://epa.gov/ttn/chief/emch/2007v5/2007v5_2020base_EmisMod_TSD_13dec2012.pdf). In addition, 

comments on the 2011v6.0 emissions modeling platform received by states and other agencies indicated the 

removal of some closure information (keep open). Ultimately, all data were updated to match the SMOKE FF10 

inventory key fields, with all duplicates removed, and a single CoST packet was generated. The cumulative 

reductions in emissions from this packet are shown in Table 4-4. Note that these reductions are the same for 

both 2017 and 2025 future years.

Table 4-4. Reductions from all facility/unit/stack-level closures by modeling sector

Pollutant ptnonipm pt_oilgas Cumulative

CO 7,542 1,473 9,015

NH3 727 0 727

NOX 12,250 2,300 14,550

PM10 4,940 108 5,048

PM2.5 3,882 104 3,986

SO2 39,491 184 39,675

VOC 12,695 641 13,336
101

4.2.3 CoST PROJECTION packets (afdust, ag, c1c2rail, c3marine, nonpt, np_oilgas, 

ptnonipm, pt_oilgas, rwc)

As previously discussed, for point inventories, after application of any/all CLOSURE packet information, the 

next step in running a CoST control strategy is the application of all CoST PROJECTION packets. Regardless 

of inventory type (point or nonpoint), the PROJECTION packets applied prior to the CoST packets. For several 

emissions modeling sectors (afdust, ag, c1c2rail, c3marine and rwc), there is only one CoST PROJECTION 

packet. For all other sectors, there are several different sources of PROJECTIONS data and therefore there are 

multiple PROJECTION packets that are concatenated and quality-assured for duplicates and applicability to the 

inventories in the CoST strategy. The PROJECTION (and CONTROL) packets were separated into a few “key” 

control program types to allow for quick summaries of these distinct control programs. The remainder of this 

section is broken out by CoST packet, with the exception of discussion of the various packets used for oil and 

gas and industrial source projections; these packets are a mix of different sources of data that targeted similar 

sources.

4.2.3.1 Paved and unpaved roads VMT growth (afdust)

Packet:

For 2017: “PROJECTION_2011_2017_AFDUST_VMT_2011v6.2_10mar2015.txt”

For 2025: “PROJECTION_2011_2025_AFDUST_VMT_2011v6.2_10mar2015.txt”

We received comments from the 2018 NODA (search for ‘EPA-HQ-OAR-2013-0809’ at www.regulations.gov) 

suggesting we grow emissions from paved and unpaved road dust as a function of vehicle miles traveled 

(VMT). The future year VMT used to project this sector was consistent with the VMT used for the onroad 

mobile source modeling as described in Section 4.3.1.1. The resulting national sector-total increase in PM2.5 

emissions are provided in Table 4-5. Note that this packet does not impact any other sources of fugitive dust 

emissions in the afdust sector (e.g., no impact on construction dust, mining and quarrying, etc.).

Table 4-5. Increase in total afdust PM2.5 emissions from VMT projections

2011 Emissions 2017 Emissions 2025 Emissions % Increase 2017 % Increase 2025

2,510,307 2,623,572 2,792,127 4.5% 11.2%

4.2.3.2 Livestock population growth (ag)

Packet:

For 2017: “PROJECTION_2011_2017_ag_2011v6.2_no_RFS2_04feb2015.txt”

For 2025: “PROJECTION_2011_2025_ag_2011v6.2_no_RFS2_23jan2015.txt”

EPA estimated animal population growth in ammonia (NH3) emissions from livestock in the ag sector. Except 

for dairy cows and turkey production, the animal projection factors are derived from national-level animal 

population projections from the U.S. Department of Agriculture (USDA) and the Food and Agriculture Policy 

and Research Institute (FAPRI). This methodology was initiated in 2005 for the 2005 NEI, but was updated on 

July 24, 2012 in support of the 2007v5 platform (EPA, 2012). For dairy cows, EPA assumed that there would 

be no growth in emissions based on little change in U.S. dairy cow populations from year 2011 through 2025 

according to linear regression analyses of the FAPRI projections. This assumption was based on an analysis of 

historical trends in the number of such animals compared to production rates. Although productions rates have 

increased, the number of animals has declined. Based on this analysis, EPA concluded that production forecasts 

do not provide representative estimates of the future number of cows and turkeys; therefore, these forecasts 

were not used for estimating future-year emissions from these animals. In particular, the dairy cow population 
102

is projected to decrease in the future as it has for the past few decades; however, milk production will be 

increasing over the same period. Note that the ammonia emissions from dairies are not directly related to animal 

population but also nitrogen excretion. With the cow numbers going down and the production going up the 

excretion value will change, but no change was assumed because a quantitative estimate was not available.

Appendix C provides the animal population data and regression curves used to derive the growth factors. 

The projection factors by animal category and ag sector total impacts are provided in Table 4-5. As discussed 

below, dairy cows are assumed to have no growth in animal population, and therefore the projection factor for 

these animals is 1.0 (no growth). Impacts from the renewable fuels mandate are not included in projections for 

this sector.

Table 4-5. NH3 projection factors and total impacts to years 2017 and 2025 for animal operations

Animal Category 2017 Projection Factors

& Total Emissions

2025 Projection Factors

& Total Emissions

Dairy Cow 1.0 1.0

Beef 0.988 0.974

Pork 1.069 1.118

Broilers 1.087 1.130

Turkeys 0.947 0.921

Layers 1.063 1.094

Poultry Average 1.057 1.085

Overall Average 1.026 1.041

Total Emissions 3,584,419 3,617,575

% Increase from 2011 1.8% 2.7%

4.2.3.3 Locomotives and Category 1 & 2 commercial marine vessels (c1c2rail, ptnonipm)

Packet:

For 2017: “PROJECTION_2011v6.2_2017_c1c2rail_BASE_06feb2015.txt”

For 2025: “PROJECTION_2011v6.2_2025_c1c2rail_BASE_06feb2015.txt”

There are two components used to create projection factors for years 2017 and 2025. The first component of the 

future year c1c2rail inventory is the non-California data projected from the 2011 base case. The second 

component is the CARB-supplied year 2011, 2017 and 2025 data for California. 

For all states outside of California, national projection factors by SCC and pollutant between 2011 and future 

years reflect the May 2004 “Tier 4 emissions standards and fuel requirements” 

(http://www.epa.gov/otaq/documents/nonroad-diesel/420r04007.pdf) as well as the March 2008 “Final 

locomotive-marine rule” controls (http://www.epa.gov/otaq/regs/nonroad/420f08004.pdf) . The future-year 

c1c2rail emissions account for increased fuel consumption based on Energy Information Administration (EIA) 

fuel consumption projections for freight, and emissions reductions resulting from emissions standards from the 

Final Locomotive-Marine rule (EPA, 2009d).30 For locomotives, EPA applied HAP factors for VOC HAPs by 

using VOC projection factors to obtain 1,3-butadiene, acetaldehyde, acrolein, benzene, and formaldehyde. 

Similar to locomotives, C1/C2 VOC HAPs were projected based on the VOC factor. C1/C2 diesel emissions 

were projected based on the Final Locomotive Marine rule national-level factors. These non-California 

projection ratios are provided in Table 4-6. Note that projection factors for “...Yard Locomotives” 

 

30 This rule lowered diesel sulfur content and tightened emission standards for existing and new locomotives and marine diesel 

emissions to lower future-year PM, SO2, and NOX, and is documented at: http://www.epa.gov/otaq/marine.htm#2008final.
103

(SCC=2285002010) are applied to the ptnonipm (point inventory) “yard locomotives” (SCC=28500201) 

reported by a couple of states in the 2011 NEI.

Table 4-6. Non-California projection factors for locomotives and Category 1 and Category 2 Commercial 

Marine Vessel Emissions

SCC Description Poll 2017

Factor

2025 

Factor

2280002XXX Marine Vessels, Commercial; Diesel; Underway & port emissions CO 0.957 0.955

2280002XXX Marine Vessels, Commercial; Diesel; Underway & port emissions NOX 0.801 0.537

2280002XXX Marine Vessels, Commercial; Diesel; Underway & port emissions PM 0.712 0.491

2280002XXX Marine Vessels, Commercial; Diesel; Underway & port emissions SO2 0.157 0.069

2280002XXX Marine Vessels, Commercial; Diesel; Underway & port emissions VOC 0.814 0.523

2285002006 Railroad Equipment; Diesel; Line Haul Locomotives: Class I Operations CO 1.100 1.249

2285002006 Railroad Equipment; Diesel; Line Haul Locomotives: Class I Operations NOX 0.840 0.621

2285002006 Railroad Equipment; Diesel; Line Haul Locomotives: Class I Operations PM 0.716 0.457

2285002006 Railroad Equipment; Diesel; Line Haul Locomotives: Class I Operations SO2 0.031 0.036

2285002006 Railroad Equipment; Diesel; Line Haul Locomotives: Class I Operations VOC 0.656 0.430

2285002007 Railroad Equipment; Diesel; Line Haul Locomotives: Class II / III Operations CO 1.100 1.249

2285002007 Railroad Equipment; Diesel; Line Haul Locomotives: Class II / III Operations NOX 1.056 1.065

2285002007 Railroad Equipment; Diesel; Line Haul Locomotives: Class II / III Operations PM 1.025 1.012

2285002007 Railroad Equipment; Diesel; Line Haul Locomotives: Class II / III Operations SO2 0.031 0.036

2285002007 Railroad Equipment; Diesel; Line Haul Locomotives: Class II / III Operations VOC 1.100 1.249

2285002008 Railroad Equipment; Diesel; Line Haul Locomotives: Passenger Trains (Amtrak) CO 1.049 1.118

2285002008 Railroad Equipment; Diesel; Line Haul Locomotives: Passenger Trains (Amtrak) NOX 0.703 0.458

2285002008 Railroad Equipment; Diesel; Line Haul Locomotives: Passenger Trains (Amtrak) PM 0.661 0.337

2285002008 Railroad Equipment; Diesel; Line Haul Locomotives: Passenger Trains (Amtrak) SO2 0.030 0.033

2285002008 Railroad Equipment; Diesel; Line Haul Locomotives: Passenger Trains (Amtrak) VOC 0.600 0.275

2285002009 Railroad Equipment; Diesel; Line Haul Locomotives: Commuter Lines CO 1.049 1.118

2285002009 Railroad Equipment; Diesel; Line Haul Locomotives: Commuter Lines NOX 0.703 0.458

2285002009 Railroad Equipment; Diesel; Line Haul Locomotives: Commuter Lines PM 0.661 0.337

2285002009 Railroad Equipment; Diesel; Line Haul Locomotives: Commuter Lines SO2 0.030 0.033

2285002009 Railroad Equipment; Diesel; Line Haul Locomotives: Commuter Lines VOC 0.600 0.275

2285002010 Railroad Equipment; Diesel; Yard Locomotives CO 1.100 1.249

2285002010 Railroad Equipment; Diesel; Yard Locomotives NOX 0.980 0.837

2285002010 Railroad Equipment; Diesel; Yard Locomotives PM 0.951 0.810

2285002010 Railroad Equipment; Diesel; Yard Locomotives SO2 0.032 0.036

2285002010 Railroad Equipment; Diesel; Yard Locomotives VOC 0.950 0.767

For California projections, CARB provided to EPA the locomotive, and Category 1 and 2 commercial marine 

emissions used to reflect years 2011, 2017 and year 2025. These CARB inventories included nonroad rules 

reflected in the December 2010 Rulemaking Inventory 

(http://www.arb.ca.gov/regact/2010/offroadlsi10/offroadisor.pdf), those in the March 2011 Rule Inventory, the 

Off-Road Construction Rule Inventory for “In-Use Diesel”, cargo handling equipment rules in place as of 2011 

(see http://www.arb.ca.gov/ports/cargo/cargo.htm), and the 2007 and 2010 regulations to reduce emissions 

diesel engines on commercial harbor craft operated within California waters and 24 nautical miles of the 

California baseline. 

The California C1/C2 CMV emissions were obtained from the CARB nonroad mobile dataset 

“ARMJ_RF#2002_ANNUAL_MOBILE.txt”. These emissions were developed using Version 1 of the CEPAM 

which supports various California off-road regulations. The locomotive emissions were obtained from the 

CARB trains dataset “ARMJ_RF#2002_ANNUAL_TRAINS.txt”. Documentation of the CARB off-road

methodology, including c1c2rail sector data, is provided here: 

http://www.arb.ca.gov/msei/categories.htm#offroad_motor_vehicles. EPA converted the CARB inventory TOG 
104

to VOC by dividing the inventory TOG by the available VOC-to-TOG speciation factor. The CARB year-2011 

inventory (provided with the 2017 and 2025 emissions) did not match the CARB-submitted inventory in 

Version 2 of the 2011 NEI; therefore, we used the CARB 2011/2017/2025 data to compute projection ratios that 

were then applied to the 2011 emissions modeling platform (2011NEIv2). California projection factors were 

“capped” at 2.5; we found that those counties/SCCs/pollutants with projection factors greater than 2 (100% 

increase) were all under 100 tons for any given pollutant. The California projection factors are county-level and 

therefore not provided here.

The non-California projection factors were applied to all “offshore” c1c2 CMV emissions. These offshore 

emissions, in the 2011 NEI, start at the end of state waters, and extend out to the Economic Exclusion Zone 

(EEZ). A summary of the national impact for US (including California) and offshore c1c2rail sector emissions 

are provided in Table 4-7.

Table 4-7. Difference in c1c2rail sector emissions between 2011 and future years

Region

Pollutant 2011 2017 2025

Difference 

2017 - 2011

Difference 

2025 - 2011

U.S. CO 185,074 198,436 219,537 13,362 34,463

U.S. NOX 1,097,162 933,414 691,890 -163,749 -405,273

U.S. PM10 36,079 26,484 18,034 -9,594 -18,045

U.S. PM2.5 33,713 24,741 16,850 -8,972 -16,863

U.S. SO2 12,869 1,202 905 -11,667 -11,963

U.S. VOC 48,810 34,956 24,777 -13,854 -24,032

Offshore CO 66,395 63,515 63,390 -2,880 -3,005

Offshore NOX 326,631 261,637 175,482 -64,994 -151,149

Offshore PM10 10,795 7,687 5,297 -3,108 -5,499

Offshore PM2.5 10,471 7,457 5,138 -3,015 -5,334

Offshore SO2 4,014 632 278 -3,382 -3,736

Offshore VOC 7,472 6,080 3,910 -1,392 -3,562

4.2.3.4 Category 3 commercial marine vessels (c3marine, othpt)

Packet:

For 2017: “PROJECTION_2011_2017_C3_CMV_ECA_IMO_2011v6.2_10feb2015.txt”

For 2025: “PROJECTION_2011_2025_C3_CMV_ECA_IMO_2011v6.2_10feb2015.txt

As discussed in Section 2.4.2, the EPA estimates for C3 CMV emissions data were developed for year 2002 and 

projected to year 2011 for the 2011 base case and used where states did not submit data to Version 2 of the 2011 

NEI. Pollutant and geographic-specific projection factors to year 2011 were applied, along with projection 

factors to years 2017 and 2025 that reflect assumed growth and final ECA-IMO controls. These emissions 

estimates reflect EPA’s coordinated strategy for large marine vessels. More information on EPA’s coordinated 

strategy for large marine vessels can be found in our Category 3 Marine Diesel Engines and Fuels regulation 

published in April 2010. That rule, as well as information about the North American and U.S. Caribbean Sea 

ECAs, designated by amendment to MARPOL Annex VI, can be found here: 

http://www.epa.gov/otaq/oceanvessels.htm.

Projection factors for creating the year 2017 and 2025 c3marine inventories from the 2011 base case are 

provided in Table 4-8. Background on the region and Exclusive Economic Zone (EEZ) FIPS is provided in the 

discussion on the c3marine inventory for 2011 –Section 2.4.2. For example, Washington state emissions are 

grown the same as all North Pacific offshore emissions.
105

Table 4-8. Growth factors to project the 2011 ECA-IMO inventory to 2017 and 2025

Region

EEZ 

(Offshore) 

FIPS Year

2017 and 2025 Adjustments Relative to 2011

CO NOX PM10 PM25 SO2 VOC

North Pacific (NP) 85001 2017 1.215 0.989 0.168 0.167 0.047 1.215

2025 1.575 0.798 0.217 0.216 0.061 1.575

South Pacific (SP) 85002 2017 1.350 1.084 0.187 0.185 0.053 1.351

2025 2.027 0.909 0.285 0.283 0.081 2.028

East Coast (EC) 85004 2017 1.302 1.039 0.177 0.176 0.047 1.302

2025 1.852 0.838 0.252 0.250 0.066 1.852

Gulf Coast (GC) 85003 2017 1.187 0.947 0.162 0.161 0.042 1.187

2025 1.492 0.679 0.204 0.202 0.053 1.492

Great Lakes (GL) n/a 2017 1.106 0.972 0.146 0.145 0.039 1.106

2025 1.266 0.940 0.168 0.166 0.045 1.266

Outside ECA 98001 2017 1.298 1.182 1.298 1.298 1.298 1.298

2025 1.858 1.463 0.409 0.405 0.337 1.858

As discussed in Section 2.4.2, emissions outside the 3 to 10 mile coastal boundary but within the approximately 

200 nm EEZ boundaries were projected to years 2017 and 2025 using the same regional adjustment factors as 

the U.S. emissions; however, the FIPS codes were assigned as “EEZ” FIPS and these emissions are processed in 

the “othpt” sector (see Section 2.5.1 and 4.5.1). Note that state boundaries in the Great Lakes are an exception, 

extending through the middle of each lake such that all emissions in the Great Lakes are assigned to a U.S. 

county or Ontario. The classification of emissions to U.S. and Canadian FIPS codes is needed to avoid doublecounting of Canadian-provided C3 CMV emissions in the Great Lakes.

The cumulative impact of these ECA-IMO projections and controls to the U.S. + near-offshore (c3marine 

sector) and far-offshore emissions (othpt sector) in 2017 and 2025 is provided in Table 4-9.

Table 4-9. Difference in c3marine sector and othpt C3 CMV emissions between 2011 and future years

Region Pollutant

2011 

emissions

2017 

emissions

2025 

emissions

Difference 

2017 - 2011

Difference 

2025 - 2011

U.S. + near offshore CO 13,705 17,057 22,941 3,353 9,237

U.S. + near offshore NOX 145,729 147,369 121,177 1,640 -24,552

U.S. + near offshore PM10 11,370 2,013 2,606 -9,357 -8,764

U.S. + near offshore PM2.5 10,148 1,790 2,322 -8,358 -7,826

U.S. + near offshore SO2 95,306 5,093 5,998 -90,213 -89,309

U.S. + near offshore VOC 5,645 7,047 9,515 1,401 3,870

far-offshore (othpt sector) CO 251,654 324,915 461,376 73,261 209,722

far-offshore (othpt sector) NOX 2,935,480 3,361,627 3,864,871 426,147 929,391

far-offshore (othpt sector) PM10 216,192 249,379 83,553 33,187 -132,639

far-offshore (othpt sector) PM2.5 198,750 229,369 76,127 30,619 -122,623

far-offshore (othpt sector) SO2 1,617,893 1,825,762 486,412 207,870 -1,131,480

far-offshore (othpt sector) VOC 106,860 137,972 195,924 31,112 89,064
106

4.2.3.5 Upstream distribution, pipelines and refineries (nonpt, ptnonipm, pt_oilgas)

Packet:

For 2017: “PROJECTION_2011_2017_OTAQ_upstream_GasDist_pipelines_refineries_2011v6.2_05feb2015.txt”

For 2025: “PROJECTION_2011_2025_OTAQ_upstream_GasDist_pipelines_refineries_2011v6.2_05feb2015.txt”

To account for projected increases in renewable fuel volumes due to the Renewable Fuel Standards 

(RFS2)/EISA (EPA, 2010a) and decreased gasoline volumes due to RFS2 and light-duty greenhouse gas 

standards as quantified in AEO 2014 (http://www.eia.gov/forecasts/archive/aeo14/), EPA developed countylevel inventory adjustments for gasoline and gasoline/ethanol blend transport and distribution for 2018 and 

2025. Here, 2018 adjustments are used for 2017. These adjustments account for losses during truck, rail and 

waterways loading/unloading and intermodal transfers such as highway-to-rail, highways-to-waterways, and all 

other possible combinations of transfers. Adjustments for 2018 only account for impacts of RFS2, and the 2025 

adjustments also account for additional impacts of greenhouse gas emission standards for motor vehicles (EPA, 

2012b) on transported volumes. These emissions are entirely evaporative and therefore limited to VOC.

A 2018 inventory which included impacts of the EISA mandate was developed by applying adjustment factors 

to the 2011NEIv2 inventory. These adjustments were made using an updated version of EPA’s model for 

upstream emission impacts, developed for the RFS2 rule31. The methodology used to make these adjustments is 

described in a 2014 memorandum included in the docket for the EPA Tier 3 rule (EPA, 2014).

32

 

Ethanol emissions were estimated in SMOKE by applying the ethanol to VOC ratios from headspace profiles to 

VOC emissions for E10 and E15, and an evaporative emissions profile for E85. These ratios are 0.065 for E10,

0.272 for E15, and 0.61 for E85. The E10 and E15 profiles were obtained from an ORD analysis of fuel samples 

from EPAct exhaust test program33 and were submitted for incorporation into the EPA’s SPECIATE database. 

The E85 profile was obtained from data collected as part of the CRC E-80 test program (Environ, 2008) and 

was also submitted into EPA’s SPECIATE database. For more details on the change in speciation profiles 

between 2011 and 2018, see Section 3.2.1.4.

Pipeline usage and refinery emissions were adjusted to account for impacts of the 2017-2025 light duty vehicle 

greenhouse gas emission standards, as well as renewable fuel volume projections. These adjustments were 

developed by EPA OTAQ and impact processes such as process heaters, catalytic cracking units, blowdown 

systems, wastewater treatment, condensers, cooling towers, flares and fugitive emissions. Calculation of the 

emission inventory impacts of decreased gasoline and diesel production, due to renewable fuel volume 

projections, on nationwide refinery emissions was done in EPA’s spreadsheet model for upstream emission 

impacts (EPA, 2009b). Emission inventory changes reflecting these impacts were used to develop adjustment 

factors that were applied to inventories for each petroleum refinery in the U.S. These impacts of decreased 

production were assumed to be spread evenly across all U. S. refineries. Toxic emissions were estimated in 

SMOKE by applying speciation to VOC emissions. It should be noted that the adjustment factors are estimated 

relative to that portion of refinery emissions associated with gasoline and diesel fuel production. Production of 

jet fuel, still gas and other products also produce emissions. If these emissions were included, the adjustment 

factors would not be as large.

 

31 U.S. EPA. 2013. Spreadsheet “upstream_emissions_rev T3.xls.

32 U. S. EPA. Development of Air Quality Reference Case Upstream and Portable Fuel Container Inventories for the Tier 3 Final 

Rule. Memorandum from Rich Cook, Margaret Zawacki and Zoltan Jung to the Docket. February 25, 2014. Docket EPA-HQ-OAR2011-0135.

33 U.S. EPA. 2011. Hydrocarbon Composition of Gasoline Vapor Emissions from Enclosed Fuel Tanks. Office of Research and 

Development and Office of Transportation and Air Quality. Report No. EPA-420-R-11-018. EPA Docket EPA-HQ-OAR-2011-

0135.
107

The resulting adjustments for pipelines, refineries and the gasoline distribution processes (RBT, BPS and BTP) 

are provided in Table 4-10. Separate adjustments were applied to refinery to bulk terminal (RBT), bulk plant 

storage (BPS), and bulk terminal to gasoline dispensing pump (BTP) components. Emissions for the BTP 

component are greater than the RBT and BPS components. See Appendix B for the complete cross-walk 

between SCC, for all component types of petroleum transport and storage components. An additional 

adjustment was applied for 2025 at a national scale to account for impacts of gasoline volume reductions of the 

2017-2025 light-duty greenhouse gas rule.

Notice that the “2011 Emissions” are not the same in Table 4-10. This is because these “2011” emissions are 

actually an intermediate set up projections applied after a first CoST strategy used to apply most other 

PROJECTION and CONTROL packets. We decided to first apply these other packets because we have multiple 

PROJECTION and CONTROL programs that impact the same emission sources. For this example, we applied 

year-specific industrial sector AEO-based growth (discussed in the next section) with our first CoST strategy, 

then applied these “EISA” adjustments on the results of this first CoST strategy. Similarly, we have IC Engine 

(RICE) existing (NESHAP) as well as new source (NSPS) controls that need to be applied in separate strategies. 

Alternatively, we could have made “compound” CoST packets that combine these PROJECTION (and 

CONTROL) factors, but preferred to keep these packets separate for transparency. If we tried to process the 

multiple packets affecting the same sources in a single CoST strategy, CoST would either fail if the packet 

entries were are the same key-field resolution (duplicate error), or, if packets were at a different key-field 

resolution, CoST would only apply the packet entry with higher priority according to Table 4-2.

Table 4-10. Petroleum pipelines & refineries and production storage and transport factors and reductions

Poll Year

Factors

2011 

Emissions Reduction

% 

Reduction

Pipelines & 

Refineries RBT BTP/BPS

CO

2018 0.9896 n/a 53,527 557 1.0%

2025 0.9295 53,206 3,733 7.0%

NOX

2018 0.9877 n/a 68,406 838 1.2%

2025 0.9172 62,713 5,191 8.3%

PM10

2018 0.9938 n/a 24,486 152 0.6%

2025 0.9578 24,140 1,017 4.2%

PM2.5

2018 0.9940 n/a 21,602 130 0.6%

2025 0.9592 21,269 867 4.1%

SO2

2018 0.9909 n/a 79,391 719 0.9%

2025 0.9386 78,766 4,812 6.1%

VOC

2018 0.9934 0.9940 0.9581 750,311 21,629 2.9%

2025 0.9555 0.8172 0.7878 744,678 143,906 19.3%
108

4.2.3.6 Oil and gas and industrial source growth from 2011v6.0 NODA (nonpt, np_oilgas, 

ptnonipm, pt_oilgas)

2017 Packets:

“PROJECTION_2011v6.2_2018_nonpoint_SCC_SRAcapped_05dec2014”

“PROJECTION_2011v6.2_2018_SCC_NONPOINT_LADCO_09dec2014”

“PROJECTION_2011v6.2_2018_SCC_NONPOINT_SCA_orig_CAPPED_09dec2014”

“PROJECTION_2011v6.2_2018_SRAcapped_POINT_05dec2014”

“PROJECTION_2011v6.2_2018_SCC_POINT_LADCO_09dec2014”

“PROJECTION_2011v6.2_2018_SCC_POINT_SCA_orig_CAPPED_09dec2014”

“PROJECTION_2011v6.2_2018_NAICS_SCC_SCA_orig_NEI_matched_CAPPED2.5_04dec2014”

2025 Packets:

“PROJECTION_2011v6.2_2025_nonpoint_SCC_SRAcapped_05dec2014”

“PROJECTION_2011v6.2_2025_SCC_NONPOINT_LADCO_09dec2014”

“PROJECTION_2011v6.2_2025_SCC_NONPOINT_SCA_orig_CAPPED_09dec2014”

“PROJECTION_2011v6.2_2025_SRAcapped_POINT_05dec2014”

“PROJECTION_2011v6.2_2025_SCC_POINT_LADCO_09dec2014”

“PROJECTION_2011v6.2_2025_SCC_POINT_SCA_orig_CAPPED_09dec2014”

“PROJECTION_2011v6.2_2025_NAICS_SCC_SCA_orig_NEI_matched_CAPPED2.5_04dec2014”

The EPA provided a Notice of Data Availability (NODA, search for the docket ‘EPA-HQ-OAR-2013-0809’ on

regulations.gov) for the 2011v6.0 emissions modeling platform and projected 2018 inventory in January, 2014. 

A significant number of the comments were about the EPA’s “no growth” assumption for industrial stationary 

sources and about the current projection approach for oil and gas sources that was applied similarly to 5 broad 

geographic (NEMS) regions and limited to only oil and gas drilling activities. 

With limited exceptions, the EPA has used a no-growth assumption for all industrial non-EGU emissions since 

the 2005 NEI-based emissions modeling platform (EPA, 2006). However, comments provided to the EPA for 

this platform (via the NODA) and for previous modeling platforms suggested that this approach was 

insufficient. In addition, the NOX Budget program, which had a direct impact on post-2002 emissions 

reductions, is in full compliance in the 2011 NEI. This means that additional large-scale industrial reductions 

should not be expected beyond 2011 in the absence of on-the-books state and federal rules.

In response to the comments about EPA’s no-growth approach, the EPA developed industrial sector activitybased growth factors. In response to the NODA, many states have additionally provided detailed activity-based 

projection factors for industrial sources, including oil and gas sources. To develop the methods described here, 

we have blended the state-provided growth factors with the EPA-developed industrial sector growth factors.

This approach has attempted to balance using the specific information that is available with EPA’s interest in 

consistency for a given sector and technical credibility. Table 4-11 lists the resulting data sources for industrial 

sector non-EGU growth factors that EPA applied to this emissions modeling platform. Note that this list does

not include the revised “projection packets” from the 2011v6.0-based platform, which were also sent to the EPA 

via the docket process. That additional data were considered and included in our projections as well, and are 

discussed separately in Section 4.2.3.7. 

Ultimately, there were 3 broad sources of projection information for industrial sources, including oil and gas; 

these sources are referenced as the following for simplicity (e.g., realizing that not all data from Mid-Atlantic 

Regional Air Management Association (MARAMA) states are limited to MARAMA states):
109

1) EPA: Reflects EPA-sponsored data provided by a contractor (SC&A, 2014a; SC&A, 2014b). Packet file 

names for these data include “SCA”.

2) MARAMA: Reflects data submitted on behalf of Atlantic seaboard states from North Carolina through 

Maine, and extending west through Pennsylvania and West Virginia. Packet file names for these data 

include “SRA” (SRA, 2014).

3) LADCO: Reflects data submitted on behalf of Lake Michigan Air Directors Consortium (LADCO)

states (MN, WI, MI, IL, IN, OH). Projection data from this data source are reflected in packet names 

containing “LADCO” (Alpine Geophysics, 2014).

