WRAP POINT AND AREA 

SOURCE EMISSIONS 

PROJECTIONS FOR THE 

2018 BASE CASE 

INVENTORY, VERSION 1 

Prepared for:

Western Governors’ Association and 

The Western Regional Air Partnership, 

Stationary Sources Joint Forum 

 

Prepared by: 

 

Eastern Research Group, Inc. 

8950 Cal Center Drive 

Suite 348 

Sacramento, California 95826 

January 25, 2006 

Eastern Research Group, Inc. 
3484.00.002.003 

WRAP POINT AND AREA SOURCE EMISSIONS 

PROJECTIONS FOR THE 2018 BASE CASE 

INVENTORY, VERSION 1 

Prepared for:

Western Governors’ Association (WGA) and the 

Western Regional Air Partnership (WRAP), 

Stationary Sources Joint Forum (SSJF) 

Denver, Colorado 

Prepared by:

Eastern Research Group, Inc. 

8950 Cal Center Drive 

Suite 348 

Sacramento, California 95826 

January 25, 2006
WRAP 2018 Base Case Inventory 

Version 1, January 2006 

i

TABLE OF CONTENTS 

Section Page 

ACRONYMS................................................................................................................................. iv 

PREFACE..................................................................................................................................... vii 

1.0 INTRODUCTION ........................................................................................................... 1-1 

 1.1 Inventory Characteristics ..................................................................................... 1-2 

 1.2 Methodology Overview ....................................................................................... 1-4 

 1.3 Contents of this Report ........................................................................................ 1-7 

2.0 POST-2002 ADJUSTMENTS......................................................................................... 2-1 

 2.1 New, Retired, or Omitted Facilities ..................................................................... 2-1 

 2.2 PM/Combustion Emission Corrections................................................................ 2-1 

3.0 POST-2002 CONTROL FACTORS................................................................................ 3-1 

 3.1 National Wood Products Initiative....................................................................... 3-1 

 3.2 National Petroleum Refinery Initiative................................................................ 3-4 

 3.3 Maximum Achievable Control Technologies Standards ..................................... 3-5 

 3.4 Other Unquantified Regulatory Impacts.............................................................. 3-8 

4.0 GROWTH FACTOR AND RATE ANALYSIS ............................................................. 4-1 

 4.1 Electricity Generating Units ................................................................................ 4-1 

 4.1.1 Coal-Fired EGUs ..................................................................................... 4-1 

 4.1.2 Other EGUs.............................................................................................. 4-3 

 4.1.3 Future EGUs ............................................................................................ 4-4 

 4.2 Other Point Sources ............................................................................................. 4-9 

 4.2.1 EGAS Growth Factor Model ................................................................... 4-9 

 4.2.2 Oil and Gas Growth Factors .................................................................. 4-10 

 4.3 Area Sources ...................................................................................................... 4-11 

 4.3.1 EIA Energy Projections ......................................................................... 4-11 

 4.3.2 USDA Agricultural Projections ............................................................. 4-11 

 4.4 California Point and Area Sources..................................................................... 4-12 

5.0 POINT SOURCE RETIREMENT AND REPLACEMENT........................................... 5-1 

 5.1 SCC Identification ............................................................................................... 5-1 

 5.2 Modifications to Methodology for EGUs............................................................ 5-3 

6.0 OTHER INFORMATION USED TO DEVELOP THE 2018 BASE 

CASE PROJECTIONS .................................................................................................... 6-1 

6.1 Permit Limits ....................................................................................................... 6-1 

6.2 Section 309 Flags................................................................................................. 6-1 

6.3 Data Formatting ................................................................................................... 6-9 
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TABLE OF CONTENTS – CONT. 

Section Page 

7.0 2018 BASE CASE INVENTORY RESULTS ................................................................ 7-1 

8.0 REFERENCES ................................................................................................................ 8-1 

APPENDIX A: Additional 2018 Base Case Inventory (Version 1) Summaries 

APPENDIX B: Errata 

Tables Page 

2-1 Summary of New and Retired Facilities, and Other Adjustments................................... 2-2 

2-2 Correction Ratios for Combustion Emission Factors, by SCC........................................ 2-5 

3-1 Summary of Post-2002 Point and Area Source Control Impacts .................................... 3-2 

3-2 Refineries in WRAP States Subject to the National Petroleum Refinery Initiative ........ 3-5 

4-1 Future Electricity Generation Analysis – Coal-Fired EGUs............................................ 4-5 

4-2 Future Electricity Generation Analysis – Natural Gas-Fired EGUs................................ 4-5 

4-3 Coal-Fired EGUs that are New (2003 or 2004), Under Construction, 

 or Being Permitted ........................................................................................................... 4-6 

4-4 Allocation of Future Coal EGUs...................................................................................... 4-7 

4-5 County-Level Allocation of Future Coal-Fired EGUs..................................................... 4-8 

4-6 Emission Rates for Future New Coal-Fired EGUs.......................................................... 4-9 