Table 4-11. Sources of new industrial source growth factor data from the 2011v6.0 NODA

Abbrev. Source

Geographic 

Resolution

Inventory 

Resolution Use/Caveat

EPA

2014 AEO fuel 

consumption/production 

for EPA “priority” 

categories: IC Engines, 

Gas Turbines and ICI 

Boilers/Process Heaters

Census 

Division

NAICS/SCC 

or SCC

Impacts almost all non-EGU stationary industrial and 

commercial sources. These data are used where LADCO and 

MARAMA data (below) are not also provided. Growth factors

are “capped” to 1.25 (25% cumulative growth) and outlier 

values (e.g., commercial residual oil) set to no-growth, 

consistent with MARAMA growth factor data (below).

EPA

2014 AEO Crude Oil 

Production, Natural Gas 

Production and Lease 

plant fuel + pipeline fuel 

natural gas consumption

AEO 

Oil/Gas 

Play-level 

and “Rest of 

Census 

Division”

NAICS/SCC 

or SCC

Impacts both point and nonpoint oil and gas sectors as well as 

some non-EGU point sources not in the pt_oilgas sector. These 

data supersede any/all other projections data, including 

LADCO/MARAMA information with minor exceptions (PA 

drilling, NY state no-growth, point source MARAMA data). 

These data also “cap” growth factors to 2.5 (150% cumulative 

growth).

MARAMA MARAMA/SRA/states

State or 

county for 

nonpoint and 

facility and 

below for 

most point 

sources

Facility and 

sub-facility 

for point, 

SCC-level 

for nonpoint

Many projection factors are unchanged from the 2011v6.0 

platform; however, many new data provided were included in 

our 2011v6.2 platform. However, the provided oil and gas 

projection data were not used, as we opted for single data 

source “EPA” approach. Emissions assigned a cap of 1.25 for 

many non-oil/gas production related sources (regardless of 

future year); we retain this cap and also apply this cap to all 

non-oil and gas sources.

LADCO LADCO/Alpine/states State or 

county SCC

Most projection factors are unchanged from 2011v6.0 platform. 

Oil and Gas factors from 2014 AEO but state-level only. We 

only used the new growth factor data, essentially limited to a 

couple priority (LADCO) source categories and did NOT use 

any oil and gas production-based projections data, opting 

instead to use the single data source “EPA” approach. As a 

result, these data have very limited impact on point and 

nonpoint oil and gas projections.

A discussion of each projection component in Table 4-11 is discussed below. 

“EPA” factors

As previously discussed, the EPA created a nationally-consistent set of industrial source projection factors for 

several future years. We relied on 2014 AEO fuel consumption/production projections data to develop growth 

factors for our first two “priority” source categories: IC Engines/Gas Turbines and ICI Boilers/Process Heaters. 

Table 4-12 provides a summary of the approaches used. We selected specific AEO energy consumption data 

sets that reflect the best available indicator of each source’s emissions activity. The discussion below provides 
110

more details on the approaches summarized in Table 4-12. This discussion is generally organized from the most 

straightforward approach, to the most complex. Growth factors were only developed for the specific NAICS 

codes that the AEO identifies as associated with economic sector-specific fuel consumption projections. These 

NAICS codes are listed in Table 4-13. The EPA mapped and expand the resulting NAICS/SCC and SCC 

growth factors to all relevant SCCs in the 2011v6.2 inventories. In cases where the AEO data showed a fuel 

type with zero consumption in each year, we set the growth factors for these fuels to “1.0” for each relevant 

year. This approach holds the growth flat for those fuels rather than zeros out the emissions in future years.

For all applicable commercial/institutional fuel combustion priority category SCCs, we compiled 2014 AEO 

regional commercial sector energy consumption projections data by fuel type for 2011, 2018, 2025 and 2030, 

and computed growth factors for each projection year/fuel type as the ratio of each future year’s energy 

consumption to 2011 energy consumption. The AEO’s commercial sector fuel consumption regions are 

equivalent to Census Divisions (see www2.census.gov/geo/pdfs/maps-data/maps/reference/us_regdiv.pdf). 

Because Census Divisions are groups of states, commercial/institutional fuel combustion growth factors were 

developed at the state-level, with each state in a given division assigned the same growth factors.
111

Table 4-12. Summary of “EPA” Projection Approaches for IC Engines/Gas Turbines and ICI Boilers/Process Heaters

Source 

Category Industry Sector1 NAICS Code(s)

Fuel 

Type(s) Summary of Approach

Commercial/

Institutional All AEO Commercial sector energy consumption projections by fuel type by Census Division

Industrial

Food 311

All

Calculate national energy intensity factors by AEO industry sector and fuel type; multiply by projected industry sector output at 

Census Division level to yield estimated regional energy consumption by sector/fuel type; and calculate regional growth factors 

by fuel type from these estimates

Paper 322

Refining 32411

Bulk Chemical 3251, 3252, 3253

Glass 3272

Cement 32731, 32741

Iron and Steel 3311

Aluminum 3313

Metal Based Durables 332-336

Other Manufacturing all other 31-33

Other

Agriculture 111,112,113,115

All

Calculate national energy intensity factors by AEO industry sector and fuel type; multiply by projected industry sector output at 

Census Division level to yield estimated regional energy consumption by sector/fuel type; and calculate regional growth factors 

by fuel type from these estimates

Construction 233-238

Mining 211, 2121, 2122-2123

Oil/Gas Production2 211, 213111, 213112, 

2212, 4861, 4862,

Natural 

Gas

AEO Oil/Gas Play-level: Calculate ratios of national oil/gas production to oil/gas sector constant dollar output; multiply ratios by 

AEO Census Division-level oil/gas sector constant dollar output to estimate Census Division-level oil/gas production; calculate 

Census Division-level ratios representing the sum of lease plant fuel + pipeline fuel natural gas consumption to the estimated 

volume of oil/gas produced; multiply these ratios by the volume of oil/gas produced in each applicable oil/gas play to yield oil/gas 

play-level projections of lease plant fuel + pipeline fuel natural gas consumption; finally, calculate play-level growth factors from 

these estimates.

Rest of Nation: Calculate “rest-of-Census Division” consumption estimates for pipeline fuel natural gas + lease and plant fuel by 

subtracting oil/gas play consumption estimates from the Census Division estimates published in the AEO. This yields nine sets of 

growth factors for each year, corresponding to each of the nine Census Divisions.

All other

AEO Oil/Gas Plays: Calculate the national ratio of oil/gas sector constant dollar output to the volume of oil and gas produced for 

each year; multiply these national ratios by AEO estimates of oil and gas production in each oil/gas play to yield estimates of 

oil/gas sector constant dollar output in each play; multiply the oil/gas sector constant dollar output estimates for each play by 

ratios of national Mining sector fuel consumption to national oil/gas sector constant dollar output (this procedure develops 

estimates of mining sector energy consumption by fuel type within each oil/gas play); and calculate growth factors by play/fuel 

type from these estimates.

Rest of Nation: develop “rest-of-Supply Region” oil/gas production estimates by subtracting the AEO’s oil/gas production 

estimates for these plays from AEO’s total oil/gas Supply region production estimates (the residual production values are then 

used to calculate the “rest-of-Supply Region” growth factors). This yields six sets of growth factors for each year, corresponding 

to each of the AEO’s six oil/gas Supply Regions.

All Other All AEO total energy consumption projections by fuel type and Census Division

Notes: Though not displayed in this table, a no-growth assumption was applied to 3 rocket engine SCCs, and applied AEO transportation sector fuel consumption projections to aircraft and railroad equipment-related SCCs.

1

Identified based either on NAICS code or SCC/NAICS code-see text for discussion.

2

In addition to priority category SCC records with oil/gas production NAICS codes, factors will also be applied to natural gas production SCCs (e.g., 31000203-Natural Gas Production/Compressors).
112

Table 4-13. NAICS Codes for which NAICS/SCC-level Growth Factors were developed

NAICS 

Code NAICS Code Description

111 Crop Production

112 Vegetable and Melon Farming

113 Fruit and Tree Nut Farming

115 Support Activities for Agriculture and Forestry

211 Oil and Gas Extraction

2121 Coal Mining

2122 Iron Ore Mining

2123 Nonmetallic Mineral Mining and Quarrying

213111 Drilling Oil and Gas Wells

213112 Support Activities for Oil and Gas Operations

2212 Natural Gas Distribution

233 Nonresidential Building Construction

234 Heavy Construction

235 Special Trade Contractors

236 Construction of Buildings

237 Heavy and Civil Engineering Construction

238 Specialty Trade Contractors

311 Food Manufacturing

312 Beverage and Tobacco Product Manufacturing

313 Textile Mills

314 Textile Product Mills

315 Apparel Manufacturing

316 Leather and Allied Product Manufacturing

321 Wood Product Manufacturing

322 Paper Manufacturing

323 Printing and Related Support Activities

32411 Petroleum Refineries

32412 Asphalt Paving, Roofing, and Saturated Materials Manufacturing

32419 Other Petroleum and Coal Products Manufacturing

3251 Basic Chemical Manufacturing

3252 Resin, Synthetic Rubber, and Artificial Synthetic Fibers and Filaments Manufacturing

3253 Pesticide, Fertilizer, and Other Agricultural Chemical Manufacturing

3254 Pharmaceutical and Medicine Manufacturing

3255 Paint, Coating, and Adhesive Manufacturing

3256 Soap, Cleaning Compound, and Toilet Preparation Manufacturing

3259 Other Chemical Product and Preparation Manufacturing

326 Plastics and Rubber Products Manufacturing

3272 Glass and Glass Product Manufacturing

32731 Cement Manufacturing

32732 Ready-Mix Concrete Manufacturing

32733 Concrete Pipe, Brick, and Block Manufacturing

32739 Other Concrete Product Manufacturing
113

NAICS 

Code NAICS Code Description

32741 Lime Manufacturing

3279 Other Nonmetallic Mineral Product Manufacturing

3311 Iron and Steel Mills and Ferroalloy Manufacturing

3312 Steel Product Manufacturing from Purchased Steel

3313 Alumina and Aluminum Production and Processing

3314 Nonferrous Metal (except Aluminum) Production and Processing

3315 Foundries

332 Fabricated Metal Product Manufacturing

333 Machinery Manufacturing

334 Computer and Electronic Product Manufacturing

335 Electrical Equipment, Appliance, and Component Manufacturing

336 Transportation Equipment Manufacturing

337 Furniture and Related Product Manufacturing

339 Miscellaneous Manufacturing

4861 Pipeline Transportation of Crude Oil

4862 Pipeline Transportation of Natural Gas

For all IC Engine/Gas Turbines and ICI Boilers/Process Heaters SCCs in the 2011 NEI that have no NAICS 

code, or a NAICS code for which there is no economic sector-specific AEO energy forecast available, we 

compiled growth factors based on the SCC process description. For example, SCC 10200101 (External 

Combustion Boilers; Industrial; Anthracite Coal; Pulverized Coal) is assigned to AEO’s Total Industrial 

sector coal consumption projections.

For all oil and gas production priority category SCCs (e.g., SCC 23100xxxxx) and all other priority category 

SCCs with oil/gas production-related NAICS codes, we used two separate approaches for AEO oil/gas plays 

(see Table 4-14). The first approach is specific to natural gas consumption, and the other approach is for 

consumption of all other individual fuel types. Because the AEO does not have information on the counties 

that comprise each of the oil/gas plays represented by the AEO data, we developed the necessary county lists 

using an internet search of oil/gas play maps and other related information. For counties not included in one 

of the AEO data’s oil/gas plays, “rest-of-Census Division” oil/gas consumption estimates were computed to 

develop growth factors for projecting energy consumption for all fuel types except natural gas (e.g., residual 

and distillate oil, coal, LPG, kerosene). Details on the oil/gas production sector growth factor development 

methods are described below.
114

Table 4-14. AEO Oil/Gas Plays

Tight Oil Play* Shale Gas Play

Austin Chalk Antrim

Avalon/Bone Springs Bakken

Bakken Barnett

Eagle Ford Eagle Ford

Monterey Fayetteville

Niobrara Haynesville/Bossier

Sprayberry Marcellus

Wolfcamp

Woodford

* AEO also publishes estimates for an “Other” tight oil plays category, however, EIA was 

unable to provide a list of what plays should be considered included in this “Other” category.

“Tight” oil (not to be confused with oil, or “kerogen” shale) refers to heterogeneous formations 

of low-permeability that vary widely over relatively short distances.

Natural Gas Consumption and Crude Oil Production

For natural gas consumption-related growth factor records, we developed oil/gas production area (“play”)-

level estimates of natural gas consumption and “rest-of-Census Division” estimates, which were applied to 

counties outside these play areas. For each relevant year, we first calculated from AEO’s projections, the 

ratio of national oil/gas production (in BTUs) to national oil/gas sector constant dollar output. These values 

were then multiplied by AEO projections of Census Division-level oil/gas sector constant dollar output to 

yield Division-level estimates of oil/gas production by year (in BTUs). Next, we computed AEO Census 

Division-level ratios of the sum of pipeline fuel natural gas + lease and plant fuel consumption35 to the 

estimated volume of oil/gas produced in each year. Then we developed oil/gas play-level projections of 

pipeline fuel natural gas + lease and plant fuel consumption by multiplying the Census Division-level ratios 

by the AEO estimates of oil/gas production in each play by year. Growth factors for each play/forecast year 

were developed by dividing each forecast year’s estimated consumption of pipeline fuel natural gas + lease 

and plant fuel by the estimated 2011 total volume of these fuels.

We calculated “rest-of-Census Division” consumption estimates for pipeline fuel natural gas + lease and 

plant fuel by subtracting the oil/gas play consumption estimates from the Census Division estimates 

published in the AEO. This yielded nine sets of growth factors for each year, corresponding to each of the 

nine Census Divisions. These growth factors reflect “rest-of-Census Division” estimated consumption of 

pipeline fuel natural gas + lease and plant fuel, and were applied to the non-AEO oil/gas play counties in 

each Division. 

Crude oil production growth factors were also generated for crude oil production-specific sources (SCCs).

These growth factors were generated at similar spatial resolution as natural gas consumption factors: oil/gas 

production “play”-level and rest of Census Division resolution. These data are based on AEO reference table 

“14” Crude Oil Production and Supply projections.

Other Fuels

The AEO prepares fuel consumption projections for the mining sector, which is comprised of the Oil & Gas 

Extraction & Support Activities, Coal Mining, and Other Mining and Quarrying sectors. On a national basis, 

AEO data indicate that the Oil & Gas Extraction & Support Activities sector contributed 85 percent of total 

 

35 While pipeline fuel natural gas should be self-explanatory, lease and plant fuel refers to “natural gas used in well, field, and lease 

operations, in natural gas processing plant machinery, and for liquefaction in export facilities.”
115

mining sector output (NAICS codes 211, 2121, 2122-2123) in the 2011 NEI, and is projected to account for a 

similar contribution (86 percent) in 2030. Estimates of mining sector energy consumption by fuel type for the 

AEO oil and gas plays were developed, and assumed that mining sector fuel consumption growth rates 

approximate growth rates in the oil/gas sector for these plays. Because of concerns that oil/gas production 

may not represent as significant a contribution to total mining activity in other areas (outside oil/gas plays), 

we chose not to use estimated Mining sector fuel consumption data to project oil/gas production sector fuel 

consumption in other areas of the country.

Oil/Gas Plays

As listed in Table 4-14 and displayed in Figure 4-1, the AEO reports oil and natural gas production 

projections for a number of individual oil and gas plays. The first step in estimating oil/gas sector energy 

consumption projections for these plays was to calculate, for each relevant year, the national ratio of Oil/Gas 

sector constant dollar output to the volume of oil and gas produced (expressed in BTUs) from the AEO. We 

then estimated Oil/Gas sector constant dollar output in each oil/gas play by multiplying these national ratios 

by AEO estimates of oil and gas production (BTUs) in each oil/gas play. These oil/gas play-level output 

estimates were then multiplied by year-specific national AEO ratios of Mining sector fuel consumption to 

Oil/Gas sector output, which produced Mining sector fuel consumption estimates by play/year. As noted 

above, these Mining sector estimates are deemed to be reasonable surrogates for Oil/Gas sector activity in 

the AEO oil/gas play areas.
116

Figure 4-1. Oil and gas plays with AEO projection data

Remaining Areas

For all non-AEO gas/oil play counties, we developed “rest-of-Supply Region” (National Energy Modeling 

System, or “NEMS”) oil/gas production estimates as the surrogate growth indicator for projecting fuel 

consumption in the Oil/Gas sector. These NEMS regions are shown in Figure 4-2. Since we address oil/gas 

play areas separately, this approach reflects oil/gas production occurring outside these areas. To accomplish 

this, we subtracted the AEO’s oil/gas production estimates for these plays from AEO’s total Oil/Gas Supply 

region production estimates, and used the result to calculate the growth factors for areas outside the oil/gas 

plays. After implementing this procedure, we produced six sets of “rest-of-Oil/Gas Supply Region” growth 

factors (one for each of the six Supply Regions) for application to counties in each supply region not in one 

of the AEO oil/gas plays. All oil and gas production related growth factors were capped at 2.5 (150% 

increase). Note that raw AEO growth factors of 4-6+ were not uncommon for 2018 and 2025. The cap 

addresses concerns that the uncertainty in these projections was too great to allow such dramatic growth. 
117

Figure 4-2. Oil and Gas NEMS Regions

“MARAMA” factors

The MARAMA states provided usable projections and controls data for 15 states (SRA, 2014). The growth 

data for oil and gas-specific processes (SCC-level) were not used. Rather, we used the EPA approach for 

nonpoint oil and gas emissions because it was more comprehensive and consistent nationally. We used the 

MARAMA facility and sub-facility (point inventory) growth factors; only a small subset of these factors

impact oil and gas point sources (facilities). We capped growth factors related to employment growth for 

both point and nonpoint factors at 1.25 (25% cumulative growth) to prevent excessive overestimation of 

future-year emissions.

The MARAMA point inventory projection factors were included in our projection packets at facility and 

sub-facility resolution and supersede any/all “EPA”-based SCC and NAICS/SCC projection factors (recall 

the CoST hierarchy described in Section 4.2.1). We used the other (i.e., non-oil and gas) MARAMA 

nonpoint projection factors which cover a large portion of the nonpoint sectors, including ICI fuel 

combustion, construction and mining, surface coating and degreasing processes, dry cleaners and waste 

water treatment.

“LADCO” factors
118

Similar to the MARAMA data, the LADCO (Midwest RPO) states provided usable projections and controls 

data for some states: MI, OH, IN. IL, WI, MN, IA, MO and KY (Alpine Geophysics, 2014). We did not use 

the growth data for oil and gas-specific processes (SCC-level). Rather, we used the EPA approach for 

nonpoint oil and gas emissions because it was more comprehensive and consistent nationally. The only 

facility or sub-facility growth factors for LADCO’s “priority” source categories that remained were limited 

to (hydraulic) frac sanding mining and petroleum mining. Our use of the nonpoint factors were limited to 

agriculture tilling and pesticide application, degreasing operations and residential wood combustion (RWC); 

we split out RWC factors and merged with our “rest of the country” set of projection factors (discussed in 

Section 4.2.3.11). These growth factors were all deemed reasonable, in that the values were well under 2.0 -a 

100% increase and did not rely on employment growth projections, and as such these were used essentially 

as-is. Note that the impact of these factors will be seen more for RWC than other stationary non-EGU 

emissions modeling sectors.

Net impacts of projection factors

Net impacts of these projection packets for each of the modeling sectors is provided in Table 4-15. There are 

a couple of items to note: 

1) All projection factors are for years 2018 and 2025; we used 2018 factors for year 2017.

2) The “2011 Emissions Subject to PROJECTION factors” in Table 4-15 are different in the 2017 and 

2025 projection processes/routines (CoST strategies) because other previously-applied 

PROJECTIONS or CLOSURES data differ for year 2017 and 2025, making the remaining 2011 

emissions subject to these specific PROJECTION packets different.

3) The largest increases are to the nonpoint oil and gas sector; however, these are not the final future 

year impacts, as significant new and existing controls, discussed in 4.2.4, have not yet been applied in 

creating the future-year emissions values shown in this table.

Table 4-15. Industrial source projections net impacts from 2011v6.0 NODA

Poll Sector

2011 Emissions 

Subject to 

PROJECTION factors

Intermediate 

Projected (not yet 

controlled)

Emissions

Difference (Future -

2011)

% Difference 

(Future -

2011)

For 2017 For 2025 2017 2025 2017 2025 2017 2025

CO nonpt 672,183 673,783 698,363 720,949 26,179 47,167 4% 7%

CO np_oilgas 532,211 532,211 683,021 795,874 150,811 263,663 28% 50%

CO pt_oilgas 228,664 228,577 233,940 307,594 5,276 79,016 2% 35%

CO ptnonipm 572,046 568,599 611,005 625,670 38,959 57,071 7% 10%

CO Total 2,005,104 2,003,169 2,226,329 2,450,086 221,224 446,917 11% 22%

NH3 nonpt 15,938 15,938 16,465 16,581 528 643 3% 4%

NH3 pt_oilgas 222 222 165 207 -57 -15 -26% -7%

NH3 ptnonipm 12,364 12,233 12,958 13,113 593 880 5% 7%

NH3 Total 28,524 28,392 29,588 29,900 1,064 1,508 4% 5%

NOX nonpt 477,769 472,942 497,051 498,126 19,281 25,184 4% 5%

NOX np_oilgas 576,626 576,626 775,875 902,334 199,250 325,709 35% 56%
119

Poll Sector

2011 Emissions 

Subject to 

PROJECTION factors

Intermediate 

Projected (not yet 

controlled)

Emissions

Difference (Future -

2011)

% Difference 

(Future -

2011)

For 2017 For 2025 2017 2025 2017 2025 2017 2025

NOX pt_oilgas 522,192 522,026 476,963 622,751 -45,229 100,725 -9% 19%

NOX ptnonipm 586,160 575,044 610,221 615,481 24,061 40,437 4% 7%

NOX Total 2,162,747 2,146,637 2,360,110 2,638,692 197,362 492,055 9% 23%

PM10 nonpt 260,831 260,792 278,565 293,743 17,734 32,951 7% 13%

PM10 np_oilgas 15,270 15,270 19,537 23,691 4,267 8,421 28% 55%

PM10 pt_oilgas 13,266 13,243 12,726 15,837 -540 2,594 -4% 20%

PM10 ptnonipm 130,488 128,764 141,695 146,538 11,207 17,775 9% 14%

PM10 Total 419,855 418,069 452,524 479,809 32,669 61,740 8% 15%

PM2.5 nonpt 209,188 209,206 223,913 236,507 14,725 27,302 7% 13%

PM2.5 np_oilgas 13,761 13,761 17,847 20,865 4,086 7,104 30% 52%

PM2.5 pt_oilgas 13,020 12,997 12,494 15,549 -526 2,551 -4% 20%

PM2.5 ptnonipm 105,943 104,219 115,864 119,787 9,921 15,568 9% 15%

PM2.5 Total 341,912 340,183 370,117 392,708 28,205 52,525 8% 15%

SO2 nonpt 248,793 249,431 251,323 247,483 2,531 -1,948 1% -1%

SO2 np_oilgas 17,598 17,598 36,797 38,206 19,199 20,607 109% 117%

SO2 pt_oilgas 51,588 51,477 54,423 55,180 2,835 3,703 5% 7%

SO2 ptnonipm 514,616 512,441 499,393 504,215 -15,223 -8,226 -3% -2%

SO2 Total 832,595 830,948 841,937 845,084 9,342 14,135 1% 2%

VOC nonpt 874,870 874,951 885,095 891,556 10,226 16,605 1% 2%

VOC np_oilgas 2,417,715 2,417,715 3,737,520 4,389,231 1,319,805 1,971,516 55% 82%

VOC pt_oilgas 131,691 131,395 137,535 167,923 5,843 36,528 4% 28%

VOC ptnonipm 131,016 129,910 140,787 142,621 9,771 12,711 7% 10%

VOC Total 3,555,292 3,553,970 4,900,937 5,591,332 1,345,645 2,037,361 38% 57%

4.2.3.7 Data from comments on previous platforms (nonpt, ptnonipm, pt_oilgas)

2017 Packets:

“PROJECTION_2011v6.2_2018_TCEQ_v6_leftovers_NONPOINT_30jan2015.txt”

“PROJECTION_VA_ME_TCEQ_AL_comments_2011v6_2018_03dec2013.txt”

“PROJECTION_TCEQ_ptnonipm_NAICS_comments_2011v6_2018”

2025 Packets:

“PROJECTION_2011v6.2_2025_TCEQ_v6_leftovers_NONPOINT_30jan2015.txt”

“PROJECTION_VA_ME_TCEQ_AL_comments_2011v6_2019_03dec2013.txt”

”PROJECTION_TCEQ_ptnonipm_NAICS_comments_2011v6_2025”

These projection packets includes projection factors used in the development of the 2011v6.0 emissions 

modeling platform, specifically, those discussed in Section 4.2.9 in the 2011v6.1 emissions modeling 

platform TSD (EPA, 2014b). Most of these data were originally received from the Texas Commission on 

Environmental Quality (TCEQ).
120

TCEQ nonpoint projection data

Packet: PROJECTION_2011v6.2_20YY_TCEQ_v6_leftovers_NONPOINT_30jan2015.txt, where “YY” is 

18 or 25 for year 2018 (2017 as well) and 2025 respectively.

Most of the “old” TCEQ nonpoint projections data are superseded by the 2011v6.0 NODA data, particularly 

the SCC-level growth factors discussed in Section 4.2.3.6. We removed all TCEQ projection factors for 

SCCs that overlapped. The remaining TCEQ nonpoint projection data are unchanged from the 2011v6.0 

emissions modeling platform. 

State comments from 2013

Packet: PROJECTION_VA_ME_TCEQ_AL_comments_2011v6_20YY_03dec2013.txt, where “YY” is 18 

or 19 for year 2018 (used for 2017) and year 2019 (used for 2025 projections), respectively.

This packet includes comments received prior to 2011v6.0 emissions modeling platform processing from 

Alabama, Maine, Texas and Virginia. These projections data target specific point sources in each of these 

states, generally impacting only a couple of facilities/units in a couple of counties in each state. 

TCEQ point county/NAICS projections data

Packet: PROJECTION_TCEQ_ptnonipm_NAICS_comments_2011v6_20YY, where “YY” is 18 or 25 for 

year 2018 (2017 as well) and 2025 respectively.

This packet was provided by TCEQ for minor point source emissions. Projections are applied by county and 

NAICS codes and are based on gross product projections for various types of industry, population and 

economy.com data. We did not apply these to oil and gas sources, opting to instead use the approach 

discussed in Section 4.2.3.6; in fact, most of these entries are not used because they are lower in the CoST 

hierarchy than the county/NAICS/SCC projection factors discussed in the same section.

Summary impacts

A summary of the impacts of these three projection factors for the three affected sectors are provided in 

Table 4-16. Most of these impacts are in Texas. Note that the 2011 emissions differ for 2017 and 2025 

projection scenarios; one reason for this is that projection factors equal to 1.0 (no change) were dropped from 

the TCEQ projections data; for some sources, year 2017 (2018) factors were equal to 1.0 while year 2025 

factors were not, and vice versa. When this happens, emissions in 2011 do not appear in 2017 but they do for 

2025 summaries. 

Table 4-16. Impact of 2011v6.0 projection factors for Texas

Poll Sector

2011 Emissions 

Subject to 

PROJECTION 

factors

Projected 

Emissions

Tons Difference 

(Future - 2011)

% Difference 

(Future - 2011)

For 

2017

For 

2025 2017 2025 2017 2025 2017 2025

CO nonpt 61,056 59,457 74,709 75,350 13,653 15,893 22% 27%

CO pt_oilgas 6,096 6,181 6,097 6,120 1 -61 0% -1%

CO ptnonipm 54,891 66,329 73,297 100,156 18,406 33,827 34% 51%

CO Total 122,043 131,967 154,103 181,626 32,060 49,659 26% 38%

NH3 nonpt 2,443 2,444 2,485 2,511 42 67 2% 3%

NH3 pt_oilgas 32 32 29 27 -3 -5 -9% -16%

NH3 ptnonipm 1,754 2,179 2,259 3,170 505 991 29% 45%
121

Poll Sector

2011 Emissions 

Subject to 

PROJECTION 

factors

Projected 

Emissions

Tons Difference 

(Future - 2011)

% Difference 

(Future - 2011)

For 

2017

For 

2025 2017 2025 2017 2025 2017 2025

NH3 Total 4,229 4,655 4,773 5,708 544 1,053 13% 23%

NOX nonpt 21,650 26,477 22,619 28,182 969 1,705 4% 6%

NOX pt_oilgas 4,423 4,587 4,322 4,320 -101 -267 -2% -6%

NOX ptnonipm 54,820 70,536 74,610 104,624 19,790 34,088 36% 48%

NOX Total 80,893 101,600 101,551 137,126 20,658 35,526 26% 35%

PM10 nonpt 20,101 20,140 24,535 27,003 4,434 6,863 22% 34%

PM10 pt_oilgas 1,071 1,103 1,040 1,060 -31 -43 -3% -4%

PM10 ptnonipm 16,002 22,293 20,484 30,777 4,482 8,484 28% 38%

PM10 Total 37,174 43,536 46,059 58,840 8,885 15,304 24% 35%

PM2.5 nonpt 15,672 15,655 19,439 21,629 3,767 5,974 24% 38%

PM2.5 pt_oilgas 1,037 1,069 1,005 1,022 -32 -47 -3% -4%

PM2.5 ptnonipm 12,528 18,024 16,237 24,993 3,709 6,969 30% 39%

PM2.5 Total 29,237 34,748 36,681 47,644 7,444 12,896 25% 37%

SO2 nonpt 4,415 3,776 4,367 3,649 -48 -127 -1% -3%

SO2 pt_oilgas 9,077 9,172 8,757 8,634 -320 -538 -4% -6%

SO2 ptnonipm 22,376 44,050 27,964 56,702 5,588 12,652 25% 29%

SO2 Total 35,868 56,998 41,088 68,985 5,220 11,987 15% 21%

VOC nonpt 259,815 259,734 276,439 286,184 16,624 26,450 6% 10%

VOC pt_oilgas 14,796 15,178 14,399 13,914 -397 -1,264 -3% -8%

VOC ptnonipm 51,020 70,148 68,586 103,803 17,566 33,655 34% 48%

VOC Total 325,631 345,060 359,424 403,901 33,793 58,841 10% 17%

4.2.3.8 Aircraft (ptnonipm)

Packet:

For 2017: “PROJECTION_2011_2017_aircraft_ST_and_by_airport_22jan2015.txt”

For 2025: “PROJECTION_2011_2025_aircraft_ST_and_by_airport_22jan2015.txt”

Aircraft emissions are contained in the ptnonipm inventory. These 2011 point-source emissions are projected 

to future years by applying activity growth using data on itinerant (ITN) operations at airports. The ITN 

operations are defined as aircraft take-offs whereby the aircraft leaves the airport vicinity and lands at 

another airport, or aircraft landings whereby the aircraft has arrived from outside the airport vicinity. EPA

used projected ITN information available from the Federal Aviation Administration’s (FAA) Terminal Area 

Forecast (TAF) System: http://www.apo.data.faa.gov/main/taf.asp (publication date March, 2014). This 

information is available for approximately 3,300 individual airports, for all years up to 2040. The methods 

that the FAA used for developing the ITN data in the TAF are documented in:

http://www.faa.gov/about/office_org/headquarters_offices/apl/aviation_forecasts/taf_reports/media/TAF_Su

mmary_Report_FY2013-2040.pdf.
122

None of our aircraft emission projections account for any control programs. EPA considered the NOX

standard adopted by the International Civil Aviation Organization’s (ICAO) Committee on Aviation 

Environmental Protection (CAEP) in February 2004, which is expected to reduce NOX by approximately 3% 

by 2020. However, this rule has not yet been adopted as an EPA (or U.S.) rule; therefore, its effects were not 

included in the future-year emissions projections.