4-7 Emission Rates for Future New Natural Gas-Fired EGUs .............................................. 4-9 

4-8 Regional 2002 to 2018 Oil and Gas Growth Factors..................................................... 4-11 

4-9 CEFS Modeling File Format.......................................................................................... 4-12 

5-1 Retirement and Replacement SCCs, Lifetimes, and Retirement Rates ........................... 5-2 

5-2 Retirement and Replacement Reduction Factors............................................................. 5-4 

5-3 Information Used to Develop Retirement and Replacement Reduction Factors............. 5-5 

6-1 WRAP Facilities Subject to RHR Section 309 Requirements, 

 Based on 2002 Emissions ............................................................................................... 6-2 

6-2 WRAP Facilities Shown in Appendix A-1 of 2003 SO2 Milestone Report, 

 and with 2002 SO2 Emissions Less than 100 Tons.......................................................... 6-8 

7-1 2002 and 2018 Base Case – Point Source Emissions by State and Tribe, Version 1 ...... 7-2 
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TABLE OF CONTENTS – CONT. 

7-2 2002 and 2018 Base Case – Point Source Emissions by Sector, Version 1 .................... 7-4 

7-3 2002 and 2018 Base Case – Area Source Emissions by State and Tribe, Version 1....... 7-8 

7-4 2002 and 2018 Base Case – Area Source NOx Emissions by Sector, Version 1........... 7-10 

7-5 2002 and 2018 Base Case – Area Source SO2 Emissions by Sector, Version 1 ........... 7-14 

7-6 2002 and 2018 Base Case – Area Source PM10 Emissions by Sector, Version 1 ......... 7-18 

Figures Page 

1-1 WRAP and CENRAP States and Tribes Included in the WRAP 2018 

Base Case Emissions Inventory....................................................................................... 1-3 

1-2 Roadmap for Development of the WRAP 2018 Base Case Inventory ............................ 1-5 

7-1 WRAP Point and Area Source 2002 and 2018 NOx Emissions, Version 1................... 7-23 

7-2 WRAP Point and Area Source 2002 and 2018 SO2 Emissions, Version 1.................... 7-24 

7-3 WRAP Point and Area Source 2002 and 2018 VOC Emissions, Version 1.................. 7-25 

7-4 WRAP Point and Area Source 2002 and 2018 PM10 Emissions, Version 1.................. 7-26 
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ACRONYMS 

ARB California Air Resources Board 

BACM best available control measures 

Btu British thermal unit 

CAA Clean Air Act 

CAMD Clean Air Markets Division 

CAP criteria air pollutant 

CD consent decree 

CEFS California Emission Forecasting System 

CEIDARS California Emission Inventory Development and Reporting System 

CEM continuous emissions monitor 

CENRAP Central Regional Air Planning Association 

CF capacity factor 

CO carbon monoxide 

CT capacity threshold 

EAC Early Action Compact 

EDMS Emissions Data Management System 

EGAS Economic Growth and Analysis System 

EGU electricity generating unit 

EIA Energy Information Administration 

EIC emission inventory code 

ER emission rate 

ERG Eastern Research Group 
WRAP 2018 Base Case Inventory 

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FCCU fluidized catalytic cracking unit 

GF growth factor 

HI heat input 

IAS Integrated Assessment System 

IDA Inventory Data Analyzer 

lbs pounds 

MACT maximum achievable control technology 

MDF medium density fiberboard 

MMBtu million British thermal units 

MMscf million standard cubic feet 

MW megawatts 

MWh megawatt-hours 

NAR Native American Reservation 

NEAP Natural Events Action Plan 

NESHAP National Emissions Standards for Hazardous Air Pollutants 

NH3 ammonia 

NIF National Emissions Inventory Format 

NOx nitrogen oxides 

NSCR non-selective catalytic reduction 

NSPS New Source Performance Standards 

NSR New Source Review 

PM particulate matter 

PM2.5 particulate matter less than 2.5 micrometers in aerodynamic diameter 

PM10 particulate matter less than 10 micrometers in aerodynamic diameter 
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PSD Prevention of Significant Deterioration 

RCO regenerative catalytic oxidation 

RHR Regional Haze Rule 

RICE reciprocating internal combustion engines 

RMC Regional Modeling Center 

ROG reactive organic gases 

RTO regenerative thermal oxidation 

SCE Southern California Edison 

scf standard cubic foot 

SCR selective catalytic reduction 

SIP State Implementation Plan 

SMOKE Sparse Matrix Operator Kernel Emissions 

SO2 sulfur dioxide 

SRP Salt River Project 

SSJF Stationary Sources Joint Forum 

TEP Tucson Electric Power 

TPY tons per year 

U.S. EPA U.S. Environmental Protection Agency 

VOC volatile organic compounds 

WGA Western Governors’ Association 

WRAP Western Regional Air Partnership 

μm micrometer 
WRAP 2018 Base Case Inventory 

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PREFACE 

Regulatory Framework for Tribal Visibility Implementation Plans 

The Regional Haze Rule explicitly recognized the authority of tribes to implement the 

provisions of the Rule, in accordance with principles of Federal Indian law, and as provided by 

the Clean Air Act §301(d) and the Tribal Authority Rule (TAR) (40 CFR §§49.1-.11). Those 

provisions create the following framework: 

1. Absent special circumstances, reservation lands are not subject to state jurisdiction. 

2. Federally recognized tribes may apply for and receive delegation of federal authority to 

implement CAA programs, including visibility regulation, or “reasonably severable” 

elements of each programs (40 CFR §§49.3, 49.7). The mechanism for this delegation is 

a Tribal Implementation Plan (TIP). A reasonable severable element is one that is not 

integrally related to program elements that are not included in the plan submittal, and is 

consistent with applicable statutory and regulatory requirements. 

3. The Regional Haze Rule expressly provides that tribal visibility programs are “not 

dependent on the strategies selected by the state or states in which the tribe is located” 

(64 Fed. Reg. 35756), and that the authority to implement §309 TIPs extends to all tribes 

within the GCVTC region (40 CFR §51.309(d)(12). 

4. The U.S. EPA has indicated that under the TAR tribes are not required to submit §309 

TIPs by the end of 2003; rather they may choose to opt-in to §309 programs at a later 

date (67 Fed. Reg. 30439). 

5. Where a tribe does not seek delegation through a TIP, U.S. EPA, as necessary and 

appropriate, will promulgate a Federal Implementation Plan (FIP) within reasonable 

timeframes to protect air quality in Indian country (40 CFR §49.11). EPA is committed 

to consulting with tribes on a government to government basis in developing tribespecific or generally applicable TIPs where necessary (See, e.g. 63 Fed. Reg. 7263-64). 

It is our hope that the findings and recommendations of this report will prove useful to 

tribes, whether they choose to submit full or partial 308 or 309 TIPs, or work with U.S. EPA to 

develop FIPs. The amount of modification necessary will vary considerably from tribe to tribe. 

The authors have striven to ensure that all references to tribes in the document are consistent 

with principles of tribal sovereignty and autonomy as reflected in the above framework. Any 

inconsistency with this framework is strictly inadvertent and not an attempt to impose 

requirements on tribes which are not present under existing law. 
WRAP 2018 Base Case Inventory 

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1.0 INTRODUCTION 

The Western Regional Air Partnership (WRAP) is assessing impacts and evaluating 

control strategies pertaining to regional haze within its geographic domain (States of Alaska, 

Arizona, California, Colorado, Idaho, Montana, Nevada, New Mexico, North Dakota, Oregon, 

South Dakota, Utah, Washington, Wyoming, and the Native American Reservations located 

within these states). The WRAP’s Stationary Sources Joint Forum (SSJF) sponsored a project to 

provide WRAP work groups and forums with data, information, and assessments necessary for 

developing regional haze control strategies. This project was conducted by Eastern Research 

Group, Inc. (ERG) and its subcontractors, ENVIRON International Corporation and Alpine 

Geophysics, LLC, for the WRAP SSJF under Contract No. 30204-101 with the Western 

Governors’ Association (WGA). This work was conducted as part of a multi-task effort for the 

WRAP SSJF, which included the following tasks: 

• Task 1A: WRAP 2002 point and area (non-oil and gas) sources emissions inventory 

quality assurance; 

• Task 1B: WRAP 2002 and 2018 oil and gas (area sources) emissions inventory; 

• Task 1C: WRAP 2018 base case point and area sources (non-oil and gas) emissions 

inventory; 

• Task 2: Control technology analysis; 

• Task 3: Tribal inventories for 2002 and 2018; 

• Task 4: California inventories for 2002 and 2018; and 

• Temporal profiles for WRAP electric generating units. 

This report contains details pertaining to the data and methods used, and results achieved 

for Task 1C (2018 base case) and Task 4 (California inventories for 2018). Also, in order to 

provide a comprehensive set of emissions inventory summaries in this report, the results from 

Tasks 1A, 1B, and 3 are incorporated. 

The specific objectives of the 2018 base case inventory task were as follows: 

• Develop and implement a transparent methodology that would be understood and 

transferred to the WRAP SSJF; member tribal, state, and local agencies; and stakeholders; 
WRAP 2018 Base Case Inventory 

Version 1, January 2006 

1-2

• Use information collected from the tribal, state, and local agencies, and stakeholders to 

the greatest extent possible; 

• Provide a technically sound basis for development of control strategies to be used in 

regional haze analyses; 

• Establish a format that facilitates conversion of results into various formats including 

U.S. EPA’s National Emissions Inventory Format (NIF) Version 3.0 and Inventory Data 

Analyzer (IDA) format for use with the Sparse Matrix Operator Kernel Emissions 

(SMOKE) modeling system; and 

• Provide a comprehensive set of growth and control factors. 