EPA developed two sets of projection factors for aircraft. The first set was a simple state-level aggregation, 

used primarily for airports with very little activity, by ITN operation type (commercial, general aviation, 

military and air taxi) to be used as a default method for projecting from 2011 to future years. The second set 

of projection factors was by airport, where EPA projects emissions for each individual airport with 

significant ITN activity. 

Where NEI facility identifiers were not matched to FAA airport identifiers we simply summed the ITN 

operations to state totals by year and aircraft operation and computed projection factors as future-year ITN to 

year-2011 ITN. EPA assigned factors to inventory SCCs based on the operation type shown in Table 4-17.

Table 4-17. NEI SCC to FAA TAF ITN aircraft categories used for aircraft projections

SCC Description FAA ITN Type

2265008005 Commercial Aircraft: 4-stroke Airport Ground Support Equipment Commercial

2267008005 Commercial Aircraft: LPG Airport Ground Support Equipment Commercial

2268008005 Commercial Aircraft: CNG Airport Ground Support Equipment Commercial

2270008005 Commercial Aircraft: Diesel Airport Ground Support Equipment Commercial

2275000000 All Aircraft Types and Operations Commercial

2275001000 Military Aircraft, Total Military

2275020000 Commercial Aviation, Total Commercial

2275050011 General Aviation, Piston General

2275050012 General Aviation, Turbine General

2275060011 Air Taxi, Total: Air Taxi, Piston Air Taxi

2275060012 Air Taxi, Total: Air Taxi, Turbine Air Taxi

2275070000 Commercial Aircraft: Aircraft Auxiliary Power Units, Total Commercial

27501015

Internal Combustion Engines; Fixed Wing Aircraft L & TO Exhaust; 

Military; Jet Engine: JP-5 Military

27502011

Internal Combustion Engines; Fixed Wing Aircraft L & TO Exhaust; 

Commercial; Jet Engine: Jet A Commercial

27505001

Internal Combustion Engines; Fixed Wing Aircraft L & TO Exhaust; Civil; 

Piston Engine: Aviation Gas

General

27505011

Internal Combustion Engines; Fixed Wing Aircraft L & TO Exhaust; Civil; 

Jet Engine: Jet A

General

Most NEI airports matched FAA TAF identifiers and therefore use airport-specific projection factors. We 

applied a cap on projection factors of 2.0 (100% increase) for state-level defaults and 5.0 for airport-specific 

entries. None of the largest airports/larger-emitters had projection factors close to these caps. A national 

summary of aircraft emissions between 2011 and future years 2017 and 2025 are provided in Table 4-18.

.
123

Table 4-18. National aircraft emission projection summary

Emissions Difference % Difference

2011 2017 2025 2017 2025 2017 2025

CO 489,854 509,687 565,678 19,833 75,824 4.0% 15.5%

NOX 120,968 131,678 161,297 10,710 40,328 8.9% 33.3%

PM10 9,164 9,373 10,121 208 956 2.3% 10.4%

PM2.5 7,891 8,084 8,787 194 896 2.5% 11.4%

SO2 14,207 15,256 18,536 1,049 4,329 7.4% 30.5%

VOC 32,023 33,601 38,591 1,578 6,568 4.9% 20.5%

4.2.3.9 Cement manufacturing (ptnonipm)

Packet:

For 2017: “PROJECTION_2011_2018_ISIS_cement_by_CENSUS_DIVISION_04dec2013.txt“

For 2025: “PROJECTION_2011_2025_ISIS_cement_by_CENSUS_DIVISION_25nov2013.txt”

As indicated in Table 4-1, the Industrial Sectors Modeling Platform (ISMP) (EPA, 2010b) was used to 

project the cement industry component of the ptnonipm emissions modeling sector to 2018 and 2025; we 

used year 2018 as a surrogate for year 2017. This approach provided reductions of criteria and select 

hazardous air pollutants. The ISMP cement emissions were developed in support for the Portland Cement 

NESHAPs and the NSPS for the Portland cement manufacturing industry.

The ISMP model produced a Portland Cement NESHAP policy case of multi-pollutant emissions for 

individual cement kilns (emission inventory units) that were relevant for years 2015 through 2030. These 

ISMP-based emissions are reflected using a CoST packet for all existing kilns that are not impacted by more 

local information from states (or consent decrees). ISMP also generates new cement kilns that are permitted 

(point inventory) and not-permitted, but generated based on ISMP assumptions on demand and infrastructure 

(nonpt inventory). These new cement kilns are discussed in Section 4.2.5.4.

The PROJECTION packets contain U.S. census division level based projection factors for each NEI unit 

(kiln) based on ISMP updated policy case emissions at existing cement kilns. The units that closed before 

2018 (and 2025) are included in the 2018 (and 2025) base case but are included in other CoST packets that 

reflect state comments and consent decrees (discussed in Section 4.2.4.10). 

The ISMP model, version August 2013 was used for these projections. Recent data updates include updated 

matching of kilns to better capture recent retirements, capacity additions and projections of capacity 

additions from Portland Cement Association (PCA) Plant Information Summary of December 31, 2010 and 

feedback from Portland Cement NESHAP reconsideration comments. Updated cement consumption 

projections are based on a post-recession (July 2012) PCA long-term cement consumption outlook. Updated 

emissions controls in 2015 from the NESHAP are also reflected. Overall, as seen in Figure 4-3, domestic 

production of cement grows significantly between 2011 and 2015, then more slowly through 2018. 

Meanwhile, emissions from NESHAP-regulated pollutants such as PM and SO2 drop significantly based on 

regulated emissions rates. Emissions for NOX increase, though not as much as production because the ISMP

model continues the recent trend in the cement sector of the replacement of lower capacity, inefficient wet 

and long dry kilns with bigger and more efficient preheater and precalciner kilns. 
124

Figure 4-3. Cement sector trends in domestic production versus normalized emissions

Multiple regulatory requirements such as the NESHAP and NSPS currently apply to the cement industry to

reduce CAP and HAP emissions. Additionally, state and local regulatory requirements might apply to 

individual cement facilities depending on their locations relative to ozone and PM2.5 nonattainment areas. 

The ISMP model provides the emission reduction strategy that balances: 1) optimal (least cost) industry 

operation, 2) cost-effective controls to meet the demand for cement, and 3) emission reduction requirements 

over the time period of interest. 

The first step in using ISMP 2018 and 2025 projected emissions is matching the kilns in future years to those 

in the 2011 NEI. While ISMP provides by-kiln emissions for each future year, EPA cement kilns experts 

preferred that the Agency project existing cement kilns based on a more-smooth geographic approach to 

reduce the “on”/”off” switching that ISMP assigns to each kiln based on production and capacity demands. It 

would be inefficient and unrealistic to project existing cement kilns to operate as essentially 0% or 100% 

capacity based strictly on ISMP output. Therefore, EPA developed a U.S. Census Division approach where 

ISMP emissions in 2011 and future years, that matched the 2011 NEI (e.g., not new ISMP kilns), were 

aggregated by pollutant for each year within each of the 9 census divisions in the contiguous U.S. 

(http://www.eia.gov/consumption/commercial/images/cendivco.gif). These aggregate emissions were used to 

create 2018/2011 and 2025/2011 emissions ratios for each pollutant and geographic area. The projection 

ratios, provided in Table 4-19, were then applied to all 2011 NEI cement kilns –except for kilns where 

specific local information (e.g., consent decrees/settlements/local information) was available. 

0

50

100

150

200

250

Domestic Production

PM trend

NOX trend

SO2 trend
125

Table 4-19. U.S. Census Division ISMP-based projection factors for existing kilns

Region Division

NOX PM SO2 VOC

2018 2025 2018 2025 2018 2025 2018 2025

Midwest East North Central 2.024 2.053 0.106 0.144 1.800 3.034 0.527 0.670

Midwest West North Central 0.930 1.279 0.614 0.673 0.695 1.262 0.317 0.492

Northeast Middle Atlantic 1.853 1.221 0.058 0.119 0.904 0.867 0.561 0.569

Northeast New England 2.560 2.560 0.004 0.004 3.563 3.563 0.713 0.713

South East South Central 0.999 0.999 0.109 0.109 0.402 0.402 0.323 0.323

South South Atlantic 1.042 1.077 0.284 0.339 0.911 0.936 0.413 0.420

South West South Central 1.220 1.526 0.079 0.174 0.484 0.664 0.225 0.252

West Mountain 1.453 1.321 2.542 1.032 1.917 1.366 0.310 0.345

West Pacific 1.465 1.465 0.001 0.006 0.300 0.251 0.321 0.290

Table 4-20 shows the magnitude of the ISMP census division based projected cement industry emissions at 

existing NEI facilities from 2011 to future years 2018 and 2025; we use 2018 projected emissions for year 

2017. Additional new kiln emissions generated by ISMP are discussed in Section 0. There are some local 

exceptions where EPA did not use ISMP-based projections for cement kilns where local information from 

consent decrees/settlements and state comments were used instead. Cement kilns projected using these nonISMP information are not reflected here in Table 4-20.

Table 4-20. ISMP-based cement industry projected emissions

Emissions Tons Difference % Difference

2011 2017 2025 2017 2025 2017 2025

NOX 53,240 70,432 75,680 17,193 22,440 32.3% 42.1%

PM10 2,954 1,185 1,033 -1,769 -1,921 -59.9% -65.0%

PM2.5 1,709 717 657 -992 -1,052 -58.0% -61.6%

SO2 15,876 18,053 25,579 2,177 9,702 13.7% 61.1%

VOC 2,503 861 1,026 -1,642 -1,477 -65.6% -59.0%

4.2.3.10Corn ethanol plants (ptnonipm)

Packet:

For 2017: “PROJECTION_2011_2017_Corn_Ethanol_Plants_AEO2014_Table17_2011v6.2_19feb2015.txt“

For 2025: “PROJECTION_2011_2025_Corn_Ethanol_Plants_AEO2014_Table17_2011v6.2_19feb2015.txt”

We used the AEO 2014 renewable forecast projections of “From Corn and Other Starch” to compute 

national year 2017 and 2025 growth in ethanol plant production. Per OTAQ direction, we exempted two 

facilities (‘Highwater Ethanol LLC’ in Redwood county MN and ‘Life Line Foods LLC-St. Joseph’ in 

Buchanan county MO) from these projections; future year emissions were equal to their 2011 NEI v2 values 

for these two facilities. 

The 2011 corn ethanol plant emissions were projected to account for the change in domestic corn ethanol 

production between 2011 and future years, from approximately 13.9 Bgal (billion gallons) in 2011 to 13.0

Bgal by 2017 and 13.2 Bgal in 2025, based on AEO 2014 projections. The projection was applied to all 

pollutants and all facilities equally. Table 4-21 provides the summaries of estimated emissions for the corn 

ethanol plants in 2011 and future years 2017 and 2025.
126

Table 4-21. 2011 and 2017/2025 corn ethanol plant emissions [tons]

Emissions Difference % Change

2011 2017 2025 2017 2025 2017 2025

CO 1,172 1,092 1,111 -80 -61 -6.9% -5.2%

NOX 1,552 1,445 1,471 -107 -81 -6.9% -5.2%

PM10 1,386 1,290 1,314 -96 -72 -6.9% -5.2%

PM2.5 339 316 322 -23 -17 -6.9% -5.2%

SO2 12 11 11 -1 -1 -6.9% -5.2%

VOC 3,379 3,147 3,204 -232 -175 -6.9% -5.2%

4.2.3.11Residential wood combustion (rwc) 

Packet:

For 2017: “PROJECTION_2011_2017_RWC_2011v6.2_03mar2015.txt”

For 2025: “PROJECTION_2011_2025_RWC_2011v6.2_03mar2015.txt”

EPA applied the recently-promulgated national New Source Performance Standards (NSPS) for wood stoves 

to the Residential Wood Combustion (RWC) projections methodology for this platform. To learn more about 

the strengthened NSPS for residential wood heaters, see http://www2.epa.gov/residential-woodheaters/regulatory-actions-residential-wood-heaters. EPA projected residential wood combustion (RWC)

emissions to years 2017 and 2025 based on expected increases and decreases in various residential wood 

burning appliances. As newer, cleaner woodstoves replace some older, higher-polluting wood stoves, there 

will be an overall reduction of the emissions from older “dirty” stoves but an overall increase in total RWC 

due to population and sales trends in all other types of wood burning devices such as indoor furnaces and 

outdoor hydronic heaters (OHH). It is important to note that our RWC projection methodology does not 

explicitly account for state or local residential wood control programs. There are a number more-stringent 

state and local rules in place in 2011, specifically in California, Oregon and Washington. However, at this 

time, EPA does not have enough detailed information to calculate state specific or local area growth rates. 

Therefore, with the exception of California, Oregon and Washington, EPA is using national level growth 

rates for each RWC SCC category. After discussions with California air districts, regional office contacts and 

EPA experts, EPA decided to hold RWC emissions flat (unchanged) for all SCCs in California, Oregon and 

Washington.

Assumed Appliance Growth and Replacement Rates

The development of projected growth in RWC emissions to years 2017 and 2025 starts with the projected 

growth in RWC appliances derived from year 2012 appliance shipments reported in the Regulatory Impact 

Analysis (RIA) for Proposed Residential Wood Heaters NSPS Revision Final Report (EPA, 2013b), also 

available at: http://www2.epa.gov/sites/production/files/2013-12/documents/ria-20140103.pdf. The 2012 

shipments are based on 2008 shipment data and revenue forecasts from a Frost & Sullivan Market Report 

(Frost & Sullivan, 2010). Next, to be consistent with the RIA (EPA, 2013b), growth rates for new appliances 

for certified wood stoves, pellet stoves, indoor furnaces and OHH were based on forecasted revenue (real 

GDP) growth rate of 2.0% per year from 2013 through 2025 as predicted by the U.S. Bureau of Economic 

Analysis (BEA, 2012). While this approach is not perfectly correlated, in the absence of specific shipment 

projections, the RIA assumes the overall trend in the projection is reasonable. The growth rates for 

appliances not listed in the RIA (fireplaces, outdoor wood burning devices (not elsewhere classified) and 

residential fire logs) are estimated based on the average growth in the number of houses between 2002 and 

2012, about 1% (U.S. Census, 2012).
127

In addition to new appliance sales and forecasts extrapolating beyond 2012, assumptions on the replacement 

of older, existing appliances are needed. Based on long lifetimes, no replacement of fireplaces, outdoor wood 

burning devices (not elsewhere classified) or residential fire logs is assumed. It is assumed that 95% of new 

woodstoves will replace older non-EPA certified freestanding stoves (pre-1988 NSPS) and 5% will replace 

existing EPA-certified catalytic and non-catalytic stoves that currently meet the 1988 NSPS (Houck, 2011).

EPA RWC NSPS experts assume that 10% of new pellet stoves and OHH replace older units and that 

because of their short lifespan, that 10% of indoor furnaces are replaced each year; these are the same 

assumptions used since the 2007 emissions modeling platform (EPA, 2012d). The resulting growth factors 

for these appliance types varies by appliance type and also by pollutant because the emission rates, from 

EPA RWC tool (EPA, 2013rwc), vary by appliance type and pollutant. For EPA certified units, the 

projection factors for PM are lower than those for all other pollutants. The projection factors also vary 

because the total number of existing units in 2011 varies greatly between appliance types.

NSPS Overview

The residential wood heaters NSPS Final Rule was promulgated on February 3, 2015. This rule does not 

affect existing woodstoves or other wood burning devices; however, it does provide more stringent emissions 

standards for new woodstoves, outdoor hydronic heaters and indoor wood-burning forced air furnaces. New 

“Phase 1” less-polluting heater standards begin in 2015, with even more-stringent Phase 2 standards 

beginning in 2020. The associated reduced emission rates for each appliance type (SCC) are applied to all 

new units sold, some of which are assumed to replace retired units, since year 2015.

Currently the 1988 NSPS limits primary PM2.5 emissions from adjustable burn rate stoves, including 

fireplace inserts and freestanding woodstoves, to 7.5 grams/hour (g/hr) for non-catalytic stoves and 4.1 g/hr 

for catalytic stoves. The final NSPS limits PM2.5 emissions for room heaters, which include adjustable and 

single burn rate stoves and pellet stoves to 4.5 g/hr in 2015 and 1.3 g/hr in 2020. In addition, the final NSPS 

limits PM2.5 emissions from hydronic heaters to 0.32 lb/MMBtu heat output in 2015, and 0.06 lb/MMBtu in 

2020. The final NSPS limits PM2.5 emissions from indoor furnaces to 0.93 lb/MMBtu in 2015 and 

0.06/MMBtu in 2020.

Emission factors were estimated from the 2011v2 NEI based on tons of emissions per appliance for PM2.5, 

VOC and CO. This calculation was based on estimated appliance (SCC) population and total emissions by 

SCC. EPA-certified wood stove emission factors are provided in the wood heaters NSPS RIA Tables 4-3, 4-

7 and 4-11 for PM2.5, VOC and CO, respectively. For all RWC appliances subject to the NSPS, baseline RIA 

emission factors, when lower than the computed emission factors (2011 NEI), are used for new appliances 

sold between 2012 and 2014. Starting in 2015, Phase 1 emission limits are 60% stronger (0.45 g/hr / 0.75 

g/hr) than the RIA baseline emission factors. There are also different standards for catalytic versus noncatalytic EPA-certified stoves. Similar calculations are performed for Phase 2 emission limits that begin in 

2020 and for different emission rates for different appliance types. Because the 2011NEI and RIA baseline 

(2012-2014) emission factors vary by pollutant, all RWC appliances subject to the NSPS have pollutantspecific “projection” factors. We realize that these “projection” factors are a composite of growth, 

retirements and potentially emission factors in 4 increments. More detailed documentation on the EPA RWC 

Projection Tool, including information on baseline, new appliances pre-NSPS, and Phase 1 and Phase 2 

emission factors, is available upon request.

Caveats and Results

California, Oregon and Washington have state-level RWC control programs, including local burn bans in 

place. Without an ability to incorporate significant local RWC control programs/burn bans for a future year 
128

inventory, EPA left RWC emissions unchanged in the future for all three states. The RWC projections 

factors for states other than California, Oregon and Washington are provided in Table 4-22. VOC HAPs use 

the same projection factors as VOC, PM10 uses the same factor as PM2.5, and all other pollutants use the CO 

projection factor. Note that appliance types not subject to the wood heaters NSPS (e.g., fire pits, fire logs) 

have pollutant-independent projection factors because there is no assumed change in future year emission 

factors.

Table 4-22. Non-West Coast RWC projection factors, including NSPS impacts

Default if 

pollutant not 

defined

PM VOC and 

VOC HAPs

CO and 

remaining 

CAPs

2017 2025 2017 2025 2017 2025 2017 2025

2104008100 Fireplace: general 1.062 1.149

2104008210

Woodstove: fireplace inserts; nonEPA certified 0.903 0.754

2104008220

Woodstove: fireplace inserts; EPA 

certified; non-catalytic 1.171 1.26 1.071 1.113

2104008230

Woodstove: fireplace inserts; EPA 

certified; catalytic 1.171 1.317 1.076 1.145

2104008310

Woodstove: freestanding, non-EPA 

certified 0.932 0.795 0.937 0.791 0.94 0.809 0.932 0.795

2104008320

Woodstove: freestanding, EPA 

certified, non-catalytic 1.171 1.26 1.071 1.113

2104008330

Woodstove: freestanding, EPA 

certified, catalytic 1.171 1.317 1.077 1.146

2104008400 Woodstove: pellet-fired, general 1.55 1.952 1.551 2.014

2104008510

Furnace: Indoor, cordwood-fired, 

non-EPA certified 0.746 0.12 0.831 0.147 0.745 0.119 0.746 0.12

2104008610 Hydronic heater: outdoor 1.062 1.038 1.094 1.074

2104008700 Outdoor wood burning device, NEC 1.062 1.149

2104009000

Residential Firelog Total: All 

Combustor Types 1.062 1.149

National emission summaries for the RWC sector in 2011, 2017 and 2025 are provided in Table 4-23. For

direct PM, the NSPS emission factor reductions mostly offset the growth in appliances by year 2017; by year 

2025, continued penetration of Phase 1 and 2 standards and replacement of non-EPA certified units with 

much cleaner EPA-certified appliances result in a net reduction for primary PM.

Table 4-23. Cumulative national RWC emissions from growth, retirements and NSPS impacts

Pollutant

Emissions Difference % Difference

2011 2017 2025 2017 - 2011 2025 -2011 2017 - 2011 2025 -2011

CO 2,527,054 2,513,621 2,332,033 -13,434 -195,021 -0.5% -7.7%

NH3 19,759 19,611 18,210 -148 -1,549 -0.7% -7.8%

NOX 34,577 35,652 34,863 1,074 285 3.1% 0.8%

PM10 382,817 385,356 357,054 2,539 -25,763 0.7% -6.7%

PM2.5 382,591 385,119 356,802 2,528 -25,789 0.7% -6.7%

SO2 8,977 8,837 7,626 -140 -1,351 -1.6% -15.1%

VOC 444,349 439,738 409,947 -4,610 -34,402 -1.0% -7.7%
129

4.2.4 CoST CONTROL packets (nonpt, np_oilgas, ptnonipm, pt_oilgas)

The final step in a CoST control strategy, after application of any/all CLOSURE packet(s) (point inventories 

only) and any/all PROJECTION packet(s) is the application of CoST CONTROL packets. While some 

controls are embedded in our PROJECTION packets (e.g., NSPS controls for RWC and loco-marine controls 

for rail and commercial marines vessels), we attempted to separate out the control (program) component in 

our modeling platform where feasible. In our platform, CoST control packets only impact the nonpt, 

np_oilgas, ptnonipm and pt_oilgas sectors.

There are several different sources of CONTROL data that are concatenated and quality-assured for 

duplicates and applicability to the inventories in the CoST strategies. We broke up the CONTROL (and 

PROJECTION) packets into a few “key” control program types to allow for quick summaries of these 

distinct control programs. The remainder of this section is broken out by CoST packet, with the exception of 

discussion of the various packets gathered from previous versions of the emissions modeling platform; these 

packets are a mix of different sources of data, only some of which have not been replaced by more recent 

information gathered for this platform.

For future-year NSPS controls (oil and gas, RICE, Natural Gas Turbines, and Process Heaters), we attempted 

to control only new sources/equipment using the following equation to account for growth and retirement of 

existing sources and the differences between the new and existing source emission rates.

Qn = Qo { [ (1 + Pf ) t – 1 ] Fn + ( 1 - Ri ) t Fe + [ 1 - ( 1 - Ri ) t ] Fn ] } Equation 1

where:

Qn = emissions in projection year

Qo = emissions in base year

Pf = growth rate expressed as ratio (e.g., 1.5=50% cumulative growth)

t = number of years between base and future years

Fn = emission factor ratio for new sources

Ri = retirement rate, expressed as whole number (e.g., 3.3%=0.033)

Fe = emission factor ratio for existing sources

The first term in Equation 1 represents new source growth and controls, the second term accounts for 

retirement and controls for existing sources, and the third term accounts for replacement source controls. For 

computing the CoST % reductions (Control Efficiency), the simplified Equation 2 was used for 2025 

projections:

Control_Efficiency2025(%) = 100 * (1- [(Pf2025-1)*Fn + (1-Ri)14 + (1-(1-Ri)14)*Fn]/ Pf2025) Equation 2

Here, the existing source emissions factor (Fe) is set to 1.0, 2025 (future year) minus 2011 (base year) is 14, 

and new source emission factor (Fn) is the ratio of the NSPS emission factor to the existing emission factor. 

Table 4-24 shows the values for Retirement rate and new source emission factors (Fn) for each NSPS 

regulation and other conditions within; this table also provides the subsection where the CONTROL packets 

are discussed.
130

Table 4-24. Assumed retirement rates and new source emission factor ratios for new sources for various 

NSPS rules

NSPS 

Rule

TSD 

Section

Retirement 

Rate years

(%/year)

Pollutants 

Impacted

Applied where? New Source 

Emission 

Factor (Fn)

Oil and 

Gas 4.2.4.1 No assumption VOC

Storage Tanks: 70.3% reduction in 

growth-only (>1.0)

0.297

Gas Well Completions: 95% 

control (regardless)

0.05

Pneumatic controllers, not highbleed >6scfm or low-bleed: 77% 

reduction in growth-only (>1.0)

0.23

Pneumatic controllers, high-bleed 

>6scfm or low-bleed: 100% 

reduction in growth-only (>1.0)

0.00

Compressor Seals: 79.9% 

reduction in growth-only (>1.0)

0.201

RICE 4.2.4.3 40, (2.5%)

NOX

Lean burn: PA, all other states 0.25, 0.606

Rich Burn: PA, all other states 0.1, 0.069

Combined (average) LB/RB: PA, 

other states

0.175, 0.338

CO

Lean burn: PA, all other states 1.0 (n/a), 

0.889

Rich Burn: PA, all other states 0.15, 0.25

Combined (average) LB/RB: PA, 

other states

0.575, 0.569

VOC

Lean burn: PA, all other states 0.125, n/a

Rich Burn: PA, all other states 0.1, n/a

Combined (average) LB/RB: PA, 

other states

0.1125, n/a

Gas 

Turbines 4.2.4.6 45 (2.2%) NOX

California and NOX SIP Call 

states

0.595

All other states 0.238

Process 

Heaters 4.2.4.7 30 (3.3%) NOX

Nationally to Process Heater 

SCCs

0.41

4.2.4.1 Oil and gas NSPS (np_oilgas, pt_oilgas)

Packet:

For 2017: “CONTROL_2011v6.2_2018_OilGas_VOC_NSPS_12dec2014.txt”

For 2025: “CONTROL_2011v6.2_2025_OilGas_VOC_NSPS_12dec2014.txt”

For oil and gas NSPS controls, with the exception of gas well completions (a 95% control) the assumption of 

no equipment retirements through year 2025 dictates that NSPS controls are applied to the growth 

component only of any PROJECTION factors. For example, if a growth factor is 1.5 for storage tanks 

(indicating a 50% increase activity), then, using Table 4-24, the 70.3% VOC NSPS control to this new 

growth will result in a 23.4% control: 100 *(70.3 * (1.5 -1) / 1.5); this yields an “effective” growth rate 

(combined PROJECTION and CONTROL) of 1.1485, or, a 70.3% reduction from 1.5 to 1.0. The impacts of 
131

all non-drilling completion VOC NSPS controls are therefore greater where growth in oil and gas production 

is assumed highest. Conversely, for oil and gas basins with assumed negative growth in activity/production, 

VOC NSPS controls will be limited to well completions only. Because these impacts are so geographically 

varying, we are providing the VOC NSPS reductions by each of the 6 broad NEMS regions, with Texas and 

New Mexico aggregated because these states include multiple NEMS regions (see Figure 4-2). These 

reductions are year-specific because projection factors for these sources are year-specific. For the 2017 

modeling case, because the projection factors are for year 2018, the reductions are based on year 2018 

growth as well.

Table 4-25. NSPS VOC oil and gas reductions from projected pre-control 2018 and 2025 grown values

Region

Pre-NSPS Emissions Post-NSPS Emissions NSPS Reductions

NSPS % 

Reductions

2018 2025 2018 2025 2018 2025 2018 2025

Gulf Coast 75,152 137,990 57,951 110,054 17,201 27,937 23% 20%

Midcontinent 7,882 222,288 4,238 189,474 3,644 32,814 46% 15%

New Mexico/Texas 1,184,448 1,389,112 716,616 881,695 467,832 507,417 39% 37%

Northeast 33,300 33,327 14,903 14,909 18,397 18,418 55% 55%

Rocky Mountains 517,266 993,574 313,729 529,956 203,536 463,618 39% 47%

West Coast 15 15 1 1 14 14 95% 95%

Overall 1,818,063 2,776,306 1,107,438 1,726,089 710,625 1,050,217 39% 38%

4.2.4.2 RICE NESHAP (nonpt, np_oilgas, ptnonipm, pt_oilgas)

Packet: “CONTROL_2011v6.2_RICE_NESHAP_v2_30jan2015.txt”

There are two rulemakings for National Emission Standards for Hazardous Air Pollutants (NESHAP) for 

Reciprocating Internal Combustion Engines (RICE). These rules reduce HAPs from existing and new RICE 

sources. In order to meet the standards, existing sources with certain types of engines will need to install 

controls. In addition to reducing HAPs, these controls have co-benefits that also reduce CAPs, specifically, 

CO, NOX, VOC, PM, and SO2. In 2014 and beyond, compliance dates have passed for both rules and are 

thus included in emissions projections. These RICE reductions also reflect the Reconsideration Amendments

(proposed in January, 2012), which result in significantly less stringent NOX controls (fewer reductions) than 

the 2010 final rules.

The rules can be found at http://www.epa.gov/ttn/atw/icengines/ and are listed below:

 National Emission Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion 

Engines; Final Rule (FR 9648) published 03/03/10

 National Emission Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion 

Engines; Final Rule (75 FR 51570) published 08/20/2010

The difference among these two rules is that they focus on different types of engines, different facility types 

(major for HAPs, versus area for HAPs) and different engine sizes based on horsepower. In addition, they 

have different compliance dates, though both are after 2011 and fully implemented prior to 2017. EPA 

projects CAPs from the 2011NEIv2 RICE sources, based on the requirements of the rule for existing sources

only because the inventory includes only existing sources. EPA estimates the NSPS (new source) impacts 
132

from RICE regulations in a separate CONTROL packet and CoST strategy; the RICE NSPS is discussed in 

the next section.