1.1 Inventory Characteristics 

The characteristics of this annual emissions inventory for the year 2018 base case are 

discussed below. The year of 2018 is the year by which the visibility in federal Class 1 areas 

should be restored to its natural condition. This “attainment” year for visibility is required by the 

federal Regional Haze Rule (RHR). 

The geographic domain covered by this 2018 base case emissions inventory is shown in 

Figure 1-1 and includes the following: 

• WRAP states (AK, AZ, CA, CO, ID, MT, NV, NM, ND, OR, SD, UT, WA, and WY); 

• Central Regional Air Planning Association (CENRAP) states (AR, IA, KS, LA, MN, 

MO, NE, OK, and TX); 

• Native American Reservations (NARs) within the WRAP (i.e., the Arapahoe Tribe of the 

Wind River Reservation, the Assiniboine and Sioux Tribes of the Fort Peck Indian 

Reservation, the Cabazon Band of Cahuilla Mission Indians of the Cabazon Reservation, 

the Coeur d’Alene Tribe of the Coeur d’Alene Reservation, Confederated Tribes and 

Bands of the Yakama Nation, Confederated Tribes of the Colville Reservation, 

Confederated Tribes of the Umatilla Reservation, Fort Mojave Indian Tribe of Arizona, 

Gila River Indian Community of the Gila River Indian Reservation, La Posta Band of 

Diegueno Mission Indians of the La Posta Indian Reservation, Navajo Nation, Pueblo of 

Laguna, Pueblo of Santa Ana, Salt River Pima-Maricopa Indian Community of the Salt 

River Reservation, Shoshone-Bannock Tribes of the Fort Hall Reservation, Tohono 

O’Odham Nation, Ute Mountain Ute Tribe of the Ute Mountain Ute Reservation); and 

• NARs within the CENRAP (i.e., Fond du Lac Tribe and the Leech Lake Band of 

Ojibwe). 
WRAP 2018 Base Case Inventory 1-3 

Version 1, January 2006 Figure 1-1. WRAP and CENRAP States and Tribes Included in the WRAP 2018 Base Case Em
WRAP 2018 Base Case Inventory 

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1-4

The sources included in the 2018 base case inventory are point sources and area 

(nonpoint) stationary sources. Certain area source categories that were not included in this 

project, but were dealt with in other WRAP projects and contracts include the following: 

• Fugitive dust from paved and unpaved roads (SCCs 2294xxxxxx, 2296xxxxxx); 

• Windblown dust (27014xxxxx, 27301xxxxx); 

• Wildfires, waste burning, agricultural burning (SCCs 28015xxxxx, 28100xxxxx); and 

• Agricultural production-livestock (SCCs 2805xxxxxx). 

Also, no nonroad mobile sources (e.g., commercial marine, locomotives, aircraft, etc.) were 

included in this inventory of point and area sources. 

The pollutants that form the 2018 base case projection inventory are nitrogen oxides 

(NOx), sulfur dioxide (SO2), volatile organic compounds (VOC), carbon monoxide (CO), 

particulate matter (PM) with an aerodynamic diameter of less than 10 micrometers (μm) (PM10) 

and less than 2.5 μm (PM2.5), and ammonia (NH3). 

The actual pollutants included in the 2018 base case inventory for a given point or area 

source category are dependent upon those pollutants included in the 2002 WRAP inventory for 

that source. For example, if only PM10-Filterable and PM2.5-Filterable (and not PM10-Primary 

and PM2.5-Primary) are included in the 2002 inventory for a given source, then only those 

pollutants are included in the 2018 base case inventory (i.e., no 2002 emissions or pollutants 

were augmented or gap filled as part of the 2018 task). 

1.2 Methodology Overview 

Figure 1-2 shows the steps followed to project the WRAP 2002 emissions inventory to 

the year 2018. The data and calculations for each of the layers in this roadmap were stored in an 

Excel spreadsheet for each state, and a single spreadsheet for the WRAP tribes. The types of 

information used in each step are described as follows: 

• 2002 Emissions Inventory. This information was taken from the revised 2002 WRAP 

point and area source inventory updated in Task 1A, and included the following fields: 
WRAP 2018 Base Case Inventory 

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Figure 1-2. Roadmap for Development of the WRAP 2018 Base Case Inventory 

CA 

Emissions 

CENRAP 

Emissions 

Area Source 

Oil and Gas 

Emissions 

2018 Base Case Emissions 

EGUs Point Oil and All Others 

Gas 

Fuel All Others 

Combustion

Agricultural 

Sources 

EGUs Point Oil and All Others 

Gas 

CAMD EGAS DOE USDA EGAS 

2002 

Emissions

2018 

Emissions

Other Projection Information:

* Permit limits 

* Section 309 Sources 

Adjustments

Control 

Factors

Growth 

Factors

New and Retired Facilities, PM Adjustments 

Oil and Gas 

Growth Factors

Fuel All Others 

Combustion

Agricultural 

Sources 

Area Source Oil and 

Gas Emissions 

Revised WRAP 2002 Point and CA Emissions

Area Source Inventory 

(excluding fire and windblown dust) 

2002 Point 

Sources 

2002 Area 

Sources 

Enforceable Agreements, Consent Decrees, New Rules and Regulations, Denver EAC, etc. 

PM Adjustments 
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⎯ State and County FIPS 

⎯ State facility identifier 

⎯ Emission unit ID 

⎯ Process ID 

⎯ Pollutant code 

⎯ Emission release point ID 

⎯ Emission numeric value 

⎯ Emission unit numerator 

⎯ Tribal code 

⎯ Primary SIC and NAICS 

⎯ Facility name 

⎯ City 

⎯ SCC 

⎯ BART flag (i.e., 1-Yes; 2-Likely; 3-Potential; 4-Do not know; 5-No) 

• Adjustments: 

⎯ Emissions for new facilities that have come on-line since 2002 

⎯ Corrections for facilities that retired in 2003 or 2004 and will not return to 

operation in the future 

⎯ Other (i.e., ratios to correct certain PM10 and PM2.5 emission factors/SCCs for 

combustion of natural gas) 

• Control Factors: Emission reductions due to known (i.e., on-the-books) controls, consent 

decrees reductions, SIP control measures, and other relevant regulations that have gone 

into effect since 2002, or will go into effect before the end of 2018. These controls do not 

include impacts from any future control scenarios that have yet to be determined. 

• Growth Factors: SCC-specific growth factors developed from EGAS projection factor 

model; special analysis of EGU growth relative to unit capacity threshold. 

• Retirement and replacement rates: Effects of retirement estimated using annual 

retirement rates based on expected equipment lifetimes. Retired equipment replaced by 
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lower-emitting new equipment. Unit lifetimes examined for natural gas-fired EGUs; no 

retirements for coal-fired EGUs. 

• Permit Limits: Used in the cases where the projected emissions may have inadvertently 

exceeded an enforceable emission limit (i.e., emissions were adjusted downward to the 

permit limit, as applicable). 

• Section 309 Flags: Point sources in the Grand Canyon Visibility Transport States (i.e., 

AZ, CA, CO, ID, NV, NM, OR, UT, and WY) whose 2002 facility-level SO2 emissions 

are at least 100 tons/year. 

An extensive data collection effort was conducted to identify the information needs for 

the adjustments, control factors, growth factors, retirement and replacement rates, and permit 

limits, etc. needed to develop the various factors and data needed for the projections. The actual 

data collected, adjustments made, factors calculated, and results are described in detail in the 

remaining sections of this report. 

Part of this WRAP 2018 projection process included numerous telephone conferences 

with the WRAP SSJF Projections Workgroup, who provided input and feedback on proposed 

methods for various source sectors, especially electric generating units. A draft 2018 base case 

inventory was generated and distributed to all affected states and tribal entities for review. Based 

upon comments received, the 2018 base case was revised and is published in this report. The 

inventory spreadsheets were used to develop emissions inventory summaries and distribute to the 

WRAP states, tribes, and other stakeholders as Version 1. The results were formatted using NIF 

3.0 for input in to the WRAP Emissions Data Management System (EDMS), and were formatted 

into IDA format and used in the SMOKE modeling system as part of the “base18a” modeling 

scenario. 

1.3 Contents of this Report 

The remainder of this report includes the following sections and content: 

• Section 2.0 – Discussion of the adjustments that were made to the 2002 emissions 

inventory to reflect post-2002 conditions for point and area sources. These include post2002 changes such as new facilities, retired facilities, and PM emission factor corrections 

for natural gas combustion. 

• Section 3.0 – Explanation of the types of on-the-books controls (factors, emission rates, 

etc.) that were applied to the 2002 inventory to reflect controls that have been 

implemented, or will be implemented by 2018 and need to be considered in the 2018 base 
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case inventory. These include impacts such as the national wood products and refinery 

initiatives, reductions in emissions due to consent decrees, enforceable agreements, and 

other regulatory programs. 

• Section 4.0 – Details on the growth factors and rates used to project the 2002 inventory 

forward to 2018. This discussion also covers the details of how the emission projections 

for California were developed and incorporated into the overall WRAP 2018 base case 

inventory 

• Section 5.0 – Description of the retirement and replacement rates used for the point 

sources in the WRAP domain to reflect turnover of older equipment with new equipment 

emitting at (generally) BACT levels. 

• Section 6.0 – Explanation of the other information used to develop and report the 2018 

base case inventory, including incorporation of permit limits, Regional Haze Rule 

Section 309 flags for applicable sources, and data formatting. 

• Section 7.0 – Results of the 2018 base case inventory at the state and sector levels, 

including comparisons with the 2002 emissions inventory. 

• Section 8.0 – Listing of references used in the development of the 2018 base case 

inventory. 

• Appendix A – Additional 2018 base case inventory (Version 1) summaries. 

• Appendix B – Errata, containing a list of potential changes to Version 1 of the 2018 base 

case inventory. 