The Regulatory Impact Analysis (RIA) for the Reconsideration of the Existing Stationary Compression 

Ignition (CI) Engines NESHAP: Final Report (EPA, 2013ci) is available at:

http://www.epa.gov/ttn/ecas/regdata/RIAs/RICE_NESHAPreconsideration_Compression_Ignition_Engines_

RIA_final2013_EPA.pdf. The Regulatory Impact Analysis (RIA) for Reconsideration of the Existing 

Stationary Spark Ignition (SI) RICE NESHAP: Final Report (EPA, 2013si) is available at:

http://www.epa.gov/ttn/ecas/regdata/RIAs/NESHAP_RICE_Spark_Ignition_RIA_finalreconsideration2013_

EPA.pdf. Together, EPA calls these the RICE NESHAP amendment RIA’s for SI and CI engines. From 

these RICE NESHAP RIA documents, EPA obtained cumulative RICE reductions for all SCCs represented 

by CI and SI engines. These aggregate reductions and percent reductions from baseline emissions (not the 

2011NEIv2) are provided in Table 4-26.

Table 4-26. Summary RICE NESHAP SI and CI percent reductions prior to 2011NEIv2 analysis

CO NOX PM SO2 VOC

RIA Baseline: SI engines 637,756 932,377 127,170

RIA Reductions: SI engines 22,211 9,648 9,147

RIA Baseline: CI engines 81,145 19,369 11,053 79,965

RIA Reductions: CI engines 14,238 2,818 5,100 27,142

RIA Cumulative Reductions 36,449 9,638 2,818 5,100 36,289

SI % reduction 3.5% 1.0% n/a n/a 7.2%

CI % reduction 17.5% n/a 14.5% 46.1% 33.9%

These RIA percent reductions were used as an upper-bound for reducing emissions from RICE SCCs in the 

2011NEIv2 point and nonpoint modeling sectors (ptnonipm, nonpt, pt_oilgas and np_oilgas). To begin with, 

the RIA inventories are based on the 2005 NEI, so EPA wanted to ensure that our 2011 reductions did not 

exceed those in the RICE RIA documents. For the 2011 platform EPA worked with EPA RICE NESHAP 

experts and developed a fairly simple approach to estimate RICE NESHAP reductions. Most SCCs in the 

inventory are not broken down by horsepower size range, mode of operation (e.g., emergency mode), nor 

major versus area source type. Therefore, EPA summed NEI emissions nationally by-SCC for RICE sources 

and also for sources that were at least partially IC engines (e.g., “Boiler and IC engines”). Then, EPA applied 

the RIA percent reductions to the 2011NEIv2 for SCCs where national totals exceeded 100 tons; EPA chose 

100 tons as a threshold, assuming there would be little to no application of RICE NESHAP controls on 

smaller existing sources. 

Next, EPA aggregated these national reductions by engine type (CI vs. SI) and pollutant and compared these 

to the RIA reductions. As expected, for most pollutants and engine types, the cumulative reductions were 

significantly less than those in the RIA. The only exception was for SO2 CI engines, where EPA scaled the 

RIA percent reduction from 46.1% to 14.4% for four broad nonpoint SCCs that were not restricted to only 

RICE engines. These four SCCs were the “Boilers and IC Engines” or “All processes” that would 

presumably contain some fraction of non-RICE component. This had minimal impact as sulfur content in 

distillate fuel for many IC engine types has decreased significantly since 2005. Reducing the SO2 percent 

reduction for these four SCCs resulted in slightly less than 5,100 tons of SO2 reductions overall from only 

RICE NESHAP controls. However, more specific CoST projection packets would later override these RICE 

NESHAP reductions for SO2. Recall the CoST hierarchy discussed earlier; these RICE NESHAP reductions 

are national by pollutant and SCC and thus easily overridden by more-specific information such as statelevel fuel sulfur rules (discussed in the next section). 
133

Additional comments from the NODA were also implemented; specifically, CO controls were modified for a 

couple of distillate-fueled industrial/commercial boiler sources. Impacts of the RICE NESHAP controls on 

nonpt, ptnonipm, pt_oilgas and np_oilgas sector emissions are provided in Table 4-27.

Table 4-27. National by-sector reductions from RICE Reconsideration controls (tons)

Pollutant Year

Nonpoint 

Oil & Gas 

(np_oilgas)

Point

Oil & Gas 

(pt_oilgas)

Nonpoint 

(nonpt)

Point 

(ptnonipm) Total

CO 2018 7,993 4,533 3,214 6,146 21,886

CO 2025 8,783 6,146 3,215 6,394 24,538

NOX 2018 2,240 1,749 192 81 4,262

NOX 2025 2,441 2,411 197 84 5,133

PM10 2018 0 8 929 305 1,242

PM10 2025 0 10 922 311 1,243

PM2.5 2018 0 8 828 289 1,124

PM2.5 2025 0 10 821 294 1,124

SO2 2018 0 9 71 296 376

SO2 2025 0 14 71 294 378

VOC 2018 1,989 2,874 586 942 6,392

VOC 2025 2,224 4,217 588 956 7,986

4.2.4.3 RICE NSPS (nonpt, np_oilgas, ptnonipm, pt_oilgas)

Packet:

For 2017: “CONTROL_2011v6.2_2018_RICE_NSPS_29dec2014.txt”

For 2025: “CONTROL_2011v6.2_2025_RICE_NSPS_29dec2014.txt”

Controls for existing RICE source emissions were discussed in the previous section. This section discusses 

control for new equipment sources, NSPS controls that impact CO, NOX and VOC. EPA emission 

requirements for stationary engines differ according to whether the engine is new or existing, whether the 

engine is located at an area source or major source, and whether the engine is a compression ignition or a 

spark ignition engine. Spark ignition engines are further subdivided by power cycle, two vs. four stroke, and 

whether the engine is rich burn or lean burn.

RICE engines in the NOX SIP Call area are covered by state regulations implementing those requirements. 

EPA estimated that NOX emissions within the control region were expected to be reduced by about 53,000 

tons per five month ozone season in 2007 from what they would otherwise be without this program. Federal 

rules affecting RICE included the NESHAP for RICE 40 CFR Part 63, Subpart ZZZZ, NSPS for Stationary 

Spark Ignition IC engines 40 CFR Part 60 Subpart JJJJ, and NSPS for Compression Ignition IC engines 40 

CFR Part 60 Subpart IIII. SI engine operators were affected by the NSPS if the engine was constructed after 

June 12, 2006, with some of the smaller engines affected by the NSPS 1-3 years later. The recommended 

RICE equipment lifetime is 30 to 40 years depending on web searches. We chose 40 years as a conservative 

estimate.

The 2011 estimates of the RICE engine average emission rates for lean burn and rich burn engines was 

developed using the stationary engine manufacturers data submitted to EPA for the NSPS analysis (Parise, 

2005). Emission factors by pollutant for engines 500-1200 horsepower (hp) were used to develop the average 
134

emission rates. The analysis was organized this way because lean vs. rich burn engine type is such a 

significant factor in the NOX emissions rate. Any state emission regulations that require stationary RICE 

engines to achieve emission levels lower than the 2012 NSPS could be included by using lower new source 

emission ratios that account for the additional emission reductions associated with having more stringent 

state permit rules. Information is provided for Pennsylvania in Table 4-28. That information shows that the 

PA regulations have different emission standards for lean burn vs. rich burn engines, and that the emission 

limits also vary by engine size (100-500 hp or greater than 500 hp). While some of the newer RICE SCCs 

(oil and gas sector in particular) allow states to indicate whether engines are lean vs. rich burn, some SCCs 

lump these two together. None of the RICE point source SCCs have information about engine sizes. 

However, the EPA regulatory impact analysis for the RICE NSPS and NESHAP analysis (RTI, 2007) 

provides a table that shows the NOX (CO, NMHC and HAP emission estimates are provided as well) 

emissions in 2015 by engine size, along with engine populations by size. In the future, more rigorous 

analysis can use this table to develop computations of weighted average emission reductions by rated hp to 

state regulations like Pennsylvania’s. 

Table 4-28. RICE NSPS Analysis and resulting 2011v6.2 new emission rates used to compute controls

Engine type & fuel Max Engine 

Power

Geographic 

Applicability

Emission standards 

g/HP-hr

NOX CO VOC

2011 pop lean burn 500-1200 hp 1.65 2.25 0.7

2011 pop rich burn 500-1200 hp 14.5 8 0.45

Non-Emerg. SI NG and Non-E. SI Lean 

Burn LPG (except LB 500≤HP<1,350) HP≥100 2006 NSPS 2.0 4.0 1.0

Non-Emerg. SI NG and Non-E. SI Lean 

Burn LPG (except LB 500≤HP<1,350) HP≥100 2012 NSPS 1.0 2.0 0.7

HP≥100 PA (Previous GP-5) 2.0 2.0 2.0

New NG Lean Burn 100<HP<500 PA (New GP-5) 1.0 2.0 0.7

New NG Lean Burn HP >500 PA (New GP-5) 0.5 2.0 0.25

New NG Rich Burn 100<HP<500 PA (New GP-5) 0.25 0.3 0.2

New NG Rich Burn HP >500 PA (New GP-5) 0.2 0.3 0.2

HP≥100 Maryland 1.5

HP>7500 Colorado 1.2 - 2

Wyoming None None None

Notes: the above table compares the criteria pollutant emission standards from the recent NSPS with the emission limits from selected 

states for stationary IC engines to determine whether future year emission rates are likely to be significantly lower than for the existing 

engine population. States in the NOX SIP Call region instituted NOX emission limits for large engines well before 2011. Most of the 

values in the above table come from an analysis posted on the PA DEP website. The state emission limits listed above are those in 

place prior to 2011. Some states (like PA) have instituted tougher RICE emission limits for new and modified engines more recently.

Note 2: Wyoming exempts all but the largest RICE engines from emission limits.

Note 3: PA has had a size limit for new RICE engines of 1500 hp until recently (i.e., not engines bigger than 1500 hp can be installed). 

Their new General Permit-5 removed the engines size cap, but requires new or modified larger engines to be cleaner (i.e., has emission 

limits lower than the NSPS). PA expects that the new emission limits will result in an increase in larger engines being installed, and 

bringing the average emission rate much lower than it is currently.

New source Emissions Rate (Fn): Controls % =100 * (1-Fn) NOX CO VOC

Pennsylvania NG-Comb. LB & RB 0.175 0.575 0.113

All other states NG-Comb. LB & RB 0.338 0.569 1.278

Pennsylvania NG-lean burn 0.250 1.000 0.125

All other states NG-lean burn 0.606 0.889 1.000

Pennsylvania NG-rich burn 0.100 0.150 0.100

All other states NG-rich burn 0.069 0.250 1.556
135

We applied NSPS reduction for lean burn, rich burn and “combined” (not specified). We also computed 

scaled-down (less-stringent) NSPS controls for SCCs that were “IC engines + Boilers” because boiler 

emissions are not subject to RICE NSPS. For these SCCs, we used the 2011NEIv2 point inventory to 

aggregate eligible (fuel and type) boiler and IC engine emissions for each pollutant. We found that for CI 

engines, almost all emissions were boiler-related; therefore, there are no CI engine RICE NSPS reductions 

for “IC engines + Boilers”. For SI engines, we found that approximately 9% of NOX, 10% Of CO and 19% 

of VOC “IC engines + Boilers” were IC engines; these splits were then applied to the NSPS reductions in 

Table 4-28. Finally, we limited RICE NSPS-eligible sources (SCCs) to those that have at least 100 tons 

nationally for NOX, CO or VOC, and ignored resulting controls that were under 1%.

PA DEP staff note that until recently they have limited RICE engines to a maximum of 1500 hp. That cap is 

lifted under the new General Permit-5 regulations. With that cap lifting, PA expects that new applications 

will choose to install larger engines which have lower emission limits. However, that potential effect will be 

difficult to capture with no information about how this might occur. These controls were then plugged into 

Equation 2 (see Section 4.2.4) as a function of the projection factor. Resulting controls greater than or equal 

to 1% were retained. Note that where new Emissions Factors >=1.0 (uncontrolled, as represented by red cells 

at the bottom of Table 4-28), no RICE NSPS controls were computed. National RICE NSPS reductions from 

projected pre-NSPS 2018 and 2025 inventories are shown in Table 4-29. 

Table 4-29. National by-sector reductions from RICE NSPS controls (tons)

Pollutant Year

Nonpoint 

Oil & Gas 

(np_oilgas)

Point Oil 

& Gas 

(pt_oilgas)

Nonpoint 

(nonpt)

Point 

(ptnonipm)

Total 

NSPS 

Reductions

Pre-NSPS 

Total 

Emissions

NSPS % 

Reduction

CO 2018 93,422 19,321 758 861 114,363 503,266 23%

CO 2025 161,075 51,249 2,277 1,366 215,968 762,028 28%

NOX 2018 156,942 44,949 1,685 1,242 204,818 777,041 26%

NOX 2025 252,770 122,603 3,903 2,063 381,339 1,072,744 36%

VOC 2018 1,656 422 0 1 2,079 3,986 52%

VOC 2025 1,838 484 0 2 2,324 3,990 58%

4.2.4.4 ICI Boilers (nonpt, ptnonipm, pt_oilgas)

Packets:

CONTROL_2011v6.2_20xx_BoilerMACT_POINT_v2_30jan2015.txt

CONTROL_2011v6.2_20xx_BoilerMACT_NONPT_08jan2015.txt

The Industrial/Commercial/Institutional Boilers and Process Heaters MACT Rule, hereafter simply referred 

to as the “Boiler MACT” was promulgated on January 31, 2013 based on reconsideration. Background 

information on the Boiler MACT can be found at: http://www.epa.gov/ttn/atw/boiler/boilerpg.html. The 

Boiler MACT promulgates national emission standards for the control of HAPs (NESHAP) for new and 

existing industrial, commercial, and institutional (ICI) boilers and process heaters at major sources of HAPs. 

The expected cobenefit for CAPs at these facilities is significant and greatest for SO2 with lesser impacts for 

direct PM, CO and VOC. These packets address only the expected cobenefits to existing ICI boilers.

Boiler MACT reductions were computed from a non-NEI database of ICI boilers. As seen in the Boiler 

MACT Reconsideration RIA (http://www.epa.gov/ttn/atw/boiler/boilersriaproposalrecon111201.pdf), this 

Boiler MACT Information Collection Request (ICR) dataset computed over 558,000 tons of SO2 reductions 
136

by year 2015. However, the Boiler MACT ICR database and reductions are based on the assumption that if a 

unit could burn oil, it did burn oil, and often to capacity. With high oil prices and many of these units also 

able to burn cheaper natural gas, the 2011NEIv2 inventory has a lot more gas combustion and a lot less oil 

combustion than the boiler MACT database. For this reason, EPA decided to target units that potentially 

could be subject to the Boiler MACT and compute preliminary reductions for several CAPs prior to building 

a control packet.

Step 1: Extract facilities/sources potentially subject to Boiler MACT

This step is only applicable to point inventory sources. EPA did not attempt to map each ICR unit to the NEI 

units, instead choosing to use a more general approach to extract NEI sources that would be potentially 

subject to, and hence have emissions reduced by the Boiler MACT. The NEI includes a field that indicates 

whether a facility is a major source of HAPs and/or CAPs. This field in our FF10 point inventory modeling 

file is called “FACIL_CATEGORY_CODE” and the possible values for that field are shown in Table 4-30. 

Because the Boiler MACT rule applies to only major sources of HAPs, EPA restricted the universe of 

facilities potentially subject to the Boiler MACT to those classified as HAP major or unknown (UNK). The 

third column indicates whether the facility was a candidate for extraction as being potentially subject to the 

Boiler MACT.

Table 4-30. Facility types potentially subject to Boiler MACT reductions

Code Facility 

Category

Subject 

to Boiler 

MACT?

Description

CAP CAP Major N Facility is Major based upon 40 CFR 70 Major Source definition paragraph 

2 (100 tpy any CAP. Also meets paragraph 3 definition, but NOT 

paragraph 1 definition).

HAP HAP Major Y Facility is Major based upon only 40 CFR 70 Major Source definition 

paragraph 1 (10/25 tpy HAPs).

HAPCAP HAP and 

CAP Major

Y Facility meets both paragraph 1 and 2 of 40 CFR 70 Major Source 

definitions (10/25 tpy HAPs and 100 tpy any CAP).

HAPOZN HAP and O3 

n/a Major

Y Facility meets both paragraph 1 and 3 of 40 CFR 70 Major Source 

definitions (10/25 tpy HAPs and Ozone n/a area lesser tons for NOX or 

VOC).

NON Non-Major N Facility's Potential To Emit is below all 40 CFR 70 Major Source threshold 

definitions without a FESOP.

OZN O3 n/a Major N Facility is Major based upon only 40 CFR 70 Major Source definition 

paragraph 3 (Ozone n/a area lesser tons for NOX or VOC).

SYN Synthetic 

non-Major

N Facility has a FESOP which limits its Potential To Emit below all three 40 

CFR 70 Major Source definitions.

UNK Unknown N Facility category per 40 CFR 70 Major Source definitions is unknown.

Step 2: Obtain “MARAMA” control information

From the (point inventory) facilities extracted in Step 1, we merged in ICI Boiler controls/adjustments 

developed under MARAMA in support of the Ozone Transport Commission (OTC) 2007 modeling platform 

future year analyses. These adjustments are discussed in a White Paper “White Paper for ICI Blr Emissions 

V6.doc” (available upon request). This white paper provides methodology and summary future year 

adjustments and emission estimates based on the OTC 2007 platform for the purpose of estimating emissions 

changes in ICI point and nonpoint sources due to the Boiler MACT, 1-hour SO2 NAAQS and economic 

factors related to natural gas prices. This MARAMA approach relies on Council of Industrial Boilers (CIBO) 

analysis of cost-effectiveness of boiler controls and retrofits in order to maintain the Boiler MACT. In short, 

the CIBO analyses showed that many ICI boilers were converting (or replacing coal units) to natural gas 
137

rather than applying more costly controls. Specifically, CIBO determined that 63% of coal units found it 

more economical to replace their coal boilers with natural gas boilers.

ICI boilers were categorized by fuel: Light Oil (distillate), Heavy Oil (residual), Pulverized Coal and 

Stoker/Other Coal. Next, AP42 (http://www.epa.gov/ttn/chief/ap42/) emission factors for each fuel was 

converted to consistent units (lb/MMBtu) via heat content and these normalized emission factors were used 

to develop emission factor ratios of natural gas to non-natural gas fuel type. Finally, the estimated number of 

ICI boiler replacements and retrofits were used to create weighted-average adjustment (“control”) factors 

from these normalized emission factor ratios. This methodology makes the following assumptions:

 Natural Gas NOX emissions rates: 0.10 lb/MMBtu for new boilers, 

0.1961 lb/MMBtu for burner retrofits

 Natural gas emission rates for SO2, PM2.5 and VOC are the same for both boiler replacement and 

burner retrofits

 Any unit that finds it economical to replace the entire boiler, will do so. Those that don't replace the 

boiler but find it economical to retrofit the burner will do so. Other units remain unchanged for NOX, 

SO2, PM2.5 and VOCs emissions.

 Analyses are based on OTC 2007 modeling platform and applied to 2011 emissions modeling 

platform

Step 3: Merge control information with 2011 NEI and apply state NODA comments

EPA analyzed the SCCs in the OTC 2007 inventories and tweaked the SCC mapping of these ICI boiler 

adjustments to map to those in the 2011 NEI point and nonpoint inventory with non-zero emissions. EPA 

also removed some duplicate and incorrect mappings and expanded the SCC mapping in some cases to SCCs 

that were in the NEI but not the OTC inventory (and thus missing from the analysis). In addition, the 

MARAMA approach only includes adjustments for NOX, PM and SO2. Therefore, EPA merged in existing 

VOC, CO, HCl controls (applying VOC controls to VOC HAPs as well) from the 2011v6.0 emissions 

modeling platform (see Section 4.2.7 in the 2011v6.0 Emissions Modeling TSD) to the same set of facilities 

(point) and SCCs as those for the pollutants provided by the MARAMA approach. 

Some states commented on the 2011v6.0 ICI boiler controls via the 2018 NODA (docket # EPA-HQ-OAR2013-0809 on http://www.regulations.gov). Wisconsin provided alternative SO2, VOC and HCl controls for 

stoker and pulverized coal fueled units. The national-level and Wisconsin-specific ICI boiler adjustments, 

applied at the unit-level for point sources and by SCC (and state for Wisconsin) are provided in Table 4-31; 

note that we applied the same national-level adjustments to CO, NOX and PM for coal units in Wisconsin.

New York and New Jersey, via the MARAMA comment/data to the 2018 NODA, provided boiler rule NOX

reductions that also supersede these nationally-applied factors. The NJ and NY factors are provided in Table 

4-32; note that NJ controls apply only to nonpoint sources and that NY controls vary by fuel for point 

sources.

The impacts of these ICI boiler reductions are provided in Table 4-33. Overall, the CO and PM2.5 reductions 

are reasonably close to the year-2015 expected reductions in the Boiler MACT Reconsideration RIA: 

http://www.epa.gov/ttn/atw/boiler/boilersriaproposalrecon111201.pdf. It is worth noting that the SO2

reductions in the preamble (http://www.epa.gov/ttn/atw/boiler/fr21mr11m.pdf) were estimated at 442,000 

tons; the additional SO2 reductions in the reconsideration are from an additional co-benefit from more 

stringent HCl controls. The 2011NEIv2 SO2 emissions are actually less than the estimated Boiler MACT 

reductions, likely a result of numerous units undergoing fuel switching from coal or oil to natural gas.
138

Table 4-31. National-level, with Wisconsin exceptions, ICI boiler adjustment factors by base fuel type

Unit/Fuel Type

Default % Reduction (Adjustments)

CO NOX PM SO2 VOC HCl

Stoker Coal 98.9 70.7 96 97.4 98.9 95

Pulverized Coal 98.9 60.6 72.2 73 98.9 95

Residual Oil 99.9 57 92.4 97.1 99.9 95

Distillate Oil 99.9 38.8 68.4 99.9 99.9 88.6

Wisconsin: Stoker Coal 98.9 70.7 96 30 0 45

Wisconsin: Pulverized Coal 98.9 60.6 72.2 30 0 45

Table 4-32. New York and New Jersey NOX ICI Boiler Rules that supersede national approach

NJ and NY Boiler Rule controls

NOX % 

Reduction

New Jersey Small Boiler Rule (nonpoint only): Default for Distillate, Residual, natural gas and LPG 25

New York Small Boiler Rule (nonpoint only): Default for Distillate, Residual, natural gas and LPG 10

NY Boiler Rule: Industrial /Distillate Oil /< 10 Million Btu/hr 10

NY Boiler Rule: Industrial /Residual Oil /10-100 Million Btu/hr 33.3

NY Boiler Rule: Electric Gen /Residual Oil /Grade 6 Oil: Normal Firing 40

NY Boiler Rule: Electric Gen /Natural Gas /Boilers, < 100 Million Btu/hr except Tangent 50

NY Boiler Rule: Electric Gen /Natural Gas /Boilers, 100 Million Btu/hr except Tangent 60

NY Boiler Rule: Industrial /Bitum Coal /Cyclone Furnace 66.7

NY Boiler Rule: Industrial /Natural Gas /> 100 Million Btu/hr 70

NY Boiler Rule: Electric Gen /Bituminous Coal /Pulverized Coal: Dry Bottom 73.3

Table 4-33. Summary of ICI Boiler reductions

Year Pollutant

Emissions Eligible 

for Control

Controlled (Final) 

Emissions

Reductions

(tons)

% 

Reductions

2017 CO 35,118 336 34,782 99.0%

2017 NOX 128,943 64,596 64,347 49.9%

2017 PM10 34,592 7,401 27,191 78.6%

2017 PM2.5 13,973 2,504 11,469 82.1%

2017 SO2 273,449 29,451 243,998 89.2%

2017 VOC 1,778 43 1,735 97.6%

2025 CO 35,883 346 35,537 99.0%

2025 NOX 130,862 65,259 65,603 50.1%

2025 PM10 35,729 7,700 28,030 78.4%

2025 PM2.5 14,273 2,572 11,701 82.0%

2025 SO2 272,425 30,579 241,846 88.8%

2025 VOC 1,791 43 1,747 97.6%
139

4.2.4.5 Fuel sulfur rules (nonpt, ptnonipm, pt_oilgas)

Packet: CONTROL_2011v6.2_20xx_Fuel_Sulfur_Rules_09jan2015.txt

Fuel sulfur rules, based on web searching and the 2011 emissions modeling NODA comments are currently 

limited to the following states: Connecticut, Delaware, Maine, Massachusetts, New Jersey, New York,

Pennsylvania, Rhode Island and Vermont. The fuel limits for these states are incremental starting after year 

2012, but are fully implemented by July 1, 2018 in all of these states. 

A summary of all fuel sulfur rules provided back to EPA by the 2011 emissions modeling NODA comments 

is provided in Table 4-34. State-specific control factors were computed for distillate, residual and #4 fuel oil 

using each state’s baseline sulfur contents and the sulfur content in the rules. For most states, the baseline 

sulfur content was 3,000 ppm (0.3%) for distillate oil, and 2.25% for residual and #4 oil. However, many 

states had lower baseline sulfur contents for residual oil, which varied by state and county. SRA used stateor county-specific baseline residual oil sulfur contents to calculate a state- or county-specific control factors 

for residual oil (SRA, 2014).

Table 4-34. State Fuel Oil Sulfur Rules data provided by MANE-VU

State Reference

Connecticut Section 22a-174-19a. Control of sulfur dioxide emissions from power plants and other large stationary sources 

of air pollution: Distillate and Residual: 3000 ppm effective April 15, 2014. 

Section 22a – 174 - 19b. Fuel Sulfur Content Limitations for Stationary Sources (except for sources subject to 

Section 22a-174-19a).

Distillate: 500 ppm effective July 1, 2014; 15 ppm effective July 1, 2018

Residual: 1.0% effective July 1, 2014; 0.3% effective July 1, 2018 

Connecticut General Statute 16a-21a. Sulfur content of home heating oil and off-road diesel fuel. 

Number 2 heating oil and off-road diesel fuel: 500 ppm effective July 1, 2014; 15 ppm effective July 1, 2018

See: http://www.ct.gov/deep/cwp/view.asp?a=2684&Q=322184&deepNav_GID=1619

Delaware 1108 Sulfur Dioxide Emissions from Fuel Burning Equipment 

Distillate: 15 ppm effective July 1, 2017

Residual: 0.5% effective July 1, 2017 

#4 Oil: 0.25% effective July 1, 2017

See: http://regulations.delaware.gov/AdminCode/title7/1000/1100/1108.shtml

Maine Chapter l06: Low Sulfur Fuel

Distillate: 500 ppm effective July 1, 2014; 15 ppm effective July 1, 2018

Residual: 0.5% effective July 1, 2018

See: http://www.mainelegislature.org/legis/bills/bills_124th/billpdfs/SP062701.pdf.

Massachusetts 310 CMR 7.05 (1)(a)1: Table 1 : Sulfur Content Limit of Liquid Fossil Fuel

Distillate: 500 ppm effective July 1, 2014; 15 ppm effective July 1, 2018

Residual: 1.0% effective July 1, 2014; 0.5% effective July 1, 2018

See: http://www.mass.gov/eea/docs/dep/service/regulations/310cmr07.pdf

New Jersey Title 7, Chapter 27, Subchapter 9 Sulfur in Fuels

Distillate: 500 ppm effective July 1, 2014; 15 ppm effective July 1, 2016

Residual: 0.5% or 0.3%, depending on county, effective July 1, 2014

#4 Oil: 0.25% effective July 1, 2014

See: http://www.nj.gov/dep/aqm/rules27.html

New York Subpart 225-1 Fuel Composition and Use - Sulfur Limitations

Distillate: 15 ppm effective July 1, 2016 

Residual: 0.3% in New York City effective July 1, 2014; 0.37% in Nassau, Rockland and Westchester 

counties effective July 1, 2014; 0.5% remainder of state effective July 1, 2016

See: http://www.nyc.gov/html/dep/html/news/dep_stories_p3-109.shtml and 

http://green.blogs.nytimes.com/2010/07/20/new-york-mandates-cleaner-heating-oil/?_r=1 and 

http://switchboard.nrdc.org/blogs/rkassel/governor_paterson_signs_new_la.html

Pennsylvania § 123.22. Combustion units 

Distillate: 500 ppm effective July 1, 2016

Residual: 0.5% effective July 1, 2016 
140

#4 Oil: 0.25% effective July 1, 2016

See: http://www.pacode.com/secure/data/025/chapter123/s123.22.html

Rhode Island Air Pollution Control Regulations No. 8 Sulfur Content of Fuels

Distillate: 500 ppm effective July 1, 2014; 15 ppm effective July 1, 2018 

Residual: 0.5% effective July 1, 2018

See: http://www.dem.ri.gov/pubs/regs/regs/air/air08_14.pdf

Vermont 5-221(1) Sulfur Limitations in Fuel 

Distillate: 500 ppm effective July 1, 2014; 15 ppm effective July 1, 2018

Residual: 0.5% effective July 1, 2018

#4 Oil: 0.25% effective July 1, 2018 

See: http://www.epa.gov/region1/topics/air/sips/vt/VT_Section5_221.pdf

A summary of the sulfur rules by state, with emissions reductions is provided in Table 4-35. Most of these 

reductions (98+%) occur in the nonpt sector; a small amount of reductions occur in the ptnonipm sector 

(approximately 1,600 tons in 2025 and 580 tons in 2017), and a negligible amount of reductions occur in the 

pt_oilgas sector. Note that these reductions are based on intermediate 2017 and 2025 inventories, those 

grown from 2011 to the specific future years. In addition, with implementation (effective) dates after June 

30, 2017 for several of these rules, there are more eligible sources for control in 2025 than 2017.