Also, in addition to this report and its appendices, several sets of electronic files have 

been delivered under the scope of this project; these include the following: 

• Zipped spreadsheets containing the detailed calculations used to develop the 2018 base 

case emissions inventory (version 1): 

⎯ AK_projections_122105_ver1.xls 

⎯ AZ_projections_122105_ver1.xls 

⎯ CO_projections_122105_ver1.xls 

⎯ ID_projections_122105_ver1.xls 

⎯ MT_projections_122105_ver1.xls 

⎯ ND_projections_122105_ver1.xls 

⎯ NM_projections_122105_ver1.xls 
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⎯ NV_projections_122105_ver1.xls 

⎯ OR_projections_122105_ver1.xls 

⎯ SD_projections_122105_ver1.xls 

⎯ UT_projections_122105_ver1.xls 

⎯ WA_projections_122105_ver1.xls 

⎯ WY_projections_122105_ver1.xls 

⎯ Tribes_projections_122105_ver1.xls 

• Zipped spreadsheet containing growth and control factors provided by the California Air 

Resources Board: CA_growth_control_2018.xls 
WRAP 2018 Base Case Inventory 

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2.0 POST-2002 ADJUSTMENTS 

To provide the basis for an accurate projections inventory, adjustments were made to the 

WRAP 2002 point and area source inventory to reflect changes in sources and emissions that have 

occurred since the 2002. These adjustments had the form of new facilities and emissions, or, in 

some cases, factors that were multiplied by the 2002 baseline inventory. This section discusses the 

various types of adjustments made to the 2002 WRAP emissions in order to achieve an up-to-date 

accounting of actual emissions. 

2.1 New, Retired, or Omitted Facilities 

Table 2-1 lists the facilities that have either come on-line or have been retired since 2002, 

facilities (or specific units at facilities) that, for various reasons, needed to be corrected from their 

2002 levels (e.g., emissions reported to the U.S. EPA Clean Air Marketing Division [CAMD] 

database but not included in the 2002 WRAP inventory, uncharacteristically high or low emissions 

in 2002, duplicate facility record or SCC). 

In addition to the new facilities shown on Table 2-1, there were several other new facilities in 

the WRAP states that even though their existence is known, they could not be added to the 

projections due to lack of information (e.g., hourly emissions instead of annual emissions, etc.). 

These included the North Border #5, Manning, Silurian, Golva Compressor Stations in North 

Dakota; and, the South Pavilion Compressor Station on the Wind River Reservation (Arapahoe 

Tribe, Wyoming). 

2.2 PM/Combustion Emission Corrections 

Table 2-2 lists the ratios developed and distributed by U.S. EPA to correct certain natural gas 

and liquefied petroleum gas combustion emission factors (Huntley, 2005). As it is currently 

understood, U.S. EPA will apply these ratios when finalizing the 2002 National Emissions Inventory 

(NEI), thus it was felt that the WRAP inventory should reflect this change as well, and that the most 

appropriate place to make this change was in the 2018 base case inventory (and not in the 2002 

inventory, since this would create an inconsistency with most 2002 state emission inventories.) 

These ratios were applied at the SCC level to adjust the WRAP 2002 emissions prior to applying 
WRAP 2018 Base Case Inventory 

Version 1, January 2006

2-2

Table 2-1. Summary of New and Retired Facilities, and Other Adjustments 

Type of Adjustmenta

Facility Name 

State or Tribe 

(County 

FIPS) New Retire 

CAMD 

Addb Other 

El Paso Natural Gas, Casa Grande 

Compressor Station 

AZ (021) 9 

Cactus Waste Systems AZ (021) 9 

APS West Phoenix Power Plant, 

Units 1, 2, 4, 7, 10, 12 

AZ (013) 

Kyrene Generating Station, Units 

4, 9, 10, 11, 12, 15, 16, 

AZ (013) 

Ocotillo Power Plant, Units 9, 11 AZ (013) 

Added non-CAMD EGUs 

located at facilities with 

CAMD EGUs, which were not 

accounted for 2002 emissions 

inventory. 

New Harquahala Generating 

Company, LLC 

AZ (013) 9 

Mesquite Generating Station AZ (013) 9 

PPL Sundance Energy AZ (021) 9

APS Saguaro Power Plant AZ (021) 9

APS West Phoenix Power Plant AZ (013) 9 

De Moss Petrie Generating Station AZ (019) 9

Gila River Power Station AZ (013) 9 

Griffith Energy LLC AZ (015) 9

San Manuel Smelter and Mill AZ (021) 9 

Nucor Steel Kingman LLC 

(previously North Star Steel AZ) 

AZ (015) Removed (permit terminated) 

Blue Spruce Energy Center CO (001) 9 

Front Range Power Plant CO (041) 9 

Platte River Power Authority – 

Rawhide (Unit D) 

CO (069) 9 

Rocky Mountain Energy Center CO (123) 9 

Public Service Co – Arapahoe 

(Units 1 and 2) 

CO (031) 9 

Holcim (US) Inc., Fort Collins CO (069) Reduced production and 

emissions after 2002 

Manchief Power Company, LLC CO (087) Removed (duplicate record) 

Mountain Home Generation 

Station 

ID (039) 9

Rathdrum Combustion Turbine 

Project 

ID (055) 9

Rathdrum Power, LLC ID (055) 9

Bittercreek Pipelines Compressor 

Station 

MT (021) 9 

Fiberglass Structures MT (111) 9 

Specialty Surgical Products MT (081) 9 

Glendive Generating Station (GT2) MT (021) 9

Asarco East Helena MT (049) 9 

Heating Plant ND (017) 9 

Amerada Hess: Dolphin ND (023) 9 

Amerada Hess: Antelope #1 ND (053) 9 

Antelope Plant No. 2 ND (053) 9 

Bear Paw Energy Inc.: Plaza ND (061) 9 

Royal Oak Enterprises, Inc. ND (089) 9 

 
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Table 2-1. Cont. 

Type of Adjustmenta

Facility Name 

State or Tribe 

(County 

FIPS) New Retire 

CAMD 

Addb Other 

Milagro NM (045) 9

Metal Parts Mfg. NM (013) 9 

Magnum Compressor Station NM (015) 9 

La Rue Compressor Station NM (015) 9 

Remediation Project NM (015) 9 

Kemnitz Compressor Station NM (025) 9 

Lee Gas Plant NM (025) 9 

State 35 Compressor Station NM (025) 9 

La Maquina NM (045) 9 

Blanco Compressor Station NM (045) 9 

30-8 CDP Compressor Station NM (045) 9 

Las Vegas Cogen NV (003) 9 

Mirant Las Vegas, LLC NV (003) 9 

Reliant Energy–Bighorn NV (003) 9 

Genwest–Silverhawk NV (003) 9 

Nevada Power-Harry Allen NV (003) 9 

Kernriver-Goodsprings 

Compressor Station 

NV (003) 9 

El Dorado Energy NV (003) Removed (duplicate record) 

Tillamook Lumber OR (059) 9 

Kinzua Resources, Pilot Rock 

Sawmill 

OR (059) 9 

Klamath Cogeneration Project OR (035) 9

Klamath Energy, LLC OR (035) 9

Coyote Springs (CTG-2) OR (049) 9 

Weyerhaeuser Company OR (011) 9 

Huron SD (005) 9

Angus Anson SD (099) 9

Lange SD (103) 9

Nebo Power Station UT (049) 9 

Sierra Pacific Industries (SPI) WA 9 

Olympic Panel Products (OPP) WA 9 

Goldendale Energy Project WA (039) 9 

Chehalis Generation Facility WA (041) 9 

Frederickson Power LP WA (053) 9

Longview Aluminium, LLC WA (015) 9 

Tecnal Corp WA (057) 9 

American Millwork Inc. (closed) WA (033) 9 

Northwest Manufacturing Inc. WA (033) 9 

Meridian Automotive Systems Inc. WA (033) 9 

Derby Cycle Corp WA (033) 9 

Basin Electric Power Coop - 

Hartzog Generation Station 

WY (005) 9 

Basin Electric Power Coop - 

Arvada Generation Station 

WY (033) 9 

Basin Electric Power Coop - 

Barber Creek Generation Station 

WY (005) 9 

 
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Table 2-1. Cont. 

Type of Adjustmenta

Facility Name 

State or Tribe 

(County 

FIPS) New Retire 

CAMD 

Addb Other 

Black Hills Corp - WyGen I WY (005) 9 

Jonah Gas Gathering - Bird 

Canyon/Co. Line Compressor 

Station 

WY 9 

Jonah Gas Gathering - Luman 

Compressor Station 

WY 9 

Western Gas Resources - Baker 

Springs/Butcher Compressor 

Station 

WY 9 

Western Gas Resources - Horse 

Creek/Gas Draw Compressor 

Station 

WY 9 

Western Gas Resources - 

Pronghorn/Oryn Compressor 

Station 

WY 9 

Western Gas Resources - Sioux/Jr. 

Reno Compressor Station 

WY 9 

Western Gas Resources - 

Pumpkin/Bruno Compressor 

Station 

WY 9 

Jonah Gas Gathering - Falcon 

Compressor Station 

WY 9 

Burlington Resources - Bighorn 

Wells 

WY 9 

Chevron USA - Table Rock Field WY 9 

Chevron USA - Whitney 

Canyon/Carter Creek Wellfield 

WY 9 

Exxon Mobil Corporation - Black 

Canyon Dehydration. Facility 

WY 9 

Black Hills Corp., Simpson 2 WY (005) 9

KCS Mountain Resources, 

Ainsworth Flare 

WY (003) 9 

Belle Fourche Pipeline, South 

Hilight 

WY (005) 9 

Kinder Morgan Gopher Station WY (005) 9 

Astaris Coking Plant WY (023) 9 

American Collenoid Upton Plant WY (045) 9 

Calpine South Point Energy Center Tribe-604 9 

a

 Adjustment may apply to entire facility or to selected emission units at the facility. 