Table 4-35. Summary of fuel sulfur rule impacts on SO2 emissions

Year

Emissions Eligible

for Control

Controlled (Final)

Emissions Reductions % Reductions

2017 76,177 12,849 63,328 83.1%

2025 99,975 21,172 78,803 78.8%

4.2.4.6 Natural gas turbines NOX NSPS (ptnonipm, pt_oilgas)

Packet:

For 2017: “CONTROL_2011v6.2_2018_NOX_GasTurbines_16dec2014.txt”

For 2025: “CONTROL_2011v6.2_2025_NOX_GasTurbines_16dec2014.txt”

These controls were generated based on examination of emission limits for stationary combustion turbines 

that are not in the power sector. In 2006, EPA promulgated standards of performance for new stationary 

combustion turbines in 40 CFR subpart KKKK. The standards reflect changes in NOX emission control 

technologies and turbine design since standards for these units were originally promulgated in 40 CFR part 

60, subpart GG. The 2006 NSPSs affecting NOX and SO2 were established at levels that bring the emission 

limits up-to-date with the performance of current combustion turbines. Stationary combustion turbines were 

also regulated by the NOX SIP (State Implementation Plan) Call, which required affected gas turbines to 

reduce their NOX emissions by 60 percent. 

Table 4-36 compares the 2006 NSPS emission limits with the NOX RACT regulations in selected states 

within the NOX SIP Call region. The map showing the states and partial-states in the NOX SIP Call Program 

can be found at: http://www3.epa.gov/airmarkets/progress/reports/program_basics.html. We assigned only 

those counties in Alabama, Michigan and Missouri as NOX SIP call based on the map on page 8. The state 

NOX RACT regulations summary (Pechan, 2001) is from a year 2001 analysis, so some states may have 

updated their rules since that time.
141

Table 4-36. Stationary gas turbines NSPS analysis and resulting 2011v6.2 new emission rates used to 

compute controls

NOX Emission Limits for New Stationary Combustion Turbines

Firing Natural Gas

<50 

MMBTU/hr

50-850 

MMBTU/hr

>850 

MMBTU/hr

Federal NSPS 100 25 15 ppm

State RACT Regulations

5-100 

MMBTU/hr

100-250 

MMBTU/hr

>250 

MMBTU/hr

Connecticut 225 75 75 ppm

Delaware 42 42 42 ppm

Massachusetts 65* 65 65 ppm

New Jersey 50* 50 50 ppm

New York 50 50 50 ppm

New Hampshire 55 55 55 ppm

* Only applies to 25-100 MMBTU/hr

Notes: The above state RACT table is from a 2001 analysis. The current NY State regulations have the same 

emission limits.

New source emission rate (Fn) NOX ratio Control (%)

NOX SIP Call states plus CA = 25 / 42 = 0.595 40.5%

Other states = 25 / 105 = 0.238 76.2%

Regarding stationary gas turbine lifetimes, the Integrated Planning Model (IPM) financial modeling 

documentation lists the book life of combustion turbines as 30 years, with a debt life of 15 years, and a US 

MACRS Depreciation Schedule of 15 years (EPA, 2013). This same documentation lists the book life of 

nuclear units at 40 years. IPM uses a 60 year lifetime for nuclear units in its simulations of unit retirements. 

Using the same relationship between estimated lifetime and book life for nuclear units of 1.5, the estimated 

lifetime for a combustion turbine would be 45 years. This is the same as an annual retirement rate of 2.2 

percent.

For projection factor development, the existing source emission ratio was set to 1.0 for combustion turbines. 

The new source emission ratio for the NOX SIP Call states and California is the ratio of state NOX emission 

limit to the Federal NSPS. A complicating factor in the above is the lack of size information in the stationary 

source SCCs. Plus, the size classifications in the NSPS do not match the size differentiation used in state air 

emission regulations. We accepted a simplifying assumption that most industrial applications of combustion 

turbines are in the 100-250 MMBtu/hr size range, and computed the new source emission rates as the NSPS 

emission limit for 50-850 MMBtu/hr units divided by the state emission limits. We used a conservative new 

source emission ratio by using the lowest state emission limit of 42 ppmv (Delaware). This yields a new 

source emission ratio of 25/42, or 0.595 (40.5% reduction) for states with existing combustion turbine 

emission limits. States without existing turbine NOX limits would have a lower new source emission ratio -

the uncontrolled emission rate (105 ppmv via AP-42) divided into 25 ppmv = 0.238 (76.2% reduction). This 

control was then plugged into Equation 2 (see Section 4.2.4) as a function of the year-specific projection 

factor. Resulting controls greater than or equal to 1% were included in our projections. National Process 

Heaters NSPS reductions from projected pre-NSPS 2018 and 2025 inventories are shown in Table 4-37.
142

Table 4-37. National by-sector NOX reductions from Stationary Natural Gas Turbine NSPS controls

Sector

Pre-NSPS Emissions NSPS Reductions NSPS % Reductions

2018 2025 2018 2025 2018 2025

Non-EGU Point 

(ptnonipm) 14,238 15,593 2,400 4,405 17% 28%

Point Oil & Gas 

(pt_oilgas) 70,267 75,310 8,783 24,536 12% 33%

Total 84,505 90,903 11,183 28,941 13% 32%

4.2.4.7 Process heaters NOX NSPS (ptnonipm, pt_oilgas)

Packet:

For 2017: “CONTROL_2011v6.2_2018_NOX_Process_heaters_09dec2014.txt”

For 2025: “CONTROL_2011v6.2_2025_NOX_Process_heaters_09dec2014.txt”

Process heaters are used throughout refineries and chemical plants to raise the temperature of feed materials 

to meet reaction or distillation requirements. Fuels are typically residual oil, distillate oil, refinery gas, or 

natural gas. In some sense, process heaters can be considered as emission control devices because they can 

be used to control process streams by recovering the fuel value while destroying the VOC. The criteria 

pollutants of most concern for process heaters are NOX and SO2. 

In 2011, process heaters have not been subject to regional control programs like the NOX SIP Call, so most 

of the emission controls put in-place at refineries and chemical plants have resulted from RACT regulations 

that were implemented as part of SIPs to achieve ozone NAAQS in specific areas, and refinery consent 

decrees. The boiler/process heater NSPS established NOX emission limits for new and modified process 

heaters. These emission limits are displayed in Table 4-38.

In order to develop a relationship between the typical process heater emission rates in 2011 compared with 

what the NSPS will require of new and modified sources, an analysis of the materials in the EPA docket 

(EPA-HQ-OAR-2007-0011) for the NSPS was performed. This docket contained an EPA memorandum that 

estimated the NOX emissions impacts for process heaters. Table 1 in that memo—titled: Summary of 

Representative Baseline NOX Concentrations for Affected Process Heaters. That analysis can be used to 

establish an effective 2011 process heater NOX emission rate, although the information that EPA-SPPD used 

in the revised NOX impact estimates probably uses data from a few years before 2011. It is likely that the 

data used are representative of 2011 emissions because the only wide-ranging program that has affected 

process heater emission rates recently have been consent decrees, and the emission reductions associated 

with these agreements should have been achieved before 2011. However, the compliance schedules are 

company-specific, and differ by company, so it is difficult to make overarching conclusions about when 

compliance occurred.
143

Table 4-38. Process Heaters NSPS analysis and 2011v6.2 new emission rates used to compute controls

NOX emission rate Existing (Fe) Fraction at this rate

PPMV Average

Natural 

Draft

Forced 

Draft

80 0.4 0

100 0.4 0.5

150 0.15 0.35

200 0.05 0.1

240 0 0.05

Cumulative, weighted: Fe 104.5 134.5 119.5

NSPS Standard 40 60

New Source NOX ratio (Fn) 0.383 0.446 0.414

NSPS Control (%) 61.7 55.4 58.6

EPA states that because it “does not have much data on the precise proportion of process heaters that are 

forced versus natural draft, so the nationwide impacts are expressed as a range bounded by these two 

scenarios”. (Scenario 1 assumes all of the process heaters are natural draft process heaters and Scenario 2 

assumes all of the process heaters are forced draft process heaters.) 

For computations, the existing source emission ratio (Fe) was set to 1.0. The computed (average) NOX

emission factor ratio for new sources (Fn) is 0.41 (58.6% control). The retirement rate is the inverse of the 

expected unit lifetime. There is limited information in the literature about process heater lifetimes. This 

information was reviewed at the time that the Western Regional Air Partnership (WRAP) developed its 

initial regional haze program emission projections, and energy technology models used a 20 year lifetime for 

most refinery equipment. However it was noted that in practice, heaters would probably have a lifetime that 

was on the order of 50 percent above that estimate. Therefore, a 30 year lifetime was used to estimate the 

effects of process heater growth and retirement. This yields a 3.3 percent retirement rate. This control was 

then plugged into Equation 2 (see Section 4.2.4) as a function of the year-specific projection factor. 

Resulting controls greater than or equal to 1% were retained. National Process Heaters NSPS reductions 

from projected pre-NSPS 2018 and 2025 inventories are shown in Table 4-39.

Table 4-39. National by-sector NOX reductions from Process Heaters NSPS controls

Sector

Pre-NSPS Emissions NSPS Reductions NSPS % Reductions

2018 2025 2018 2025 2018 2025

Non-EGU Point 

(ptnonipm) 74,129 75,936 14,200 21,306 19% 28%

Point Oil & Gas 

(pt_oilgas) 7,086 7,170 1,114 1,816 16% 25%

Total 81,215 83,106 15,313 23,123 19% 28%

4.2.4.8 Arizona Regional Haze controls (ptnonipm)

Packet: CONTROL_2011v6.2_20xx_AZ_Regional_Haze_PT_24feb2015.txt

U.S. EPA Region 9 provided regional haze Federal Implementation Plan (FIP) controls for a few industrial 

facilities. Information on these controls are available in the Federal Register (EPA-R09-OAR-2013-0588; 
144

FRL-9912-97-OAR) at http://www.federalregister.com . These non-EGU controls have implementation dates 

between September 2017 and December 2018 and therefore do not reduce emissions in year 2017 

projections. Year 2025 emissions are reduced at 5 smelter and cement units: NOX by 1,722 tons and SO2 by 

26,423 tons.

4.2.4.9 CISWI (ptnonipm)

Packet: CONTROL_CISWI_2011v6_22nov2013.txt

On March 21, 2011, EPA promulgated the revised NSPS and emission guidelines for Commercial and 

Industrial Solid Waste Incineration (CISWI) units. This was a response to the voluntary remand that was 

granted in 2001 and the vacatur and remand of the CISWI definition rule in 2007. In addition, the standards 

re-development included the 5-year technology review of the new source performance standards and 

emission guidelines required under Section 129 of the Clean Air Act (CAA). The history of the CISWI 

implementation is documented here: http://www.epa.gov/ttn/atw/129/ciwi/ciwipg.html. Baseline and CISWI 

rule impacts associated with the CISWI rule are documented here: 

http://www.epa.gov/ttn/atw/129/ciwi/baseline_emission_reductions_memo.pdf. EPA mapped the units from 

the CISWI baseline and controlled dataset to the 2011 NEI inventory and because the baseline CISWI 

emissions and the 2011 NEI emissions were not the same, EPA computed percent reductions such that our 

future year emissions matched the CISWI controlled dataset values. CISWI controls are applied in Arkansas 

and Louisiana only, totaling 3,100 and 3,552 tons of SO2 reductions in years 2017 and 2025 respectively. 

The reductions are greater in year 2025 because they are applied to year-specific projected (grown) 

emissions.

4.2.4.10Data from comments on previous platforms (nonpt, ptnonipm, pt_oilgas)

Packets:

“CONTROL_2011v6.2_20xx_Consent_Decrees_State_comments_2018docket_pt_v2_09mar2015.txt”

“CONTROL_2011v6.2_20xx_State_comments_2018docket_nonpt_15jan2015.txt”

All remaining non-EGU point and nonpoint controls are discussed in this section. For the nonpoint sector, 

these controls are limited to comments/data-responses on the previous (2011v6.0) emissions modeling 

platforms, and the 2018 NODA process. For point sources, controls include data from the 2018 NODA 

process as well as a concatenation of all remaining controls not already discussed. These controls are split 

into separate packets for point and nonpoint sources.

Nonpoint packet: (CONTROL_2011v6.2_20xx_State_comments_2018docket_nonpt_15jan2015.txt)

This packet contains all nonpoint controls not already discussed in previous sections (e.g., Fuel Sulfur rules, 

ICI boilers) provided in response to the 2018 NODA, and is restricted to VOC controls for Delaware, 

Massachusetts, Pennsylvania and Virginia, with the great majority of these controls restricted to Virginia. 

These VOC controls cover various state programs and rules such as Auto refinishing, Adhesives and Surface 

Coatings. Cumulatively, these VOC controls reduce nonpoint VOC by approximately 3,900 tons in 2017 and 

4,100 tons in 2025.

Point packet:

(CONTROL_2011v6.2_20xx_Consent_Decrees_State_comments_2018docket_pt_v2_09mar2015.txt)

This packet contains all point controls not already discussed in previous sections (e.g., Fuel Sulfur rules, ICI 

boilers). This packet includes new controls information provided in response to the 2018 NODA as well as 

“legacy” controls from the 2011v6.0 emissions modeling platform from numerous sources such as settlement 
145

and consent decree data gathering efforts, comments received during the Cross-State Air Pollution Rule

rulemaking process, regional haze modeling, and stack-specific control information provided by TCEQ.

New control information from the 2018 NODA responses is primarily limited to VOC controls from several 

states: Delaware, Massachusetts, New Jersey, Pennsylvania and Virginia. However, we also received 

comments with revised compliance dates, removal of existing control information, and updated controls from 

local settlements. The CONTROL packet comments field provides information on the source of new control 

information, where available. 

The “old” control information includes information discussed in previous emissions modeling platforms; 

these CONTROL packet components are discussed in Section 4.2.9 in the 2011v6.1 emissions modeling 

platform TSD (EPA, 2014b).

Cumulative ptnonipm and pt_oilgas reductions to 2017 and 2025 pre-controlled (projection factors already 

applied) from this CONTROL packet are shown in Table 4-40. While these controls impact both the 

ptnonipm and pt_oilgas sector, almost all reductions are in the ptnonipm sector; pt_oilgas NOX is reduced by 

1,300 tons in 2025, and VOC by 172 tons in 2025. Reductions to pt_oilgas for PM and SO2 are under 100 

tons cumulatively.

Table 4-40. Summary of remaining ptnonipm and pt_oilgas reductions

Year Pollutant

Emissions 

Eligible for 

Control

Controlled 

(Final) 

Emissions Reductions

% 

Reductions

2017 CO 5,783 764 5,019 86.8%

2017 NH3 32 0 32 100.0%

2017 NOX 85,009 42,609 42,401 49.9%

2017 PM10 4,007 1,932 2,075 51.8%

2017 PM2.5 3,582 1,759 1,823 50.9%

2017 SO2 121,735 26,155 95,580 78.5%

2017 VOC 2,741 2,234 507 18.5%

2025 CO 6,092 712 5,380 88.3%

2025 NH3 757 251 505 66.8%

2025 NOX 88,790 43,415 45,375 51.1%

2025 PM10 4,089 1,927 2,162 52.9%

2025 PM2.5 3,642 1,748 1,893 52.0%

2025 SO2 125,367 26,755 98,612 78.7%

2025 VOC 3,145 2,326 819 26.0%

We discovered an error in year 2017 processing for the pt_oilgas sector. We created a second version of the 

point CONTROL packet after processing year 2025, but prior to year 2017. For the “v2” packet, we changed 

the compliance dates from January 1, 2018 to January 1, 2017 for the ptnonipm sector processing because 

compliance dates after June 30, 2017 would not be applied for year 2017 projections. This was applied 

correctly for the ptnonipm sector but the pt_oilgas sector used an older version of the point CONTROL 

packet that had the 1/1/2018 compliance dates. These controls, limited to information provided by TCEQ 

(for Texas) were therefore not applied to the pt_oilgas sector; however, this impact is assumed small 
146

because: 1) the impact was very small in 2025, 2) the pre-controlled emissions in 2025 were larger than 2017 

because of smaller oil and gas growth rates in 2017 than 2025, and 3) it is not clear how many of these stacks 

in the pt_oilgas sector were controlled by other packets as a result. Regarding item 3, recall that the CoST 

hierarchy for applying CONTROL packet information. The intended control data in this packet is very 

specific (stack-level), so it supersedes other possible less-specifically applied control information that could 

apply to several of these stacks, particularly RICE NESHAP (SCC/pollutant-level) and ICI boilers 

(unit/SCC/pollutant-level) control data.

4.2.5 Stand-alone future year inventories (nonpt, ptnonipm)

This section discusses future year NEI non-EGU point and nonpoint emission inventories that were not 

created via CoST strategies/programs/packets. These inventories are either new to the future years because 

they did not exist in 2011 (e.g., new cement kilns, biodiesel and cellulosic plants), or are a complete 

replacement to the year 2011 NEI inventory in the case of portable fuel containers. New non-EGU facilities 

provided by South Carolina via the 2018 NODA on the 2011v6.0 platform were mistakenly omitted from 

both year 2017 and 2025 emissions modeling processing. Cumulatively, these new facilities would have 

added approximately 200 tons of NOX, and under 100 tons of each of the remaining CAPs.

4.2.5.1 Portable fuel containers (nonpt)

Future year inventory:

For 2017: “pfc_2018_2011v6.2_ff10_28jan2015_v0.csv”

For 2025: “pfc_2025_2011v6.2_ff10_28jan2015_v0.csv”

EPA used future-year VOC emissions from Portable Fuel Containers (PFCs) from inventories developed and 

modeled for EPA’s MSAT2 rule (EPA, 2007a). The 6 PFC SCCs are summarized below (note that the full 

SCC descriptions for these SCCs include “Storage and Transport; Petroleum and Petroleum Product Storage” 

as the beginning of the description). 

 2501011011 Residential Portable Fuel Containers: Permeation

 2501011012 Residential Portable Fuel Containers: Evaporation

 2501011014 Residential Portable Fuel Containers: Refilling at the Pump: Vapor Displacement

 2501012011 Commercial Portable Fuel Containers: Permeation

 2501012012 Commercial Portable Fuel Containers: Evaporation

 2501012014 Commercial Portable Fuel Containers: Refilling at the Pump: Vapor Displacement

The future-year emissions reflect projected increases in fuel consumption, state programs to reduce PFC 

emissions, standards promulgated in the MSAT2 rule, and impacts of the RFS2 standards on gasoline 

volatility. EPA developed year 2018 and 2025 PFC emissions that include estimated Reid Vapor Pressure 

(RVP) and oxygenate impacts on VOC emissions, and more importantly, large increases in ethanol 

emissions from RFS2. These emission estimates also include gas can vapor displacement, tank permeation 

and diurnal emissions from evaporation. Because the future year PFC inventories contain ethanol in addition 

to benzene, EPA developed a VOC E-profile that integrated ethanol and benzene; see Section 0 for more 

details. Note that spillage emissions were not projected and were carried forward from 2011. We received 

comments and PFC projections data for year 2018 from MARAMA as part of the 2011v6.0 emissions 

modeling platform NODA (see: http://www.regulations.gov/#!docketDetail;D=EPA-HQ-OAR-2013-0809). 

We used these projection factors to project MARAMA state PFC emissions to year 2018 and then projected

to year 2025 using the existing ratios 2025 to 2018 PFC emissions provided by OTAQ. We used commercial 

software to blend the MARAMA projection factors and existing PFC inventories to create year 2018 and 
147

2025 PFC inventories for this platform. A summary of the resulting PFC emissions for 2011, 2018 (used for 

2017) and 2025 are provided in Table 4-41. 

Table 4-41. PFC emissions for 2011, 2018 and 2025 [tons]

Emissions Difference % Change

2011 2018 2025 2018 2025 2018 2025

VOC 171,963 32,158 37,617 -139,805 -134,347 -81.3% -78.1%

Benzene 742 654 758 -88 15 -11.9% 2.1%

Ethanol 0 3,719 4,448 n/a

4.2.5.2 Biodiesel plants (ptnonipm)

New Future year inventory: “Biodiesel_Plants_2018_ff10”

EPA OTAQ developed an inventory of biodiesel plants for 2018. Plant location and production volume data 

came from the Tier 3 proposed rule.36,37 The total volume of biodiesel came from the AEO 2013 early 

release, 1.3 BG for 2018. To reach the total volume of biodiesel, plants that had current production volumes 

were assumed to be at 100% production and the remaining volume was split among plants with planned 

production. Once facility-level production capacities were scaled, emission factors based on soybean oil 

feedstock were applied. These emission factors in Table 4-42 are in tons per million gallons (Mgal) and were 

obtained from EPA’s spreadsheet model for upstream EISA impacts developed for the RFS2 rule (EPA, 

2010a). Inventories were modeled as point sources with Google Earth and web searching validating facility 

coordinates and correcting state-county FIPS. Table 4-43 provides the 2018 biodiesel plant emissions 

estimates. Since biofuels were not projected to change significantly between 2017 and 2025 the year 2018 

inventory was used for both year 2017 and year 2025. Emissions in 2011 are assumed to be near zero, and 

HAP emissions in 2017 and 2025 are nearly zero.

Table 4-42. Emission Factors for Biodiesel Plants (Tons/Mgal)

Pollutant Emission Factor

VOC 4.3981E-02

CO 5.0069E-01

NOX 8.0790E-01

PM10 6.8240E-02

PM2.5 6.8240E-02

SO2 5.9445E-03

NH3 0

Acetaldehyde 2.4783E-07

Acrolein 2.1290E-07

Benzene 3.2458E-08

1,3-Butadiene 0

Formaldehyde 1.5354E-06

Ethanol 0

 

36 US EPA 2014.Regulatory Impact Analysis for Tier 3 Vehicle Emission and Fuel Standards Program. EPA-420-RD-143-0052. 

37 Cook, R. 2014. Development of Air Quality Reference Case Upstream and Portable Fuel Container Inventories for Tier 3 Final 

Rule. Memorandum to Docket EPA-HQ-OAR-2010-0162.
148

Table 4-43. 2018/2025 biodiesel plant emissions [tons]

Pollutant 2018

CO 649

NOX 1048

PM10 89

PM2.5 89

SO2 8

VOC 57

4.2.5.3 Cellulosic plants (nonpt)

New Future year inventories:

Primary inventory: “2018_cellulosic_inventory”

New Iowa inventory: “cellulosic_new_Iowa_plants_from2018docket_2011v6.2_ff10_28jan2015”

Development of primary inventory

Depending on available feedstock, cellulosic plants are likely to produce fuel through either a biochemical 

process or a thermochemical process. EPA developed county-level inventories for biochemical and 

thermochemical cellulosic fuel production for 2018 to reflect AEO2013er renewable fuel volumes. 

Emissions factors for each cellulosic biofuel refinery reflect the fuel production technology used rather than 

the fuel produced. Emission rates in Table 4-44 and Table 4-45 were used to develop cellulosic plant 

inventories. Criteria pollutant emission rates are in tons per RIN gallon. Emission factors from the cellulosic 

diesel work in the Tier 3 NPRM were used as the emission factors for the thermochemical plants. Cellulosic 

ethanol VOC and related HAP emission factors from the Tier 3 NPRM were used as the biochemical VOC 

and related HAP emission factors. Because the future year cellulosic inventory contains ethanol, a VOC Eprofile that integrated ethanol was used, see Sections 0 and 3.2.1.3 for more details. 

Plants were treated as area sources spread across the entire area of whatever county they were considered to 

be located in. Cellulosic biofuel refinery siting was based on utilizing the lowest cost feedstock, accounting 

for the cost of the feedstock itself as well as feedstock storage and the transportation of the feedstock to the 

cellulosic biofuel refinery. The total number of cellulosic biofuel refineries was projected using volumes 

from AEO2013 (early release). The methodology used to determine most likely plant locations is described 

in Section 1.8.1.3 of the RFS2 RIA (EPA, 2010a). Table 4-46 provides the year 2018 cellulosic plant 

emissions estimates. Since biofuels were not projected to change significantly between 2017 and 2025 the 

year 2018 inventory was used for both year 2017 and year 2025.

Table 4-44. Criteria Pollutant Emission Factors for Cellulosic Plants (Tons/RIN gallon)

Cellulosic Plant 

Type VOC CO NOX PM10 PM2.5 SO2 NH3

Thermochemical 5.92E-07 8.7E-06 1.31E-05 1.56E-06 7.81E-07 1.17E-06 1.44E-10

Biochemical 1.82E-06 1.29E-05 1.85E-05 3.08E-06 1.23E-06 6.89E-07 0
149

Table 4-45. Toxic Emission Factors for Cellulosic Plants (Tons/RIN gallon)

Plant Type Acetaldehyde Acrolein Benzene 1,3-Butadiene Formaldehyde Ethanol

Thermochemical 2.95E-08 1.27E-09 9.61E-10 0 5.07E-09 2.09E-07

Biochemical 3.98E-07 1.11E-08 1.39E-08 0 2.28E-08 6.41E-07

Table 4-46. 2017/2025 cellulosic plant emissions [tons]

Pollutant Emissions

Acrolein 1

Formaldehyde 4

Benzene 1

Acetaldehyde 21

CO 6,088

Ethanol 146

NH3 0.1

NOX 9,199

PM10 1,088

PM2.5 547

SO2 819

VOC 414

Development of new Iowa inventory

Iowa DNR (Department of Natural Resources), via the 2018 NODA comments (see docket # EPA-HQOAR-2013-0809 under http://www.regulations.gov.), provided information on new cellulosic ethanol 

capacity information for three facilities. Emissions for these facilities were computed using the emission 

factors previously discussed in Table 4-44 and Table 4-45. The resulting new facilities and NOX emissions, 

used for both years 2017 and 2025, are provided in Table 4-47. Note that these facilities are in a nonpoint 

inventory because latitude-longitude coordinates were not available.

Table 4-47. New cellulosic plants NOX emissions provided by Iowa DNR.

FIPS County Facility Name

Approximate 

Production 

Capacity 

(Mgal/yr)

NOX

Emissions

19093 Ida Quad County Corn Processors' Adding Cellulosic Ethanol (ACE) 2 26

19147 Palo Alto POET-DSM Project Liberty 25 329

19169 Story DuPont Cellulosic Ethanol 30 394
150

4.2.5.4 New cement plants (nonpt, ptnonipm)

Point Inventories:

For 2017: “cement_newkilns_year2018_from_ISIS2013_NEI2011v1”

For 2025: “cement_newkilns_year_2025_from_ISIS2013_NEI2011v1_08nov2013_v0.csv”

Nonpoint Inventories:

For 2017: “cement_newkilns_year_2018_from_ISIS2013_NEI2011v1_NONPOINT_v0.csv”

For 2025: “cement_newkilns_year_2025_from_ISIS2013_NEI2011v1_NONPOINT_12nov2013_v0.csv”

As discussed in Section 4.2.3.9, the ISMP model, was used to project the cement manufacturing sector to 

future years. This section covers new ISMP-generated kilns that did not exist in the 2011 NEI. For kilns that 

were new in 2018 and/or 2025, EPA used two different approaches for modeling. For kilns already 

permitted, known locations (coordinates) allowed us to process these as point sources. However, the ISMP

model also created “generic” kilns in specific geographically strategic locations (counties) to cover the need 

for increased production/capacity in future years. Because these generic kilns are not permitted and the 

location in these counties is uncertain, EPA decided to model these as county-level to avoid placing large 

emissions sources from a model (ISMP) artifact in one grid cell. These nonpoint source kilns were then 

spatially allocated based on industrial land activity in the county. A list of all new point and nonpoint 

inventory cement kilns in 2018 and 2025 are provided in Table 4-48. Note that as production continues to 

increase beyond 2018, that additional new kilns are needed in 2025. Not shown here is a cement kiln in 

Washington (King county) that ISMP generates but according to Washington Department of Ecology, was

not correct; this kiln was thus removed from our emissions modeling platform.

Table 4-48. Locations of new ISMP-generated cement kilns

Year(s) ISMP ID Permitted? Facility Name FIPS State County

Both FLNEW2 Y Vulcan 12001 FL Aluchua

2025 FLNEW1 Y American Cement Company 12119 FL

Both GANEW1 Y Houston American Cement 13153 GA Houston

Both NCNEW1 Y Titan America LLC 37129 NC New Hanover

Both NewGA2 N n/a 13153 GA Houston

Both NewPA8 N n/a 42011 PA Berks

Both NewSC1 N n/a 45035 SC Dorchester

Both NewTX1 N n/a 48029 TX Bexar

Both NewTX10 N n/a 48091 TX Comal

2025 NewAZ2 N n/a 04025 AZ Yavapai

2025 NewCO2 N n/a 08043 CO Freemont

2025 NewOK2 N n/a 40123 OK Pontotoc

2025 NewPA8 N n/a 42095 PA Northampton

2025 NewTX4 N n/a 48029 TX Bexar

2025 NewTX5 N n/a 48091 TX Comal

2025 NewTX12 N n/a 48209 TX Hays

For all ISMP future year emissions, PM10 is assigned as 0.85 of total PM provided by ISMP, and PM2.5 is 

assigned as 0.15 of total PM. All new ISMP-generated kilns, point and nonpoint format, are assigned as 

Precalciner kilns (SCC=30500623). While ISMP provides emissions for mercury, EPA did not retain these in 
151

our modeling. Table 4-49 shows the magnitude of the new ISMP-based cement kilns. We split out ISMPbased new kilns in future years with permitted (as of August 2013) kilns modeled as point sources and 

“generic” ISMP-generated kilns as nonpoint sources. 

Table 4-49. ISMP-generated new permitted and non-permitted emissions

New kilns in 2018 New kilns in 2025 Total New ISMP Emissions

Permitted 

(point)

ISMPgenerated 

(nonpoint)

Permitted 

(point)

ISMPgenerated 

(nonpoint) 2018 2025

NOX 3,751 5,697 4,795 13,673 8,546 19,370

PM2.5 8 24 11 57 19 81

SO2 1,775 13 2,004 30 3,779 43

VOC 91 2,969 117 7,115 208 10,084

4.3 Mobile source projections

Mobile source monthly inventories of onroad and nonroad mobile emissions were created for 2017 and 2025 

using a combination of the MOVES2014 and the NMIM models. The 2017 and 2025 onroad emissions 

account for changes in activity data and the impact of on-the-books rules including some of the recent 

regulations such as the Light Duty Vehicle GHG Rule for Model-Year 2017-2025, and the Tier 3 Motor 

Vehicle Emission and Fuel Standards Rule (http://www.epa.gov/otaq/tier3.htm). Local inspection and 

maintenance (I/M) and other onroad mobile programs are included such as California LEVIII, the National 

Low Emissions Vehicle (LEV) and Ozone Transport Commission (OTC) LEV regulations

(http://www.epa.gov/otaq/lev-nlev.htm), local fuel programs, and Stage II refueling control programs. Table 

4-1 provides references to many of these programs.

Nonroad mobile emissions reductions for these years include reductions to various nonroad engines such as

diesel engines and recreational marine engine types (pleasure craft), fuel sulfur content, and evaporative 

emissions standards.

Onroad mobile sources are comprised of several components and are discussed in the next subsection (4.3.1). 

Monthly nonroad equipment mobile emission projections are discussed in subsection 4.4. Locomotives and 

Category 1 and Category 2 commercial marine vessel (C1/C2 CMV) projections were discussed in Section 

4.2.3.3, and Category 3 (C3) CMV projections were discussed in Section 4.2.3.4.

4.3.1 Onroad mobile (onroad)

The onroad emissions for 2017 and 2025 use the same SMOKE-MOVES system as for the base year (see 

Sections 2.3.1). Meteorology, speed, spatial surrogates and temporal profiles, representative counties, and 

fuel months were the same as for 2011. EPA had already performed many of the modeling steps to produce 

2018 emissions, when the NRDC v. EPA 38 decision resulted in 2017 being the last full ozone season to 

consider for moderate nonattainment designations with respect to the 2008 ozone NAAQS. To 

accommodate this change within the time available, a two-step process was undertaken for onroad (and 

nonroad): (1) estimate the emissions for 2018 at a full detailed level (see Sections 4.3.1.1and 4.3.1.2), and (2) 

adjust the 2018 emissions to 2017 (see Section 4.3.1.3). 

 

38 D.C. Circuit Court’s decision in NRDC v. EPA, 777 F.3dFD 456, 469 (D.C. Cir. 2014).
152

4.3.1.1 Future activity data

Estimates of total national Vehicle Miles Travelled (VMT) in 2018 and 2025 came from DOE's Annual 

Energy Outlook (AEO) 2014 (http://www.eia.gov/forecasts/aeo/) transportation projections, specifically the 

reference case that was released on May 7, 2014. Trends were developed by calculating ratios between 2011 

AEO and 2018 AEO39 estimates and applying the trends to the 2011NEIv2 VMT. These ratios were 

developed for light versus heavy duty and for four fuel types: gasoline, diesel, E-85, and CNG. This same 

method was used to project 2011NEIv2 VMT to 2025 with the incorporation of 2025 AEO estimates. The 

projection factors, the national 2011NEIv2 VMT (“VMT_2011”) by broad vehicle and fuel type, and the 

default future VMT (“VMT_2018” and VMT_2025”) are show in Table 4-50.

Table 4-50. Projection factors for 2018 and 2025 VMT (in millions of miles)40

Classification MOVES source types VMT 2011 Ratio 2018 VMT 2018 Ratio 2025 VMT 2025

LD gas 11,21,31,32 2,565,979 1.0154 2,605,570 1.0466 2,685,656

HD gas 42,43,51,52,53,54 21,530 1.0598 22,817 1.0880 23,425

HHD gas 61 10 0.7997 8 0.8414 9

LD diesel 21,31,32 41,645 3.0647 127,631 6.3858 265,938

HD diesel 41,42,43,51,52,53,54 58,995 1.1959 70,551 1.3621 80,357

HHD diesel 61,62 131,706 1.1709 154,216 1.3296 175,120

Bus CNG 42 303 2.1065 639 3.7099 1,125

LD E-85 21,31,32 143,600 1.8800 269,963 2.3570 338,463

Total N/A 2,963,768 N/A 3,251,394 N/A 3,570,094

In the above table, light duty (LD) includes passenger cars, light trucks, and sometimes motorcycles, heavy 

duty (HD) includes buses and single unit trucks, and heavy-heavy duty (HHD) includes combination trucks. 

The specific MOVES source type codes are listed above. These national SCC6 ratios were applied to the 

2011NEIv2 VMT to create an EPA estimate of 2018 and 2025 VMT at the county, SCC level. 

Two additional steps were incorporated into the VMT projections. First, a set of states provided 2018 VMT 

projections41: AL, CT, GA, ME, MD, MA, MI, MO, NV, NY, NJ, NC, UT, VT, VA, and WY42. The state 

provided VMT projections were used over the EPA default projections in those specific counties. Second, 

EPA adjusted the national LD ratios so that it would reflect regional differences in growth rate. EPA 

analyzed LD VMT and corroborated that it had a high correlation with human population. Therefore, if a 

region has strong human population growth in the future, it will likely have larger VMT growth than the 

national average. To take account of this spatial difference in growth, EPA used human population to adjust 

 

39 By “2011 AEO,” “2018 AEO,” and “2025 AEO,” this refers to the AEO2014’s estimates of national VMT in those specific 

calendar years.

40 Note: these are the default VMT values. The actual VMT used for 2018 and 2025 has slightly different VMT values. This is 

due to some states providing VMT projections for 2018. In addition, the LD ratios were further adjusted to take into account of 

high vs low growth of human population (discussed below). On average, the LD ratios match those in this table. For the actual 

VMT, see the inventory packaged with the cases.

41 Although some states provided 2018 specific VMT projections, these projections were not consistently available for 2025. 

Therefore, state projections were not incorporated into the 2025 modeling.

42 For many of these states, we used the county total from the state data and distributed those totals to EPA’s SCCs based on 

default projected VMT. For MI, SEMCOG provided the Detroit projections and the rest of the counties came from the state. For 

MO, the state provided the 5 counties around St Louis. For Nevada, EPA received projections only for Clark County. For GA, the 

state agreed with our default projection method but they wanted to use GA provided human population projections for distributing 

the LD VMT growth rates to counties. They provided the human population for the 21 Atlanta counties. For the remaining 

counties, GA asked to use EPA defaults.
153

the national LD VMT growth rate so that on average the growth rate matched the national average, but any 

specific county growth rate was adjusted by the human population growth for that county:

VMTprojFactorsc = AEOprojFactors ∗ (1 + D((

humanProjFactorc

natlhumanProjFactor) − 1))

where

◦ s = source type/fuel

◦ c = county

◦ VMTprojFactor = county VMT projection factor (by source/fuel)

◦ AEOprojFactor = national VMT projection factor from AEO (by source/fuel)

◦ humanProjFactor = human projection factor for the county (year specific)

◦ natlhumanProjFactor = national human projection factor (year specific)

◦ D = damping factor, 0 = no county adjustment, 1 = full county variation

The specific value of D used for EPA projections was 0.5. This was based on an analysis of the growth of 

LD vehicles over time as compared to human population, which was found to be about 0.5 vehicles per 

person. The LD growth rates will vary by county, fuel, and year. The range of these growth rates are shown 

in Figure 4-4.

Vehicle population (VPOP) was developed by creating VMT/VPOP ratios from the 2011NEIv2 VMT and 

2011NEIv2 VPOP at the county, fuel and vehicle type (SCC6) level. These ratios were applied to the 2018 

VMT to create a 2018 VPOP. This process was repeated using the 2025 VMT to create the 2025 VPOP. 

Hoteling (HOTELING) was developed by creating VMT/HOTELING ratios from the 2011 NEIv2 VMT and 

2011 NEIv2 HOTELING at the county level. For these ratios, the VMT was limited to combination longhaul trucks (SCC6 220262). The HOTELING was the total of auxiliary power units (APU) and extended 

idle (EXT). These ratios were applied to the 2018 VMT to create a 2018 HOTELING. To get the APU split, 

16% of HOTELING was assumed to be APU in all counties. This is consistent with MOVES2014 default 

split for APU for calendar year 2018. This process was repeated using the 2025 VMT to create the 2025 

HOTELING. An APU split of 25% was used in 2025.
154

Figure 4-4. Light Duty VMT growth rates

4.3.1.2 Set up and Run MOVES to create EFs

Emission factor tables were created by running SMOKE-MOVES using the same procedures and models as 

described for 2011 (see the 2011NEIv2 TSD and Section 2.3). The same meteorology and the same 

representative counties were used. Changes between 2011 and future years (2018 or 2025) are predominantly 

activity data, fuels, national and local rules, and age distributions. Age (i.e., model year) distributions were 

projected forward using the methodology described in the MOVES activity report (EPA, 2015), although 

some states supplied age distributions in their CDBs. Fleet turnover resulted in a greater fraction of newer 

vehicles meeting stricter emission standards. The similarities and differences between the two runs are 

described in Table 4-51.

Table 4-51. Inputs for MOVES runs for 2018 and 2025

Element 2017 2025

Code MOVES20141021cb6 MOVES20141021cb6

Default 

database movesdb20141021cb6 movesdb20141021cb6

VMT and 

VPOP 2011 NEIv2 2011 NEIv2

Hydrocarbon 

speciation Done inside MOVES Done inside MOVES

Fuels movesdb20141021_fuelsupply movesdb20141021_fuelsupply

CA LEVIII ca_standards_SS_20140903

(16 states)

ca_standards_SS_20140903

(16 states)

The following states were modeled as having adopted the California LEV III program (see Table 4-52):

0

1

2

3

4

5

6

7

8

9

2018 gas 2025 gas 2018 diesel 2025 diesel 2018 e85 2025 e85

Growth Rate

Range of LD VMT growth rates
155

Table 4-52. CA LEVIII program states

FIPS State Name

06 California

09 Connecticut

10 Delaware

23 Maine

24 Maryland

25 Massachusetts

34 New Jersey

36 New York

41 Oregon

42 Pennsylvania

44 Rhode Island

50 Vermont

53 Washington

Fuels were projected into the future using estimates from the AEO2014 (http://www.eia.gov/forecasts/aeo/), 

release date May 7

th 2014, as well as fuel properties changing as part of the Tier 3 Emissions and Fuel 

Standards Program (http://www.epa.gov/otaq/tier3.htm). The AEO2014 projection includes market shares of 

E10, E15, and E85 in 2018, as well as biodiesel market shares up to B5 (note that these values do not assume 

full implementation of the RFS2 program). The regional fuel properties and renewable volumes in 2011 were 

projected to 2018 in order to preserve the regional variation present in these fuel supplies, with total fuel 

volumes aligned to those in the AEO2014. Due to similarities between fuel volumes an in order to simplify 

analysis, the 2025 fuels were identical to the 2018 fuels. For details on the 2018 and 2025 speciation of 

onroad mobile source emissions, which is dependent on the fuels, see Section 3.2.1.4.

4.3.1.3 National and California adjustments

A set of adjustments were done in SMOKE-MOVES to create 2017 and 2025 emissions: 1) refueling, 

2) California emissions, and 3) 2017 adjustments.

The first set of adjustment factors was for refueling. This uses the same approach as was used in 2011 (see 

the Section 2.3.1 for details) to take account of the few counties in Colorado that provided point source gas 

refueling emissions. These adjustments essentially zero out the MOVES-based gasoline refueling emissions 

(SCC 2201*62) in these counties so that the point estimates will be used instead.

The second set of adjustment factors was used to incorporate future year emissions provided by California. 

The same approach as was used in 2011 was used to match the emissions totals provided by CARB (see 

Section 2.3.1). The only differences between the 2011 approach and that applied for 2017 are that the latter 

uses the 2017 emissions provided by CARB and the 2018 EPA SMOKE-MOVES output to apportion and 

temporalize the emissions. For 2025, the process was repeated using 2025 emissions provided by CARB and 

the 2025 SMOKE-MOVES output for the EPA estimates. The provided CARB emissions were produced 

from working draft versions of EMFAC2011-LD and EMFAC2011-HD and include the following heavy 

duty regulations: chip reflash, extended idling, public fleet, trash trucks, drayage trucks, and trucks and 

buses. It does not include the GHG/smartway regulations for trucks, or the low carbon fuel standard. The 

California adjustment factors are by county, comparison SCC6, pollutant and impact all processes (RPD, 

RPV, RPH, and RPP).
156

The third set of adjustment factors adjusted 2018 emissions to 2017 levels. EPA ran MOVES2014 in 

inventory mode at the national level to create a 2017 inventory and a 2018 inventory. Each inventory was 

then divided by the respective year’s VMT to create a 2017 emissions rate and a 2018 emissions rate. EPA 

calculated ratios of 2017 to 2018 by SCC and pollutant and applied them nationally at the SCC and pollutant 

level to adjust the SMOKE-MOVES results from 2018 to 2017. Separate ratios were calculated for the 

winter fuel months and the summer fuel months. The exception to this adjustment was in California, where 

CARB emissions were used to adjust the emissions (see above). 

Because these adjustment factors are multiplicative, a single set of adjustment factors was created by 

multiplying the three adjustment factors together while taking care to match process (RPD, RPV, RPH, or 

RPP), pollutant, SCC, and county. Movesmrg applied the composite adjustment factor file (CFPRO) to 

compute 2017 or 2025 emissions that incorporated the appropriate adjustments for that case, county, SCC, 

and process.

4.4 Nonroad mobile source projections (nonroad)

The projection of locomotives and Category 1 and 2 commercial marine vessels to 2017 and 2025 is 

described in 4.2.3.3. The projection of the larger Category 3 commercial marine vessels is described in 

Section 4.2.3.4. Most of the remaining sources in the nonroad sector are projected by running the NMIM 

model with fuels and vehicle populations appropriate to 2018 and 2025; this section describes the projection 

of these sources. Similar to onroad, EPA adjusted the 2018 modeled emissions to 2017 levels.

This sector includes monthly exhaust, evaporative and refueling emissions from nonroad engines (not 

including commercial marine, aircraft, and locomotives) derived from NMIM for all states except California

and Texas. NMIM provides nonroad emissions for VOC by three emission modes: exhaust, evaporative and 

refueling.

With the exception of California and Texas, U.S. emissions for the nonroad sector (defined as the equipment 

types covered by the NONROAD model) were created using a consistent NMIM-based approach as was 

used for 2011. Specifically, NMIM utilized NONROAD2008a including future-year equipment population 

estimates, control programs to the years 2018 and 2025, and inputs were either state-supplied as part of the 

2011NEIv1 and 2011NEIv2 process or national level inputs. Fuels for 2018 and 2025 were assumed to be 

E10 everywhere for nonroad equipment. The fuels were developed from the MOVES fuels, which in turn 

were developed to be consistent with AEO2013 projections for 2018 and 2025. The AEO version is slightly 

older because nonroad projections were not updated for the 2011NEIv2. The databases used in the 2018 run 

were NMIM county database “NCD20130731_nei2018dv1” and fuels database 

“tier3frm2018ctrlfuels_03152013_ e10fuelsNMIM.” The 2018 and 2025 emissions account for changes in 

activity data (based on NONROAD model default growth estimates of future-year equipment population)

and changes in fuels and engines that reflect implementation of national regulations and local control 

programs that impact each year differently due to engine turnover. For details on the 2018 and 2025 

speciation of nonroad, see Section 3.2.1.4.

The version of NONROAD used was the current public release, NR08a, which models all in-force nonroad 

controls. The represented rules include:

 “Clean Air Nonroad Diesel Final Rule - Tier 4”, published June, 2004: 

http://www.epa.gov/otaq/nonroad-diesel.htm

 Control of Emissions from Nonroad Large Spark-Ignition Engines, and Recreational Engines (Marine 

and Land-Based), November 8, 2002 (“Pentathalon Rule”).
157

 Small Engine Spark Ignition (“Bond”) Rule, October, 2008: http://www.epa.gov/otaq/smallsi.htm

Not included are voluntary local programs such as encouraging either no refueling or evening refueling on 

Ozone Action Days.

To adjust 2018 emissions to 2017 levels, EPA ran NONROAD at the national level to create a 2017 

inventory and a 2018 inventory. EPA calculated ratios of 2017 to 2018 by SCC and pollutant. These ratios 

were applied nationally at the SCC, mode, and pollutant level to adjust the NONROAD results from 2018 to 

2017. Separate ratios were calculated for the winter fuel months versus the summer fuel months. The 

exception to this adjustment was in California, where CARB emissions were used to adjust the emissions 

(see below).

California and Texas nonroad emissions

Similar to the 2011 base year nonroad mobile, NMIM was not used to generate future-year nonroad 

emissions for California, other than for NH3. EPA used NMIM for California future nonroad NH3 emissions 

because CARB did not provide these data for any nonroad vehicle types. For the rest of the pollutants, the 

CARB-supplied 2017 and 2025 nonroad annual inventories were distributed to monthly emissions values by 

using the respective year 2018 and 2025 NMIM monthly inventories to compute monthly ratios by county, 

SCC7, mode and pollutant, which was consistent with the approach in 2011 (see Section 2.4.3). Some 

adjustments to the CARB inventory were needed to convert the provided TOG to VOC. See Section 3.2.1.3

for details on speciation of California nonroad data see Section 3.2.1.3)

43

. The CARB nonroad emissions 

include nonroad rules reflected in the December 2010 Rulemaking Inventory 

(http://www.arb.ca.gov/regact/2010/offroadlsi10/offroadisor.pdf) and those in the March 2011 Rule 

Inventory, the Off-Road Construction Rule Inventory for “In-Use Diesel”.

For Texas, EPA combined Texas’ submitted estimates for 2011 with EPA projections of nonroad emissions 

into 2017 and 2025. Conceptually, EPA used the trend of 2011 to 2017 or 2025 based on EPA’s estimates to 

project Texas’ submitted emissions for 2011. Specifically, projections were based on state-wide SCC7, 

mode, poll ratios44 of 2017 and 2025 NMIM to 2011 NMIM. These ratios were then applied to Texas’ 

submitted 2011 nonroad emissions, which had already been distributed to a monthly inventory (see Section 

2.4.3), to create 2018 and 2025 monthly nonroad inventories.

4.5 “Other Emissions”: Offshore Category 3 commercial marine 

vessels and drilling platforms, Canada and Mexico (othpt, othar, and 

othon)

As described in Section 2.5, emissions from Canada, Mexico, and non-U.S. offshore Category 3 Commercial 

Marine Vessels (C3 CMV) and drilling platforms are included as part of three emissions modeling sectors:

othpt, othar, and othon. For oil drilling platforms, EPA used emissions from the 2011NEIv2 point source 

inventory for 2011 and both future years. Environment Canada did not provide any future-year emissions 

that were consistent with the 2010 base year emissions, therefore emissions for Canada were not projected to 

 

43 In addition, airport equipment was removed from CARB’s inventory because these sources were modeled elsewhere.

44 These ratios were initially attempted by county/SCC7/mode/pollutant, but due to significantly different distributions of certain 

source types between EPA and TCEQ’s emissions, this created unreasonable growth in certain areas. The above approach was 

used except in the following, relatively limited conditions. If a state/SCC7/mode/pollutant was in EPA 2017 and 2025 emissions 

but not in EPA’s 2011 emissions, 2017 and 2025 EPA emissions were used in the final inventory. If a state/SCC7/mode/pollutant 

was in TCEQ’s 2011 emissions but was not in EPA’s 2017 and 2025 emissions, then state/SCC3/mode/pollutant ratios were used 

to project to 2017 and 2025.
158

future years and are the same as those used in the 2011 base case. Emissions for Mexico are based on the 

Inventario Nacional de Emisiones de Mexico, 2008 projected to years 2018 and 2025 (ERG, 2014a). 

As discussed in Section 2.5.1, the ECA-IMO-based C3 CMV emissions outside of U.S. state waters are 

processed in the othpt sector. This enables shipping lanes to be represented and for emissions to be treated 

as elevated sources. These C3 CMV emissions include those assigned to the Exclusive Economic Zone 

(defined as those emissions just beyond U.S. waters approximately 3-10 miles offshore, extending to about 

200 nautical miles from the U.S. coastline), and all other offshore emissions. The projection factors for the 

othpt C3 CMV emissions vary by geographic and region as shown in Table 4-8. 
159

5 Emission Summaries

The following tables summarize emissions differences between the 2011 evaluation case, the 2017 base case, 

and the 2025 base case. These summaries are provided at the national level by sector for the contiguous U.S. 

and for the portions of Canada and Mexico inside the smaller 12km domain (12US2) discussed in Section 

3.1. The afdust sector emissions represent the summaries after application of both the land use (transport 

fraction) and meteorological adjustments (see Section 2.2.1); therefore, this sector is called “afdust_adj” in 

these summaries. The onroad sector totals are post-SMOKE-MOVES totals, representing air quality modelready emission totals, and include CARB emissions for California. The c3marine sector includes U.S. 

emissions within state waters only; these extend to roughly 3-5 miles offshore and includes CMV emissions 

at U.S. ports. “Offshore to EEZ” represents CMV emissions that are within the (up to) 200 nautical mile 

Exclusive Economic Zone (EEZ) boundary but are outside of U.S. state waters along with the offshore oil 

platform emissions from the NEI. Finally, the “Non-US SECA C3” represents all non-U.S. and non-Canada 

emissions outside of the (up to) 200nm offshore boundary, including all Mexican CMV emissions. Canadian 

CMV emissions are included in the othar sector. 

National emission totals by air quality model-ready sector are provided for all CAP emissions for the 2011

evaluation case in Table 5-1. The total of all sectors in the 2011 evaluation case are listed as “Con U.S. 

Total”. Table 5-2 provides national emissions totals by sector for CAPs in the 2017 base case. Table 5-3

provides national emissions totals by sector for CAPs in the 2025 base case.

Table 5-4 provides national-by sector emission summaries for CO for all the cases: 2011 evaluation case, 

2017 base case, and 2025 base case, with percent change from 2011 to 2017 and 2011 to 2025. Table 5-5

through Table 5-10 provide the same summaries for NH3, NOX, PM2.5, PM10, SO2 and VOC, respectively. 

Note that the same fire emissions are used in all cases.
160

Table 5-1. National by-sector CAP emissions summaries for the 2011 evaluation case

Sector CO NH3 NOX PM10 PM2.5 SO2 VOC

afdust_adj 6,735,072 923,938

ag 3,515,198

agfire 956,243 3,321 42,767 140,728 93,959 16,224 74,783

c1c2rail 180,579 511 1,075,217 35,359 33,019 12,609 48,281

nonpt 1,645,989 94,242 720,454 491,825 404,258 275,655 3,672,249

np_oilgas 627,609 0 647,169 16,843 15,333 18,306 2,556,649

nonroad 13,951,020 2,627 1,630,301 162,417 154,657 4,031 2,024,419

onroad 26,313,827 120,805 5,719,979 367,667 194,690 29,665 2,709,470

c3marine 12,532 68 131,382 10,168 9,043 86,373 5,149

ptprescfire 10,063,500 161,999 167,599 1,060,130 900,546 83,082 2,313,404

ptwildfire 10,499,197 167,331 165,799 1,111,857 943,717 82,691 2,374,690

ptegu 777,902 24,925 2,088,233 281,614 206,884 4,662,717 36,336

ptnonipm 2,312,304 66,192 1,222,456 478,885 322,142 1,057,242 802,988

pt_oilgas 235,162 5,947 509,856 14,585 13,935 66,577 164,098

rwc 2,517,844 19,693 34,436 381,476 381,252 8,954 442,541

Con U.S. Total 70,093,709 4,182,859 14,155,649 11,288,626 4,597,374 6,404,125 17,225,056

Off-shore to EEZ* 175,353 185 899,986 26,247 24,544 139,169 81,602

Non-US SECA C3 17,184 0 202,432 17,206 15,828 127,579 7,294

Canada othafdust 779,674 112,523

Canada othar 3,015,606 326,610 361,896 158,996 131,114 70,272 886,456

Canada othon 3,032,005 18,653 345,664 17,628 12,216 1,701 178,431

Canada othpt** 496,083 13,069 266,912 70,005 29,165 544,502 129,119

Mexico othar 277,810 163,040 182,869 98,812 50,158 10,679 410,734

Mexico othon 3,361,123 7,978 243,714 2,425 1,624 4,919 319,353

Mexico othpt 153,061 3,706 286,303 55,162 42,105 453,466 53,813

Non-US Total 10,528,225 533,241 2,789,775 1,226,156 419,276 1,352,287 2,066,802

* “Offshore to EEZ” includes both the offshore point emissions, and the “Offshore to EEZ” c3marine emissions
161

Table 5-2. National by-sector CAP emissions summaries for the 2017 base case

Sector CO NH3 NOX PM10 PM2.5 SO2 VOC

afdust_adj 7,093,387 964,080

ag 3,577,123

agfire 956,243 3,321 42,767 140,728 93,959 16,224 74,783

c1c2rail 194,109 513 915,797 25,970 24,245 1,161 34,528

nonpt 1,673,888 94,816 734,072 494,930 416,334 104,585 3,511,392

np_oilgas 677,087 0 687,307 21,112 19,420 37,505 3,164,559

nonroad 12,371,786 2,857 1,129,911 113,568 107,267 1,856 1,422,907

onroad 15,607,769 88,774 3,150,751 302,041 124,930 14,985 1,507,880

c3marine 15,600 68 131,691 1,729 1,531 3,904 6,429

ptprescfire 10,063,500 161,999 167,599 1,060,130 900,546 83,082 2,313,404

ptwildfire 10,499,197 167,331 165,799 1,111,857 943,717 82,691 2,374,690

ptegu 820,402 41,275 1,547,987 279,931 212,913 1,462,200 40,433

ptnonipm 2,357,260 66,496 1,192,297 480,114 325,400 807,093 814,400

pt_oilgas 216,480 5,887 411,055 14,013 13,379 69,034 165,559

rwc 2,504,587 19,546 35,507 384,041 383,807 8,814 437,984

Con U.S. Total 57,957,907 4,230,006 10,312,541 11,523,551 4,531,527 2,693,133 15,868,951

Off-shore to EEZ* 186,196 185 855,139 10,237 9,768 9,945 86,093

Non-US SECA C3 22,335 0 239,528 22,313 20,527 165,925 9,462

Canada othafdust 779,674 112,523

Canada othar 3,015,606 326,610 361,896 158,996 131,114 70,272 886,456

Canada othon 3,032,005 18,653 345,664 17,628 12,216 1,701 178,431

Canada othpt** 496,083 13,069 266,912 70,005 29,165 544,502 129,119

Mexico othar 299,511 166,412 199,951 103,086 53,005 11,930 470,910

Mexico othon 2,068,792 10,044 164,555 2,565 1,697 1,943 218,848

Mexico othpt 186,436 4,904 348,544 64,263 49,790 363,306 68,970

Non-US Total 9,306,964 539,877 2,782,187 1,228,767 419,805 1,169,524 2,048,288
162

Table 5-3. National by-sector CAP emissions summaries for the 2025 base case

Sector CO NH3 NOX PM10 PM2.5 SO2 VOC

afdust_adj 7,621,008 1,023,169

ag 3,610,283

agfire 956,243 3,321 42,767 140,728 93,959 16,224 74,783

c1c2rail 215,196 514 679,934 17,679 16,507 888 24,498

nonpt 1,695,259 94,957 746,389 511,976 431,038 95,195 3,426,386

np_oilgas 721,546 0 717,783 25,266 22,439 38,913 3,478,495

nonroad 13,299,524 3,543 794,770 77,615 72,788 2,088 1,179,395

onroad 10,444,934 85,521 1,707,692 280,816 83,019 13,759 904,713

c3marine 20,988 68 104,503 2,335 2,075 5,272 8,687

ptprescfire 10,063,500 161,999 167,599 1,060,130 900,546 83,082 2,313,404

ptwildfire 10,499,197 167,331 165,799 1,111,857 943,717 82,691 2,374,690

ptegu 903,766 46,007 1,435,523 274,544 208,678 1,471,933 41,795

ptnonipm 2,440,880 66,698 1,229,333 487,373 333,048 800,678 826,684

pt_oilgas 254,080 5,922 464,256 16,859 16,381 69,560 190,788

rwc 2,323,717 18,150 34,722 355,849 355,599 7,606 408,336

Con U.S. Total 53,838,831 4,264,314 8,291,070 11,984,034 4,502,962 2,687,889 15,252,654

Off-shore to EEZ* 210,270 185 666,757 9,313 8,799 12,165 94,501

Non-US SECA C3 31,937 0 296,532 7,029 6,407 43,104 13,563

Canada othafdust 779,674 112,523

Canada othar 3,015,606 326,610 361,896 158,996 131,114 70,272 886,456

Canada othon 3,032,005 18,653 345,664 17,628 12,216 1,701 178,431

Canada othpt** 496,083 13,069 266,912 70,005 29,165 544,502 129,119

Mexico othar 316,038 168,218 218,022 105,952 55,152 13,454 526,197

Mexico othon 2,167,729 13,338 116,490 3,196 2,104 1,351 198,850

Mexico othpt 204,038 5,975 387,578 74,454 57,000 360,401 85,703

Non-US Total 9,473,705 546,048 2,659,850 1,226,247 414,482 1,046,952 2,112,821
163

Table 5-4. National by-sector CO emissions (tons/yr) summaries and percent change

Sector 2011 CO 2017 CO 2025 CO

% change 

2011 to 2017

% change 

2011 to 2025

afdust_adj 0 0 0 0% 0%

ag 0 0 0 0% 0%

agfire 956,243 956,243 956,243 0% 0%

c1c2rail 180,579 194,109 215,196 7% 19%

nonpt 1,645,989 1,673,888 1,695,259 2% 3%

np_oilgas 627,609 677,087 721,546 8% 15%

nonroad 13,951,020 12,371,786 13,299,524 -11% -5%

onroad 26,313,827 15,607,769 10,444,934 -41% -60%

c3marine 12,532 15,600 20,988 24% 67%

ptprescfire 10,063,500 10,063,500 10,063,500 0% 0%

ptwildfire 10,499,197 10,499,197 10,499,197 0% 0%

ptegu 777,902 820,402 903,766 5% 16%

ptnonipm 2,312,304 2,357,260 2,440,880 2% 6%

pt_oilgas 235,162 216,480 254,080 -8% 8%

rwc 2,517,844 2,504,587 2,323,717 -1% -8%

Con U.S. Total 70,093,709 57,957,907 53,838,831 -17% -23%

Off-shore to EEZ* 175,353 186,196 210,270 6% 20%

Non-US SECA C3 17,184 22,335 31,937 30% 86%

Canada othafdust 0 0 0 0% 0%

Canada othar 3,015,606 3,015,606 3,015,606 0% 0%

Canada othon 3,032,005 3,032,005 3,032,005 0% 0%

Canada othpt** 496,083 496,083 496,083 0% 0%

Mexico othar 277,810 299,511 316,038 8% 14%

Mexico othon 3,361,123 2,068,792 2,167,729 -38% -36%

Mexico othpt 153,061 186,436 204,038 22% 33%

Non-US Total 10,528,225 9,306,964 9,473,705 -12% -10%
164

Table 5-5. National by-sector NH3 emissions (tons/yr) summaries and percent change

Sector 2011 NH3 2017 NH3 2025 NH3

% change 

2011 to 2017

% change 

2011 to 2025

afdust_adj 0 0 0 0% 0%

ag 3,515,198 3,577,123 3,610,283 2% 3%

agfire 3,321 3,321 3,321 0% 0%

c1c2rail 511 513 514 0% 1%

nonpt 94,242 94,816 94,957 1% 1%

np_oilgas 0 0 0 0% 0%

nonroad 2,627 2,857 3,543 9% 35%

onroad 120,805 88,774 85,521 -27% -29%

c3marine 68 68 68 0% 0%

ptprescfire 161,999 161,999 161,999 0% 0%

ptwildfire 167,331 167,331 167,331 0% 0%

ptegu 24,925 41,275 46,007 66% 85%

ptnonipm 66,192 66,496 66,698 0% 1%

pt_oilgas 5,947 5,887 5,922 -1% 0%

rwc 19,693 19,546 18,150 -1% -8%

Con U.S. Total 4,182,859 4,230,006 4,264,314 1% 2%

Off-shore to EEZ* 185 185 185 0% 0%

Non-US SECA C3 0 0 0 0% 0%

Canada othafdust 0 0 0 0% 0%

Canada othar 326,610 326,610 326,610 0% 0%

Canada othon 18,653 18,653 18,653 0% 0%

Canada othpt** 13,069 13,069 13,069 0% 0%

Mexico othar 163,040 166,412 168,218 2% 3%

Mexico othon 7,978 10,044 13,338 26% 67%

Mexico othpt 3,706 4,904 5,975 32% 61%

Non-US Total 533,241 539,877 546,048 1% 2%
165

Table 5-6. National by-sector NOx emissions (tons/yr) summaries and percent change

Sector 2011 NOX 2017 NOX 2025 NOX

% change 

2011 to 2017

% change 

2011 to 2025

afdust_adj 0 0 0 0% 0%

ag 0 0 0 0% 0%

agfire 42,767 42,767 42,767 0% 0%

c1c2rail 1,075,217 915,797 679,934 -15% -37%

nonpt 720,454 734,072 746,389 2% 4%

np_oilgas 647,169 687,307 717,783 6% 11%

nonroad 1,630,301 1,129,911 794,770 -31% -51%

onroad 5,719,979 3,150,751 1,707,692 -45% -70%

c3marine 131,382 131,691 104,503 0% -20%

ptprescfire 167,599 167,599 167,599 0% 0%

ptwildfire 165,799 165,799 165,799 0% 0%

ptegu 2,088,233 1,547,987 1,435,523 -26% -31%

ptnonipm 1,222,456 1,192,297 1,229,333 -2% 1%

pt_oilgas 509,856 411,055 464,256 -19% -9%

rwc 34,436 35,507 34,722 3% 1%

Con U.S. Total 14,155,649 10,312,541 8,291,070 -27% -41%

Off-shore to EEZ* 899,986 855,139 666,757 -5% -26%

Non-US SECA C3 202,432 239,528 296,532 18% 46%

Canada othafdust 0 0 0 0% 0%

Canada othar 361,896 361,896 361,896 0% 0%

Canada othon 345,664 345,664 345,664 0% 0%

Canada othpt** 266,912 266,912 266,912 0% 0%

Mexico othar 182,869 199,951 218,022 9% 19%

Mexico othon 243,714 164,555 116,490 -32% -52%

Mexico othpt 286,303 348,544 387,578 22% 35%

Non-US Total 2,789,775 2,782,187 2,659,850 0% -5%
166

Table 5-7. National by-sector PM2.5 emissions (tons/yr) summaries and percent change

Sector 2011 PM2.5 2017 PM2.5 2025 PM2.5

% change 

2011 to 2017

% change 

2011 to 2025

afdust_adj 923,938 964,080 1,023,169 4% 11%

ag 0 0 0 0% 0%

agfire 93,959 93,959 93,959 0% 0%

c1c2rail 33,019 24,245 16,507 -27% -50%

nonpt 404,258 416,334 431,038 3% 7%

np_oilgas 15,333 19,420 22,439 27% 46%

nonroad 154,657 107,267 72,788 -31% -53%

onroad 194,690 124,930 83,019 -36% -57%

c3marine 9,043 1,531 2,075 -83% -77%

ptprescfire 900,546 900,546 900,546 0% 0%

ptwildfire 943,717 943,717 943,717 0% 0%

ptegu 206,884 212,913 208,678 3% 1%

ptnonipm 322,142 325,400 333,048 1% 3%

pt_oilgas 13,935 13,379 16,381 -4% 18%

rwc 381,252 383,807 355,599 1% -7%

Con U.S. Total 4,597,374 4,531,527 4,502,962 -1% -2%

Off-shore to EEZ* 24,544 9,768 8,799 -60% -64%

Non-US SECA C3 15,828 20,527 6,407 30% -60%

Canada othafdust 112,523 112,523 112,523 0% 0%

Canada othar 131,114 131,114 131,114 0% 0%

Canada othon 12,216 12,216 12,216 0% 0%

Canada othpt** 29,165 29,165 29,165 0% 0%

Mexico othar 50,158 53,005 55,152 6% 10%

Mexico othon 1,624 1,697 2,104 5% 30%

Mexico othpt 42,105 49,790 57,000 18% 35%

Non-US Total 419,276 419,805 414,482 0% -1%
167

Table 5-8. National by-sector PM10 emissions (tons/yr) summaries and percent change

Sector 2011 PM10 2017 PM10 2025 PM10

% change 

2011 to 2017

% change 

2011 to 2025

afdust_adj 6,735,072 7,093,387 7,621,008 5% 13%

ag 0 0 0 0% 0%

agfire 140,728 140,728 140,728 0% 0%

c1c2rail 35,359 25,970 17,679 -27% -50%

nonpt 491,825 494,930 511,976 1% 4%

np_oilgas 16,843 21,112 25,266 25% 50%

nonroad 162,417 113,568 77,615 -30% -52%

onroad 367,667 302,041 280,816 -18% -24%

c3marine 10,168 1,729 2,335 -83% -77%

ptprescfire 1,060,130 1,060,130 1,060,130 0% 0%

ptwildfire 1,111,857 1,111,857 1,111,857 0% 0%

ptegu 281,614 279,931 274,544 -1% -3%

ptnonipm 478,885 480,114 487,373 0% 2%

pt_oilgas 14,585 14,013 16,859 -4% 16%

rwc 381,476 384,041 355,849 1% -7%

Con U.S. Total 11,288,626 11,523,551 11,984,034 2% 6%

Off-shore to EEZ* 26,247 10,237 9,313 -61% -65%

Non-US SECA C3 17,206 22,313 7,029 30% -59%

Canada othafdust 779,674 779,674 779,674 0% 0%

Canada othar 158,996 158,996 158,996 0% 0%

Canada othon 17,628 17,628 17,628 0% 0%

Canada othpt** 70,005 70,005 70,005 0% 0%

Mexico othar 98,812 103,086 105,952 4% 7%

Mexico othon 2,425 2,565 3,196 6% 32%

Mexico othpt 55,162 64,263 74,454 16% 35%

Non-US Total 1,226,156 1,228,767 1,226,247 0% 0%
168

Table 5-9. National by-sector SO2 emissions (tons/yr) summaries and percent change

Sector 2011 SO2 2017 SO2 2025 SO2

% change 

2011 to 2017

% change 

2011 to 2025

afdust_adj 0 0 0 0% 0%

ag 0 0 0 0% 0%

agfire 16,224 16,224 16,224 0% 0%

c1c2rail 12,609 1,161 888 -91% -93%

nonpt 275,655 104,585 95,195 -62% -65%

np_oilgas 18,306 37,505 38,913 105% 113%

nonroad 4,031 1,856 2,088 -54% -48%

onroad 29,665 14,985 13,759 -49% -54%

c3marine 86,373 3,904 5,272 -95% -94%

ptprescfire 83,082 83,082 83,082 0% 0%

ptwildfire 82,691 82,691 82,691 0% 0%

ptegu 4,662,717 1,462,200 1,471,933 -69% -68%

ptnonipm 1,057,242 807,093 800,678 -24% -24%

pt_oilgas 66,577 69,034 69,560 4% 4%

rwc 8,954 8,814 7,606 -2% -15%

Con U.S. Total 6,404,125 2,693,133 2,687,889 -58% -58%

Off-shore to EEZ* 139,169 9,945 12,165 -93% -91%

Non-US SECA C3 127,579 165,925 43,104 30% -66%

Canada othafdust 0 0 0 0% 0%

Canada othar 70,272 70,272 70,272 0% 0%

Canada othon 1,701 1,701 1,701 0% 0%

Canada othpt** 544,502 544,502 544,502 0% 0%

Mexico othar 10,679 11,930 13,454 12% 26%

Mexico othon 4,919 1,943 1,351 -61% -73%

Mexico othpt 453,466 363,306 360,401 -20% -21%

Non-US Total 1,352,287 1,169,524 1,046,952 -14% -23%
169

Table 5-10. National by-sector VOC emissions (tons/yr) summaries and percent change

Sector 2011 VOC 2017 VOC 2025 VOC

% change 

2011 to 2017

% change 

2011 to 2025

afdust_adj 0 0 0 0% 0%

ag 0 0 0 0% 0%

agfire 74,783 74,783 74,783 0% 0%

c1c2rail 48,281 34,528 24,498 -28% -49%

nonpt 3,672,249 3,511,392 3,426,386 -4% -7%

np_oilgas 2,556,649 3,164,559 3,478,495 24% 36%

nonroad 2,024,419 1,422,907 1,179,395 -30% -42%

onroad 2,709,470 1,507,880 904,713 -44% -67%

c3marine 5,149 6,429 8,687 25% 69%

ptprescfire 2,313,404 2,313,404 2,313,404 0% 0%

ptwildfire 2,374,690 2,374,690 2,374,690 0% 0%

ptegu 36,336 40,433 41,795 11% 15%

ptnonipm 802,988 814,400 826,684 1% 3%

pt_oilgas 164,098 165,559 190,788 1% 16%

rwc 442,541 437,984 408,336 -1% -8%

Con U.S. Total 17,225,056 15,868,951 15,252,654 -8% -11%

Off-shore to EEZ* 81,602 86,093 94,501 6% 16%

Non-US SECA C3 7,294 9,462 13,563 30% 86%

Canada othafdust 0 0 0 0% 0%

Canada othar 886,456 886,456 886,456 0% 0%

Canada othon 178,431 178,431 178,431 0% 0%

Canada othpt** 129,119 129,119 129,119 0% 0%

Mexico othar 410,734 470,910 526,197 15% 28%

Mexico othon 319,353 218,848 198,850 -31% -38%

Mexico othpt 53,813 68,970 85,703 28% 59%

Non-US Total 2,066,802 2,048,288 2,112,821 -1% 2%
170

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Appendix A: Nonpoint Oil and Gas (np_oilgas) SCCs

The table below shows the SCCs in the nonpoint oil and gas sector (np_oilgas).

SCC SCC description

2310000000 Industrial Processes;Oil and Gas Production: SIC 13;All Processes;Total: All Processes

2310000220 Industrial Processes;Oil and Gas Production: SIC 13; Drill rigs

2310000230 Industrial Processes;Oil and Gas Exploration and Production;All Processes;Workover Rigs

2310000330 Industrial Processes;Oil and Gas Production: SIC 13; Artificial lift

2310000550 Industrial Processes;Oil and Gas Exploration and Production;All Processes;Produced Water

2310000660 Industrial Processes;Oil and Gas Exploration and Production;All Processes;Hydraulic Fracturing Engines

2310002000 Industrial Processes;Oil and Gas Production: SIC 13;All Processes : Off-shore;Total: All Processes

2310002301 Industrial Processes;Oil and Gas Exploration and Production;Off-Shore Oil And Gas Production;Flares: Continuous Pilot Light

2310002305 Industrial Processes;Oil and Gas Exploration and Production;Off-Shore Oil And Gas Production;Flares: Flaring Operations

2310002401 Industrial Processes;Oil and Gas Exploration and Production;Off-Shore Oil And Gas Production;Pneumatic Pumps: Gas And Oil Wells

2310002411 Industrial Processes;Oil and Gas Exploration and Production;Off-Shore Oil And Gas Production;Pressure/Level Controllers

2310002421 Industrial Processes;Oil and Gas Exploration and Production;Off-Shore Oil And Gas Production;Cold Vents

2310010000 Industrial Processes;Oil and Gas Production: SIC 13;Crude Petroleum;Total: All Processes

2310010100 Industrial Processes;Oil and Gas Production: SIC 13;Crude Petroleum; Oil well heaters

2310010200 Industrial Processes;Oil and Gas Production: SIC 13;Crude Petroleum; Oil well tanks - flashing & standing/working/breathing

2310010300 Industrial Processes;Oil and Gas Production: SIC 13;Crude Petroleum; Oil well pneumatic devices

2310010700 Industrial Processes;Oil and Gas Production: SIC 13;Crude Petroleum; Oil well fugitives

2310010800 Industrial Processes;Oil and Gas Production: SIC 13;Crude Petroleum; Oil well truck loading

2310011000 Industrial Processes;Oil and Gas Production: SIC 13;Crude Petroleum : On-shore;Total: All Processes

2310011020 Industrial Processes;Oil and Gas Exploration and Production;On-Shore Oil Production;Storage Tanks: Crude Oil

2310011100 Industrial Processes;Oil and Gas Exploration and Production;On-Shore Oil Production;Heater Treater

2310011201 Industrial Processes;Oil and Gas Exploration and Production;On-Shore Oil Production;Tank Truck/Railcar Loading: Crude Oil

2310011450 Industrial Processes;Oil and Gas Exploration and Production;On-Shore Oil Production;Wellhead

2310011500 Industrial Processes;Oil and Gas Exploration and Production;On-Shore Oil Production;Fugitives: All Processes

2310011501 Industrial Processes;Oil and Gas Exploration and Production;On-Shore Oil Production;Fugitives: Connectors

2310011502 Industrial Processes;Oil and Gas Exploration and Production;On-Shore Oil Production;Fugitives: Flanges
178

SCC SCC description

2310011503 Industrial Processes;Oil and Gas Exploration and Production;On-Shore Oil Production;Fugitives: Open Ended Lines

2310011504 Industrial Processes;Oil and Gas Exploration and Production;On-Shore Oil Production;Fugitives: Pumps

2310011505 Industrial Processes;Oil and Gas Exploration and Production;On-Shore Oil Production;Fugitives: Valves

2310011506 Industrial Processes;Oil and Gas Exploration and Production;On-Shore Oil Production;Fugitives: Other

2310011600 Industrial Processes;Oil and Gas Exploration and Production;On-Shore Oil Production;Artificial Lift Engines

2310012000 Industrial Processes;Oil and Gas Production: SIC 13;Crude Petroleum : Off-shore;Total: All Processes

2310012020 Industrial Processes;Oil and Gas Exploration and Production;Off-Shore Oil Production;Storage Tanks: Crude Oil

2310012511 Industrial Processes;Oil and Gas Exploration and Production;Off-Shore Oil Production;Fugitives; Connectors: Oil Streams

2310012512 Industrial Processes;Oil and Gas Exploration and Production;Off-Shore Oil Production;Fugitives; Flanges: Oil

2310012515 Industrial Processes;Oil and Gas Exploration and Production;Off-Shore Oil Production;Fugitives; Valves: Oil

2310012516 Industrial Processes;Oil and Gas Exploration and Production;Off-Shore Oil Production;Fugitives; Other: Oil

2310012521 Industrial Processes;Oil and Gas Exploration and Production;Off-Shore Oil Production;Fugitives; Connectors: Oil/Water Streams

2310012522 Industrial Processes;Oil and Gas Exploration and Production;Off-Shore Oil Production;Fugitives; Flanges: Oil/Water

2310012526 Industrial Processes;Oil and Gas Exploration and Production;Off-Shore Oil Production;Fugitives; Other: Oil/Water

2310020000 Industrial Processes;Oil and Gas Production: SIC 13;Natural Gas;Total: All Processes

2310020600 Industrial Processes;Oil and Gas Production: SIC 13;Natural Gas; Compressor engines

2310020700 Industrial Processes;Oil and Gas Production: SIC 13;Natural Gas; Gas well fugitives

2310020800 Industrial Processes;Oil and Gas Production: SIC 13;Natural Gas; Gas well truck loading

2310021010 Industrial Processes;Oil and Gas Exploration and Production;On-Shore Gas Production;Storage Tanks: Condensate

2310021011 Industrial Processes;Oil and Gas Exploration and Production;On-Shore Gas Production;Condensate Tank Flaring

2310021030 Industrial Processes;Oil and Gas Exploration and Production;On-Shore Gas Production;Tank Truck/Railcar Loading: Condensate

2310021100 Industrial Processes;Oil and Gas Production: SIC 13;Natural Gas; Gas well heaters

2310021101

Industrial Processes;Oil and Gas Exploration and Production;On-Shore Gas Production;Natural Gas Fired 2Cycle Lean Burn 

Compressor Engines < 50 HP

2310021102

Industrial Processes;Oil and Gas Exploration and Production;On-Shore Gas Production;Natural Gas Fired 2Cycle Lean Burn 

Compressor Engines 50 To 499 HP

2310021103

Industrial Processes;Oil and Gas Exploration and Production;On-Shore Gas Production;Natural Gas Fired 2Cycle Lean Burn 

Compressor Engines 500+ HP

2310021201

Industrial Processes;Oil and Gas Exploration and Production;On-Shore Gas Production;Natural Gas Fired 4Cycle Lean Burn 

Compressor Engines <50 HP

2310021202

Industrial Processes;Oil and Gas Exploration and Production;On-Shore Gas Production;Natural Gas Fired 4Cycle Lean Burn 

Compressor Engines 50 To 499 HP

2310021203

Industrial Processes;Oil and Gas Exploration and Production;On-Shore Gas Production;Natural Gas Fired 4Cycle Lean Burn 

Compressor Engines 500+ HP
179

SCC SCC description

2310021209

2310021251 Industrial Processes;Oil and Gas Exploration and Production;On-Shore Gas Production;Lateral Compressors 4 Cycle Lean Burn

2310021300 Industrial Processes;Oil and Gas Production: SIC 13;Natural Gas; Gas well pneumatic devices

2310021301

Industrial Processes;Oil and Gas Exploration and Production;On-Shore Gas Production;Natural Gas Fired 4Cycle Rich Burn 

Compressor Engines <50 HP

2310021302

Industrial Processes;Oil and Gas Exploration and Production;On-Shore Gas Production;Natural Gas Fired 4Cycle Rich Burn 

Compressor Engines 50 To 499 HP

2310021303

Industrial Processes;Oil and Gas Exploration and Production;On-Shore Gas Production;Natural Gas Fired 4Cycle Rich Burn 

Compressor Engines 500+ HP

2310021309

2310021310 Industrial Processes;Oil and Gas Exploration and Production;On-Shore Gas Production;Gas Well Pneumatic Pumps

2310021351 Industrial Processes;Oil and Gas Exploration and Production;On-Shore Gas Production;Lateral Compressors 4 Cycle Rich Burn

2310021400 Industrial Processes;Oil and Gas Production: SIC 13;Natural Gas; Gas well dehydrators

2310021401

Industrial Processes;Oil and Gas Exploration and Production;On-Shore Gas Production;Nat Gas Fired 4Cycle Rich Burn Compressor 

Engines <50 HP w/NSCR

2310021402

Industrial Processes;Oil and Gas Exploration and Production;On-Shore Gas Production;Nat Gas Fired 4Cycle Rich Burn Compressor 

Engines 50 To 499 HP w/NSCR

2310021403

Industrial Processes;Oil and Gas Exploration and Production;On-Shore Gas Production;Nat Gas Fired 4Cycle Rich Burn Compressor 

Engines 500+ HP w/NSCR

2310021411 Industrial Processes;Oil and Gas Exploration and Production;On-Shore Gas Production;Gas Well Dehydrators - Flaring

2310021500 Industrial Processes;Oil and Gas Production: SIC 13;Natural Gas; Gas well completion - flaring and venting

2310021501 Industrial Processes;Oil and Gas Exploration and Production;On-Shore Gas Production;Fugitives: Connectors

2310021502 Industrial Processes;Oil and Gas Exploration and Production;On-Shore Gas Production;Fugitives: Flanges

2310021503 Industrial Processes;Oil and Gas Exploration and Production;On-Shore Gas Production;Fugitives: Open Ended Lines

2310021504 Industrial Processes;Oil and Gas Exploration and Production;On-Shore Gas Production;Fugitives: Pumps

2310021505 Industrial Processes;Oil and Gas Exploration and Production;On-Shore Gas Production;Fugitives: Valves

2310021506 Industrial Processes;Oil and Gas Exploration and Production;On-Shore Gas Production;Fugitives: Other

2310021509 Industrial Processes;Oil and Gas Exploration and Production;On-Shore Gas Production;Fugitives: All Processes

2310021600 Industrial Processes;Oil and Gas Production: SIC 13;Natural Gas; Gas well venting

2310021601 Industrial Processes;Oil and Gas Exploration and Production;On-Shore Gas Production;Gas Well Venting - Initial Completions

2310021602 Industrial Processes;Oil and Gas Exploration and Production;On-Shore Gas Production;Gas Well Venting - Recompletions

2310021603 Industrial Processes;Oil and Gas Exploration and Production;On-Shore Gas Production;Gas Well Venting - Blowdowns

2310021604 Industrial Processes;Oil and Gas Exploration and Production;On-Shore Gas Production;Gas Well Venting - Compressor Startups

2310021605 Industrial Processes;Oil and Gas Exploration and Production;On-Shore Gas Production;Gas Well Venting - Compressor Shutdowns
180

SCC SCC description

2310021700 Industrial Processes;Oil and Gas Exploration and Production;On-Shore Gas Production;Miscellaneous Engines

2310022000 Industrial Processes;Oil and Gas Production: SIC 13;Natural Gas : Off-shore;Total: All Processes

2310022010 Industrial Processes;Oil and Gas Exploration and Production;Off-Shore Gas Production;Storage Tanks: Condensate

2310022051 Industrial Processes;Oil and Gas Exploration and Production;Off-Shore Gas Production;Turbines: Natural Gas

2310022090 Industrial Processes;Oil and Gas Exploration and Production;Off-Shore Gas Production;Boilers/Heaters: Natural Gas

2310022105 Industrial Processes;Oil and Gas Exploration and Production;Off-Shore Gas Production;Diesel Engines

2310022410 Industrial Processes;Oil and Gas Exploration and Production;Off-Shore Gas Production;Amine Unit

2310022420 Industrial Processes;Oil and Gas Exploration and Production;Off-Shore Gas Production;Dehydrator

2310022501 Industrial Processes;Oil and Gas Exploration and Production;Off-Shore Gas Production;Fugitives; Connectors: Gas Streams

2310022502 Industrial Processes;Oil and Gas Exploration and Production;Off-Shore Gas Production;Fugitives; Flanges: Gas Streams

2310022505 Industrial Processes;Oil and Gas Exploration and Production;Off-Shore Gas Production;Fugitives; Valves: Gas

2310022506 Industrial Processes;Oil and Gas Exploration and Production;Off-Shore Gas Production;Fugitives; Other: Gas

2310023010 Industrial Processes;Oil and Gas Exploration and Production;Coal Bed Methane Natural Gas;Storage Tanks: Condensate

2310023030 Industrial Processes;Oil and Gas Exploration and Production;Coal Bed Methane Natural Gas;Tank Truck/Railcar Loading: Condensate

2310023100 Industrial Processes; Oil and Gas Production; CBM; Dehydrators

2310023102

Industrial Processes;Oil and Gas Exploration and Production;Coal Bed Methane Natural Gas;CBM Fired 2Cycle Lean Burn Compressor 

Engines 50 To 499 HP

2310023202

Industrial Processes;Oil and Gas Exploration and Production;Coal Bed Methane Natural Gas;CBM Fired 4Cycle Lean Burn Compressor 

Engines 50 To 499 HP

2310023251 Industrial Processes;Oil and Gas Exploration and Production;Coal Bed Methane Natural Gas;Lateral Compressors 4 Cycle Lean Burn

2310023300

Industrial Processes;Oil and Gas Exploration and Production;Coal Bed Methane Natural Gas;Pneumatic Devices Industrial 

Processes;Oil and Gas Exploration and Production;Coal Bed Methane Natural Gas;Pneumatic Devices

2310023302

Industrial Processes;Oil and Gas Exploration and Production;Coal Bed Methane Natural Gas;CBM Fired 4Cycle Rich Burn Compressor 

Engines 50 To 499 HP

2310023310 Industrial Processes;Oil and Gas Exploration and Production;Coal Bed Methane Natural Gas;Pneumatic Pumps

2310023351 Industrial Processes;Oil and Gas Exploration and Production;Coal Bed Methane Natural Gas;Lateral Compressors 4 Cycle Rich Burn

2310023400 Industrial Processes;Oil and Gas Exploration and Production;Coal Bed Methane Natural Gas;Dehydrators

2310023509 Industrial Processes;Oil and Gas Exploration and Production;Coal Bed Methane Natural Gas;Fugitives

2310023511 Industrial Processes;Oil and Gas Exploration and Production;Coal Bed Methane Natural Gas;Fugitives: Connectors

2310023512 Industrial Processes;Oil and Gas Exploration and Production;Coal Bed Methane Natural Gas;Fugitives: Flanges

2310023513 Industrial Processes;Oil and Gas Exploration and Production;Coal Bed Methane Natural Gas;Fugitives: Open Ended Lines

2310023515 Industrial Processes;Oil and Gas Exploration and Production;Coal Bed Methane Natural Gas;Fugitives: Valves

2310023516 Industrial Processes;Oil and Gas Exploration and Production;Coal Bed Methane Natural Gas;Fugitives: Other
181

SCC SCC description

2310023600 Industrial Processes; Oil and Gas Production; CBM; Venting - Compressor Shutdown

2310023601 Industrial Processes;Oil and Gas Exploration and Production;Coal Bed Methane Natural Gas;Venting - Initial Completions

2310023602 Industrial Processes;Oil and Gas Exploration and Production;Coal Bed Methane Natural Gas;Venting - Recompletions

2310023603 Industrial Processes;Oil and Gas Exploration and Production;Coal Bed Methane Natural Gas;Venting - Blowdowns

2310023606 Industrial Processes;Oil and Gas Exploration and Production;Coal Bed Methane Natural Gas;Mud Degassing

2310030000 Industrial Processes;Oil and Gas Production: SIC 13;Natural Gas Liquids;Total: All Processes

2310030210 Industrial Processes;Oil and Gas Production: SIC 13;Natural Gas Liquids; Gas well tanks - Flashing & Standing/Working/Breathing

2310030300 Industrial Processes;Oil and Gas Exploration and Production;Natural Gas Liquids;Gas Well Water Tank Losses

2310030401 Industrial Processes;Oil and Gas Exploration and Production;Natural Gas Liquids;Gas Plant Truck Loading

2310111100 Industrial Processes;Oil and Gas Exploration and Production;On-Shore Oil Exploration;Mud Degassing

2310111401 Industrial Processes;Oil and Gas Exploration and Production;On-Shore Oil Exploration;Oil Well Pneumatic Pumps

2310111700 Industrial Processes;Oil and Gas Exploration and Production;On-Shore Oil Exploration;Oil Well Completion: All Processes

2310112401 Industrial Processes;Oil and Gas Exploration and Production;Off-Shore Oil Exploration;Oil Well Pneumatic Pumps

2310121100 Industrial Processes;Oil and Gas Exploration and Production;On-Shore Gas Exploration;Mud Degassing

2310121401 Industrial Processes;Oil and Gas Exploration and Production;Off-Shore Oil Exploration;Oil Well Pneumatic Pumps

2310121700 Industrial Processes;Oil and Gas Exploration and Production;Off-Shore Oil Exploration;Oil Well Completion: All Processes

2310122100 Industrial Processes;Oil and Gas Exploration and Production;Off-Shore Gas Exploration;Mud Degassing
182

Appendix B: Mapping of Fuel Distribution SCCs to BTP, BPS and RBT

The table below provides a crosswalk between fuel distribution SCCs and classification type for portable fuel containers (PFC), fuel 

distribution operations associated with the bulk-plant-to-pump (BTP), refinery to bulk terminal (RBT) and bulk plant storage (BPS).

SCC Type Description

40301001 RBT

Petroleum and Solvent Evaporation; Petroleum Product Storage at Refineries; Fixed Roof Tanks (Varying Sizes); Gasoline RVP 13: 

Breathing Loss (67000 Bbl. Tank Size) 

40301002 RBT

Petroleum and Solvent Evaporation; Petroleum Product Storage at Refineries; Fixed Roof Tanks (Varying Sizes); Gasoline RVP 10: 

Breathing Loss (67000 Bbl. Tank Size) 

40301003 RBT

Petroleum and Solvent Evaporation; Petroleum Product Storage at Refineries; Fixed Roof Tanks (Varying Sizes); Gasoline RVP 7:

Breathing Loss (67000 Bbl. Tank Size) 

40301004 RBT

Petroleum and Solvent Evaporation; Petroleum Product Storage at Refineries; Fixed Roof Tanks (Varying Sizes); Gasoline RVP 13: 

Breathing Loss (250000 Bbl. Tank Size) 

40301006 RBT

Petroleum and Solvent Evaporation; Petroleum Product Storage at Refineries; Fixed Roof Tanks (Varying Sizes); Gasoline RVP 7:

Breathing Loss (250000 Bbl. Tank Size) 

40301007 RBT

Petroleum and Solvent Evaporation; Petroleum Product Storage at Refineries; Fixed Roof Tanks (Varying Sizes); Gasoline RVP 13: 

Working Loss (Tank Diameter Independent) 

40301101 RBT

Petroleum and Solvent Evaporation; Petroleum Product Storage at Refineries; Floating Roof Tanks (Varying Sizes); Gasoline RVP 13: 

Standing Loss (67000 Bbl. Tank Size) 

40301102 RBT

Petroleum and Solvent Evaporation; Petroleum Product Storage at Refineries; Floating Roof Tanks (Varying Sizes); Gasoline RVP 10: 

Standing Loss (67000 Bbl. Tank Size) 

40301103 RBT

Petroleum and Solvent Evaporation; Petroleum Product Storage at Refineries; Floating Roof Tanks (Varying Sizes); Gasoline RVP 7: 

Standing Loss (67000 Bbl. Tank Size) 

40301105 RBT

Petroleum and Solvent Evaporation; Petroleum Product Storage at Refineries; Floating Roof Tanks (Varying Sizes); Gasoline RVP 10: 

Standing Loss (250000 Bbl. Tank Size) 

40301151 RBT

Petroleum and Solvent Evaporation; Petroleum Product Storage at Refineries; Floating Roof Tanks (Varying Sizes); Gasoline: Standing 

Loss - Internal 

40301202 RBT Petroleum and Solvent Evaporation; Petroleum Product Storage at Refineries; Variable Vapor Space; Gasoline RVP 10: Filling Loss 

40301203 RBT Petroleum and Solvent Evaporation; Petroleum Product Storage at Refineries; Variable Vapor Space; Gasoline RVP 7: Filling Loss 

40400101 RBT

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Terminals; Gasoline RVP 13: Breathing Loss (67000 

Bbl Capacity) - Fixed Roof Tank 

40400102 RBT

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Terminals; Gasoline RVP 10: Breathing Loss (67000 

Bbl Capacity) - Fixed Roof Tank 

40400103 RBT

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Terminals; Gasoline RVP 7: Breathing Loss (67000 

Bbl. Capacity) - Fixed Roof Tank 

40400104 RBT

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Terminals; Gasoline RVP 13: Breathing Loss 

(250000 Bbl Capacity)-Fixed Roof Tank 

40400105 RBT

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Terminals; Gasoline RVP 10: Breathing Loss 

(250000 Bbl Capacity)-Fixed Roof Tank 
183

SCC Type Description

40400106 RBT

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Terminals; Gasoline RVP 7: Breathing Loss (250000 

Bbl Capacity) - Fixed Roof Tank 

40400107 RBT

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Terminals; Gasoline RVP 13: Working Loss (Diam. 

Independent) - Fixed Roof Tank 

40400108 RBT

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Terminals; Gasoline RVP 10: Working Loss 

(Diameter Independent) - Fixed Roof Tank 

40400109 RBT

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Terminals; Gasoline RVP 7: Working Loss 

(Diameter Independent) - Fixed Roof Tank 

40400110 RBT

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Terminals; Gasoline RVP 13: Standing Loss (67000 

Bbl Capacity)-Floating Roof Tank 

40400111 RBT

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Terminals; Gasoline RVP 10: Standing Loss (67000 

Bbl Capacity)-Floating Roof Tank 

40400112 RBT

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Terminals; Gasoline RVP 7: Standing Loss (67000 

Bbl Capacity)- Floating Roof Tank 

40400113 RBT

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Terminals; Gasoline RVP 13: Standing Loss (250000 

Bbl Cap.) - Floating Roof Tank 

40400114 RBT

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Terminals; Gasoline RVP 10: Standing Loss (250000 

Bbl Cap.) - Floating Roof Tank 

40400115 RBT

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Terminals; Gasoline RVP 7: Standing Loss (250000 

Bbl Cap.) - Floating Roof Tank 

40400116 RBT

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Terminals; Gasoline RVP 13/10/7: Withdrawal Loss 

(67000 Bbl Cap.) - Float Rf Tnk 

40400117 RBT

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Terminals; Gasoline RVP 13/10/7: Withdrawal Loss 

(250000 Bbl Cap.) - Float Rf Tnk 

40400118 RBT

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Terminals; Gasoline RVP 13: Filling Loss (10500 

Bbl Cap.) - Variable Vapor Space 

40400119 RBT

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Terminals; Gasoline RVP 10: Filling Loss (10500 

Bbl Cap.) - Variable Vapor Space 

40400120 RBT

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Terminals; Gasoline RVP 7: Filling Loss (10500 Bbl 

Cap.) - Variable Vapor Space 

40400130 RBT

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Terminals; Specify Liquid: Standing Loss - External 

Floating Roof w/ Primary Seal 

40400131 RBT

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Terminals; Gasoline RVP 13: Standing Loss - Ext. 

Floating Roof w/ Primary Seal 

40400132 RBT

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Terminals; Gasoline RVP 10: Standing Loss - Ext. 

Floating Roof w/ Primary Seal 

40400133 RBT

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Terminals; Gasoline RVP 7: Standing Loss - External 

Floating Roof w/ Primary Seal 

40400140 RBT

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Terminals; Specify Liquid: Standing Loss - Ext. Float 

Roof Tank w/ Secondy Seal 
184

SCC Type Description

40400141 RBT

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Terminals; Gasoline RVP 13: Standing Loss - Ext. 

Floating Roof w/ Secondary Seal 

40400142 RBT

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Terminals; Gasoline RVP 10: Standing Loss - Ext. 

Floating Roof w/ Secondary Seal 

40400143 RBT

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Terminals; Gasoline RVP 7: Standing Loss - Ext. 

Floating Roof w/ Secondary Seal 

40400148 RBT

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Terminals; Gasoline RVP 13/10/7: Withdrawal Loss 

- Ext. Float Roof (Pri/Sec Seal) 

40400149 RBT

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Terminals; Specify Liquid: External Floating Roof 

(Primary/Secondary Seal) 

40400150 RBT

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Terminals; Miscellaneous Losses/Leaks: Loading 

Racks 

40400151 RBT Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Terminals; Valves, Flanges, and Pumps 

40400152 RBT Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Terminals; Vapor Collection Losses 

40400153 RBT Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Terminals; Vapor Control Unit Losses 

40400160 RBT

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Terminals; Specify Liquid: Standing Loss - Internal 

Floating Roof w/ Primary Seal 

40400161 RBT

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Terminals; Gasoline RVP 13: Standing Loss - Int. 

Floating Roof w/ Primary Seal 

40400162 RBT

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Terminals; Gasoline RVP 10: Standing Loss - Int. 

Floating Roof w/ Primary Seal 

40400163 RBT

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Terminals; Gasoline RVP 7: Standing Loss - Internal 

Floating Roof w/ Primary Seal 

40400170 RBT

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Terminals; Specify Liquid: Standing Loss - Int. 

Floating Roof w/ Secondary Seal 

40400171 RBT

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Terminals; Gasoline RVP 13: Standing Loss - Int. 

Floating Roof w/ Secondary Seal 

40400172 RBT

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Terminals; Gasoline RVP 10: Standing Loss - Int. 

Floating Roof w/ Secondary Seal 

40400173 RBT

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Terminals; Gasoline RVP 7: Standing Loss - Int. 

Floating Roof w/ Secondary Seal 

40400178 RBT

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Terminals; Gasoline RVP 13/10/7: Withdrawal Loss 

- Int. Float Roof (Pri/Sec Seal) 

40400179 RBT

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Terminals; Specify Liquid: Internal Floating Roof 

(Primary/Secondary Seal) 

40400199 RBT Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Terminals; See Comment ** 

40400201 BTP/BPS

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Plants; Gasoline RVP 13: Breathing Loss (67000 Bbl 

Capacity) - Fixed Roof Tank 

40400202 BTP/BPS

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Plants; Gasoline RVP 10: Breathing Loss (67000 Bbl 

Capacity) - Fixed Roof Tank 
185

SCC Type Description

40400203 BTP/BPS

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Plants; Gasoline RVP 7: Breathing Loss (67000 Bbl. 

Capacity) - Fixed Roof Tank 

40400204 BTP/BPS

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Plants; Gasoline RVP 13: Working Loss (67000 Bbl. 

Capacity) - Fixed Roof Tank 

40400205 BTP/BPS

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Plants; Gasoline RVP 10: Working Loss (67000 Bbl. 

Capacity) - Fixed Roof Tank 

40400206 BTP/BPS

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Plants; Gasoline RVP 7: Working Loss (67000 Bbl. 

Capacity) - Fixed Roof Tank 

40400207 BTP/BPS

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Plants; Gasoline RVP 13: Standing Loss (67000 Bbl 

Cap.) - Floating Roof Tank 

40400208 BTP/BPS

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Plants; Gasoline RVP 10: Standing Loss (67000 Bbl 

Cap.) - Floating Roof Tank 

40400210 BTP/BPS

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Plants; Gasoline RVP 13/10/7: Withdrawal Loss 

(67000 Bbl Cap.) - Float Rf Tnk 

40400211 BTP/BPS

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Plants; Gasoline RVP 13: Filling Loss (10500 Bbl 

Cap.) - Variable Vapor Space 

40400212 BTP/BPS

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Plants; Gasoline RVP 10: Filling Loss (10500 Bbl 

Cap.) - Variable Vapor Space 

40400213 BTP/BPS

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Plants; Gasoline RVP 7: Filling Loss (10500 Bbl 

Cap.) - Variable Vapor Space 

40400230 BTP/BPS

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Plants; Specify Liquid: Standing Loss - External 

Floating Roof w/ Primary Seal 

40400231 BTP/BPS

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Plants; Gasoline RVP 13: Standing Loss - Ext. 

Floating Roof w/ Primary Seal 

40400232 BTP/BPS

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Plants; Gasoline RVP 10: Standing Loss - Ext. 

Floating Roof w/ Primary Seal 

40400233 BTP/BPS

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Plants; Gasoline RVP 7: Standing Loss - External 

Floating Roof w/ Primary Seal 

40400240 RBT

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Plants; Specify Liquid: Standing Loss - Ext. Floating 

Roof w/ Secondary Seal 

40400241 BTP/BPS

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Plants; Gasoline RVP 13: Standing Loss - Ext. 

Floating Roof w/ Secondary Seal 

40400248 BTP/BPS

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Plants; Gasoline RVP 10/13/7: Withdrawal Loss -

Ext. Float Roof (Pri/Sec Seal) 

40400249 RBT

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Plants; Specify Liquid: External Floating Roof 

(Primary/Secondary Seal) 

40400250 BTP/BPS Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Plants; Loading Racks 

40400251 BTP/BPS Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Plants; Valves, Flanges, and Pumps 

40400252 BTP/BPS

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Plants; Miscellaneous Losses/Leaks: Vapor 

Collection Losses 
186

SCC Type Description

40400253 BTP/BPS

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Plants; Miscellaneous Losses/Leaks: Vapor Control 

Unit Losses 

40400260 RBT

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Plants; Specify Liquid: Standing Loss - Internal 

Floating Roof w/ Primary Seal 

40400261 BTP/BPS

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Plants; Gasoline RVP 13: Standing Loss - Int. 

Floating Roof w/ Primary Seal 

40400262 BTP/BPS

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Plants; Gasoline RVP 10: Standing Loss - Int. 

Floating Roof w/ Primary Seal 

40400263 BTP/BPS

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Plants; Gasoline RVP 7: Standing Loss - Internal 

Floating Roof w/ Primary Seal 

40400270 BTP/BPS

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Plants; Specify Liquid: Standing Loss - Int. Floating 

Roof w/ Secondary Seal 

40400271 BTP/BPS

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Plants; Gasoline RVP 13: Standing Loss - Int. 

Floating Roof w/ Secondary Seal 

40400272 BTP/BPS

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Plants; Gasoline RVP 10: Standing Loss - Int. 

Floating Roof w/ Secondary Seal 

40400273 BTP/BPS

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Plants; Gasoline RVP 7: Standing Loss - Int. Floating 

Roof w/ Secondary Seal 

40400278 BTP/BPS

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Plants; Gasoline RVP 10/13/7: Withdrawal Loss -

Int. Float Roof (Pri/Sec Seal) 

40400279 BTP/BPS

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Bulk Plants; Specify Liquid: Internal Floating Roof 

(Primary/Secondary Seal) 

40400401 BTP/BPS

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Petroleum Products - Underground Tanks; Gasoline RVP 

13: Breathing Loss 

40400402 BTP/BPS

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Petroleum Products - Underground Tanks; Gasoline RVP 

13: Working Loss 

40400403 BTP/BPS

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Petroleum Products - Underground Tanks; Gasoline RVP 

10: Breathing Loss 

40400404 BTP/BPS

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Petroleum Products - Underground Tanks; Gasoline RVP 

10: Working Loss 

40400405 BTP/BPS

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Petroleum Products - Underground Tanks; Gasoline RVP 

7: Breathing Loss 

40400406 BTP/BPS

Petroleum and Solvent Evaporation; Petroleum Liquids Storage (non-Refinery); Petroleum Products - Underground Tanks; Gasoline RVP 

7: Working Loss 

40600101 BTP/BPS

Petroleum and Solvent Evaporation; Transportation and Marketing of Petroleum Products; Tank Cars and Trucks; Gasoline: Splash 

Loading ** 

40600126 BTP/BPS

Petroleum and Solvent Evaporation; Transportation and Marketing of Petroleum Products; Tank Cars and Trucks; Gasoline: Submerged 

Loading ** 

40600131 BTP/BPS

Petroleum and Solvent Evaporation; Transportation and Marketing of Petroleum Products; Tank Cars and Trucks; Gasoline: Submerged 

Loading (Normal Service) 
187

SCC Type Description

40600136 BTP/BPS

Petroleum and Solvent Evaporation; Transportation and Marketing of Petroleum Products; Tank Cars and Trucks; Gasoline: Splash 

Loading (Normal Service) 

40600141 BTP/BPS

Petroleum and Solvent Evaporation; Transportation and Marketing of Petroleum Products; Tank Cars and Trucks; Gasoline: Submerged 

Loading (Balanced Service) 

40600144 BTP/BPS

Petroleum and Solvent Evaporation; Transportation and Marketing of Petroleum Products; Tank Cars and Trucks; Gasoline: Splash 

Loading (Balanced Service) 

40600147 BTP/BPS

Petroleum and Solvent Evaporation; Transportation and Marketing of Petroleum Products; Tank Cars and Trucks; Gasoline: Submerged 

Loading (Clean Tanks) 

40600162 BTP/BPS

Petroleum and Solvent Evaporation; Transportation and Marketing of Petroleum Products; Tank Cars and Trucks; Gasoline: Loaded with 

Fuel (Transit Losses) 

40600163 BTP/BPS

Petroleum and Solvent Evaporation; Transportation and Marketing of Petroleum Products; Tank Cars and Trucks; Gasoline: Return with 

Vapor (Transit Losses) 

40600199 BTP/BPS Petroleum and Solvent Evaporation; Transportation and Marketing of Petroleum Products; Tank Cars and Trucks; Not Classified ** 

40600231 RBT

Petroleum and Solvent Evaporation; Transportation and Marketing of Petroleum Products; Marine Vessels; Gasoline: Loading Tankers: 

Cleaned and Vapor Free Tanks 

40600232 RBT Petroleum and Solvent Evaporation; Transportation and Marketing of Petroleum Products; Marine Vessels; Gasoline: Loading Tankers 

40600233 BTP/BPS

Petroleum and Solvent Evaporation; Transportation and Marketing of Petroleum Products; Marine Vessels; Gasoline: Loading Barges: 

Cleaned and Vapor Free Tanks 

40600234 RBT

Petroleum and Solvent Evaporation; Transportation and Marketing of Petroleum Products; Marine Vessels; Gasoline: Loading Tankers: 

Ballasted Tank 

40600235 BTP/BPS

Petroleum and Solvent Evaporation;Transportation and Marketing of Petroleum Products;Marine Vessels;Gasoline: Ocean Barges Loading 

- Ballasted Tank

40600236 RBT

Petroleum and Solvent Evaporation; Transportation and Marketing of Petroleum Products; Marine Vessels; Gasoline: Loading Tankers: 

Uncleaned Tanks 

40600237 RBT

Petroleum and Solvent Evaporation;Transportation and Marketing of Petroleum Products;Marine Vessels;Gasoline: Ocean Barges Loading 

- Uncleaned Tanks

40600238 RBT

Petroleum and Solvent Evaporation; Transportation and Marketing of Petroleum Products; Marine Vessels; Gasoline: Loading Barges: 

Uncleaned Tanks 

40600239 RBT

Petroleum and Solvent Evaporation; Transportation and Marketing of Petroleum Products; Marine Vessels; Gasoline: Tankers: Ballasted 

Tank 

40600240 RBT

Petroleum and Solvent Evaporation; Transportation and Marketing of Petroleum Products; Marine Vessels; Gasoline: Loading Barges: 

Average Tank Condition 

40600241 BTP/BPS Petroleum and Solvent Evaporation; Transportation and Marketing of Petroleum Products; Marine Vessels; Gasoline: Tanker Ballasting 

40600299 RBT Petroleum and Solvent Evaporation; Transportation and Marketing of Petroleum Products; Marine Vessels; Not Classified ** 

40600301 BTP/BPS

Petroleum and Solvent Evaporation; Transportation and Marketing of Petroleum Products; Gasoline Retail Operations - Stage I; Splash 

Filling 

40600302 BTP/BPS

Petroleum and Solvent Evaporation; Transportation and Marketing of Petroleum Products; Gasoline Retail Operations - Stage I; Submerged 

Filling w/o Controls 

40600305 BTP/BPS

Petroleum and Solvent Evaporation; Transportation and Marketing of Petroleum Products; Gasoline Retail Operations - Stage I; Unloading 

** 
188

SCC Type Description

40600306 BTP/BPS

Petroleum and Solvent Evaporation; Transportation and Marketing of Petroleum Products; Gasoline Retail Operations - Stage I; Balanced 

Submerged Filling 

40600307 BTP/BPS

Petroleum and Solvent Evaporation; Transportation and Marketing of Petroleum Products; Gasoline Retail Operations - Stage I; 

Underground Tank Breathing and Emptying 

40600399 BTP/BPS

Petroleum and Solvent Evaporation; Transportation and Marketing of Petroleum Products; Gasoline Retail Operations - Stage I; Not 

Classified ** 

40600401 BTP/BPS

Petroleum and Solvent Evaporation; Transportation and Marketing of Petroleum Products; Filling Vehicle Gas Tanks - Stage II; Vapor 

Loss w/o Controls 

40600501 RBT

Petroleum and Solvent Evaporation; Transportation and Marketing of Petroleum Products; Pipeline Petroleum Transport - General - All 

Products; Pipeline Leaks 

40600502 RBT

Petroleum and Solvent Evaporation; Transportation and Marketing of Petroleum Products; Pipeline Petroleum Transport - General - All 

Products; Pipeline Venting 

40600503 RBT

Petroleum and Solvent Evaporation; Transportation and Marketing of Petroleum Products; Pipeline Petroleum Transport - General - All 

Products; Pump Station 

40600504 RBT

Petroleum and Solvent Evaporation; Transportation and Marketing of Petroleum Products; Pipeline Petroleum Transport - General - All 

Products; Pump Station Leaks 

40600602 BTP/BPS

Petroleum and Solvent Evaporation; Transportation and Marketing of Petroleum Products; Consumer (Corporate) Fleet Refueling - Stage 

II; Liquid Spill Loss w/o Controls 

40600701 BTP/BPS

Petroleum and Solvent Evaporation; Transportation and Marketing of Petroleum Products; Consumer (Corporate) Fleet Refueling - Stage I; 

Splash Filling 

40600702 BTP/BPS

Petroleum and Solvent Evaporation; Transportation and Marketing of Petroleum Products; Consumer (Corporate) Fleet Refueling - Stage I; 

Submerged Filling w/o Controls 

40600706 BTP/BPS

Petroleum and Solvent Evaporation; Transportation and Marketing of Petroleum Products; Consumer (Corporate) Fleet Refueling - Stage I; 

Balanced Submerged Filling 

40600707 BTP/BPS

Petroleum and Solvent Evaporation; Transportation and Marketing of Petroleum Products; Consumer (Corporate) Fleet Refueling - Stage I; 

Underground Tank Breathing and Emptying 

40688801 BTP/BPS Petroleum and Solvent Evaporation; Transportation and Marketing of Petroleum Products; Fugitive Emissions; Specify in Comments Field 

2501050120 RBT Storage and Transport; Petroleum and Petroleum Product Storage; Bulk Terminals: All Evaporative Losses; Gasoline 

2501055120 BTP/BPS Storage and Transport; Petroleum and Petroleum Product Storage; Bulk Plants: All Evaporative Losses; Gasoline 

2501060050 BTP/BPS Storage and Transport; Petroleum and Petroleum Product Storage; Gasoline Service Stations; Stage 1: Total 

2501060051 BTP/BPS Storage and Transport; Petroleum and Petroleum Product Storage; Gasoline Service Stations; Stage 1: Submerged Filling 

2501060052 BTP/BPS Storage and Transport; Petroleum and Petroleum Product Storage; Gasoline Service Stations; Stage 1: Splash Filling 

2501060053 BTP/BPS Storage and Transport; Petroleum and Petroleum Product Storage; Gasoline Service Stations; Stage 1: Balanced Submerged Filling 

2501060200 BTP/BPS Storage and Transport; Petroleum and Petroleum Product Storage; Gasoline Service Stations; Underground Tank: Total 

2501060201 BTP/BPS Storage and Transport; Petroleum and Petroleum Product Storage; Gasoline Service Stations; Underground Tank: Breathing and Emptying 

2501995000 BTP/BPS Storage and Transport; Petroleum and Petroleum Product Storage; All Storage Types: Working Loss; Total: All Products 

2505000120 RBT Storage and Transport; Petroleum and Petroleum Product Transport; All Transport Types; Gasoline 

2505020120 RBT Storage and Transport; Petroleum and Petroleum Product Transport; Marine Vessel; Gasoline 
189

SCC Type Description

2505020121 RBT Storage and Transport; Petroleum and Petroleum Product Transport; Marine Vessel; Gasoline - Barge 

2505030120 BTP/BPS Storage and Transport; Petroleum and Petroleum Product Transport; Truck; Gasoline 

2505040120 RBT Storage and Transport; Petroleum and Petroleum Product Transport; Pipeline; Gasoline 

2660000000 BTP/BPS

Waste Disposal, Treatment, and Recovery; Leaking Underground Storage Tanks; Leaking Underground Storage Tanks; Total: All Storage 

Types 
190

Appendix C: Future Animal Population Projection Methodology, Updated 07/24/12

In the EPA’s ammonia inventory for animal agricultural operations (National Emission Inventory -

Ammonia Emissions from Animal Agricultural Operations; Revised Draft Report; April 22, 2005), 

population projections for the beef, dairy, swine, and poultry animal sectors were developed and used to 

estimate future ammonia emissions from these animal sectors. To develop the 2005 population projections, 

EPA used inventory data from the U.S. Department of Agriculture (USDA) and the Food and Agriculture 

Policy and Research Institute (FAPRI). 

Since completion of the 2005 ammonia emissions inventory, USDA and FAPRI have released updated 

reports that contain animal population data and projections. These data were used to update the 2005 animal 

inventory projections. The data sources and the methodology used to develop the population projections for 

each animal type are discussed below. These future projections do not account for any changes in animal 

populations or regional dislocations associated with EPA’s revised effluent limitations guidelines and 

standards for concentrated animal feeding operations promulgated in December 2002 (68 FR 7176, February 

12, 2003). Due to insufficient data, animal population projections and future emission estimates were not 

developed for sheep, goats, and horses. 

Dairy Cattle. The 2010 FAPRI U.S. and World Agricultural Outlook (FAPRI 2010) report provides 

estimated national milk cow inventory data and projections from 2009 through 2019 and shows an overall 

decline in U.S. dairy cow populations. The FAPRI projections depict an essentially linear relationship 

between 2001 milk cow populations and subsequent years. The EPA estimated future dairy cattle 

populations using a linear regression analysis of the national population data available from the FAPRI 

report, covering 1982 through 2019. Figure C-1 illustrates the linear projection of the U.S. dairy cow 

population and trend line.

Beef Cattle. The USDA Agricultural Projections to 2021 (USDAa) provides estimated national cattle 

inventory data and projections from 2010 through 2021. Beef production has a clear cycle generated by 

producers’ expectations about future prices, grain market cycles, and other economic conditions. The pace 

of the cycle is limited by the reproductive capacity of the animal. Cattle inventories can expand only as fast 

as cows can reproduce. This has historically resulted in a 7- to 12-year cycle, from peak to peak (Kohls, 

1998). Peaks and troughs of the cycle are 5 to 6 percent higher or lower than the general trend in cattle 

populations so the stage of the cycle can make a significant difference in population at any given future date.

The EPA decomposed the beef cow inventory time series into a trend line, a cyclical component, and a 

random error component (Bowerman, 1987). The trend line was estimated by linear regression of the 

inventory data from 1990 to 2015 on a time variable. The cyclical component was then estimated as the 

percentage deviation from the trend line in the historical data. A graph of that information appeared to show 

a cyclic trend (trough to peak). The robust U.S. economy of the 1990s may explain the longer than average 

cycle. With so little data, EPA assumed the down side of the cycle was symmetrical with the up side, so the 

data set would contain three values for each stage of the cycle. The average of the absolute value of the three 

observations represents the cyclical component. The EPA forecasted the trend line out to 2030 and adjusted 

it by the average percentage deviation from the trend for that stage of the cycle, as illustrated in Figure C-2.

The projection data for the beef cattle inventory show some difference in growth cycle of beef cows versus 

other beef cattle (e.g., steers, bulls). The EPA conducted a separate analysis of these animal populations. 

Other beef cattle populations appear to follow similar cycles and were forecasted using the same technique 

as beef cows (see Figure C-3).
191

Figure C-1. Dairy Cow Inventory Projections

Figure C-2. Beef Cow Inventory Projections

Raw data line: y = -28.545x + 90437

R2 = 0.0436

Adj. data line: y = -26.983x + 88178

R2 = 0.3417

29,000

30,000

31,000

32,000

33,000

34,000

35,000

36,000

Number Beef Cow 

(thousand head)

Year

U.S. Beef Cow Population
192

Figure C-3. Non-cow Beef Inventory Projections

Swine. Annual swine populations are categorized by breeding and market swine. The 2010 FAPRI U.S. and 

World Agricultural Outlook (FAPRI 2010) report presents annual inventory data and projections from 2009 

through 2019 for breeding swine and market swine inventories (rather than a combined total). The FAPRI 

data show an overall increase in swine production over time. Due to increasing productivity (i.e., increased 

number of pigs per litter), the population of breeding swine is expected to decline over the long term.

The EPA estimated future swine populations using a cycle and trend decomposition analysis. Breeding and 

market swine population projections and inventory data from the FAPRI report capture the variability of the 

swine production cycle. Changes in the pork industry in the 1990’s have made recent data atypical and 

inconsistent. For example, EPA replaced the 1996 market hog cyclical deviation with the average of all of 

the other data because they were so far out of line with the hog cycle.

The EPA estimated the trend and deviations from the trend as in the beef cattle analysis. However, it was 

not possible to apply the identical technique from the beef cattle industry to the hog industry because a welldefined periodic cycle was not evident in the annual data. The EPA evaluated a 3-year moving average of 

the deviation to further reduce the random component. As the smoothed cycle continued to appear irregular, 

EPA assumed that the 2010’s will repeat the pattern of the 1990’s. Breeding hog populations were estimated 

using a similar approach. See Figures C-4 and C-5 for an illustration of the swine projections for the market 

hog and breeding hog inventories, respectively.

Poultry. Annual poultry populations in the EPA’s ammonia emissions inventory for animal agriculture are 

presented for broilers, turkeys, and layers. To project poultry populations, EPA used population and 

Raw data line: y = -120.28x + 295808

R2 = 0.3119

Adj. data line: y = -145.51x + 347612

R2 = 0.9452

50,000

51,000

52,000

53,000

54,000

55,000

56,000

57,000

58,000

59,000

60,000

Non-cow Inventory (thousand head)

Year

U.S. Beef Non-cow Population 
193

projection data from the annual summary of the USDA/NASS Poultry – Production and Value reports 

(USDAb) for broilers and turkeys, and the Chickens and Eggs reports (USDAc). With these data, EPA used 

a linear regression analysis to predict the number of birds produced in the U.S. for years beyond 2011. 

Figures C-6 and C-7 present the population projections for broilers and turkeys, respectively. Figure C-8 

shows the population projections for egg layers.

Figure C-4. Market Hog Inventory Projections

Figure C-5. Breeding Hog Inventory Projections

Raw data line: y = 0.5161x - 978.44

R2 = 0.9284

Adj. data line: y = 0.5276x - 1001.5

R2 = 0.982

40

45

50

55

60

65

70

75

Market Hog Inventory

(million head)

Year

U.S. Market Hog Population

Raw data line: y = -0.0493x + 105.01

R2 = 0.8486

Adj. data line: y = -0.0458x + 98.155

R2 = 0.9277

4.00

4.50

5.00

5.50

6.00

6.50

7.00

7.50

8.00

Breeding Hog Inventory

(million head)

Year

U.S. Breeding Hog Population
194

Figure C-6. Broiler Inventory Projection

Figure C-7. Turkey Inventory Projection

y = 135606x - 3E+08

R2 = 0.8276

0

2

4

6

8

10

12

14

Million Broilers

Year

U.S. Broiler Population

y = -2204.3x + 5E+06

R2 = 0.6536

100,000

150,000

200,000

250,000

300,000

350,000 Number of Turkeys

Year

U.S. Turkey Population
195

Figure C-8. Egg Layer Projection

References

Bowerman, Bruce L. and Richard T. O’Connell (1987) Time Series Forecasting: Unified Concepts and 

Computer Implementation. Second Edition. Boston, MA. Duxbury Press.

FAPRI (2010). FAPRI 2010 U.S. and World Agricultural Outlook. January 2010. Food and Agricultural 

Policy Research Institute. Iowa State University and University of Missouri-Columbia. 

http://www.fapri.iastate.edu/outlook/2010/text/Outlook_2010.pdf

Kohls, Richard L. and Joseph N. Uhl. (1998) Marketing Edition. Upper Saddle River, NJ Prentice Hall.

USDA (2012a). USDA Agricultural Projections to 2021. Interagency Agricultural Projections Committee. 

February 2021. 

http://www.usda.gov/oce/commodity/archive_projections/USDAAgriculturalProjections2021.pdf

USDA (2012b). National Agricultural Statistics Service (NASS). Poultry - Production and Value Reports. 

http://usda.mannlib.cornell.edu/MannUsda/viewDocumentInfo.do?documentID=1130

USDA (2012c). NASS. Chickens and Eggs Annual Summary. 

http://usda.mannlib.cornell.edu/MannUsda/viewDocumentInfo.do;jsessionid=0AFEA5A73F0092B7498AC

B64B7CABBED?documentID=1509

y = 3,757.24x - 7,197,845.17

R2 = 0.86

250,000

270,000

290,000

310,000

330,000

350,000

370,000

Number of Layers (1,000)

Year

U.S. Egg Layer Population