b

CAMD Add = NOx and SO2 from natural gas-fired EGUs based on CAMD reports were added to 2018 base case because these were 

not accounted for in 2002 emissions inventory. 
WRAP 2018 Base Case Inventory 2-5 

Version 1, January 2006 Table 2-2. Correction Ratios for Combustion Emission Factors, by SCC SCC SCC_DESC 

10100601 External Combustion Boilers: Electric Generation: Natural Gas: Boilers > 100 Million Btu/hr except Tangential 10100602 External Combustion Boilers: Electric Generation: Natural Gas: Boilers < 100 Million Btu/hr except Tangential 10100604 External Combustion Boilers: Electric Generation: Natural Gas: Tangentially Fired Units 10100701 External Combustion Boilers: Electric Generation: Process Gas: Boilers > 100 Million Btu/hr 10100702 External Combustion Boilers: Electric Generation: Process Gas: Boilers < 100 Million Btu/hr 10101001 External Combustion Boilers: Electric Generation: Liquefied Petroleum Gas (LPG): Butane 10101002 External Combustion Boilers: Electric Generation: Liquefied Petroleum Gas (LPG): Propane 10101003 

External Combustion Boilers: Electric Generation: Liquefied Petroleum Gas (LPG): Butane/Propane Mixture: Specify Percent Butane in Comments 

10200601 External Combustion Boilers: Industrial: Natural Gas: > 100 Million Btu/hr 10200602 External Combustion Boilers: Industrial Natural Gas: 10-100 Million Btu/hr 10200603 External Combustion Boilers: Industrial: Natural Gas: < 10 Million Btu/hr 10200604 External Combustion Boilers: Industrial: Natural Gas: Cogeneration 10200701 External Combustion Boilers: Industrial: Process Gas: Petroleum Refinery Gas 10200704 External Combustion Boilers: Industrial: Process Gas: Blast Furnace Gas 10200707 External Combustion Boilers: Industrial: Process Gas: Coke Oven Gas 10201001 External Combustion Boilers: Industrial: Liquefied Petroleum Gas (LPG): Butane 10201002 External Combustion Boilers: Industrial: Liquefied Petroleum Gas (LPG): Propane 10201003 

External Combustion Boilers: Industrial: Liquefied Petroleum Gas (LPG): Butane/Propane Mixture: Specify Percent Butane in Comments 

10201401 External Combustion Boilers: Industrial: CO Boiler: Natural Gas 10201402 External Combustion Boilers: Industrial: CO Boiler: Process Gas 10300601 External Combustion Boilers: Commercial/Institutional: Natural Gas: > 100 Million Btu/hr 10300602 External Combustion Boilers: Commercial/Institutional: Natural Gas: 10-100 Million Btu/hr 10300603 External Combustion Boilers: Commercial/Institutional: Natural Gas: < 10 Million Btu/hr 10301001 External Combustion Boilers: Commercial/Institutional: Liquefied Petroleum Gas (LPG): Butane 10301002 External Combustion Boilers: Commercial/Institutional: Liquefied Petroleum Gas (LPG): Propane 10301003 

External Combustion Boilers: Commercial/Institutional: Liquefied Petroleum Gas (LPG): Butane/Propane Mixture: 

Specify Percent Butane in Comments 

10500106 External Combustion Boilers: Space Heaters: Industrial: Natural Gas 10500110 External Combustion Boilers: Space Heaters: Industrial: Liquefied Petroleum Gas (LPG) 10500206 External Combustion Boilers: Space Heaters: Commercial/Institutional: Natural Gas 
WRAP 2018 Base Case Inventory 2-6 

Version 1, January 2006 Table 2-2. Cont. SCC SCC_DESC 

10500210 External Combustion Boilers: Space Heaters: Commercial/Institutional: Liquefied Petroleum Gas (LPG) 20100201 Internal Combustion Engines: Electric Generation: Natural Gas: Turbine 20200201 Internal Combustion Engines: Industrial: Natural Gas: Turbine 20200203 Internal Combustion Engines: Industrial: Natural Gas: Turbine: Cogeneration 20300202 Internal Combustion Engines: Commercial/Institutional: Natural Gas: Turbine 20400301 Internal Combustion Engines: Engine Testing: Turbine: Natural Gas 27300320 

Internal Combustion Engines: Off-highway LPG-fueled Engines: Industrial Equipment: Industrial Fork Lift: Liquefied Petroleum Gas (LPG) 

30290005 

Industrial Processes: Food and Agriculture: Fuel Fired Equipment: Liquefied Petroleum Gas (LPG): Process Heaters 

30500209 Industrial Processes: Mineral Products: Asphalt Concrete: Asphalt Heater: LPG 30590005 Industrial Processes: Mineral Products: Fuel Fired Equipment: Liquefied Petroleum Gas (LPG): Process Heaters 30600105 Industrial Processes: Petroleum Industry: Process Heaters: Natural Gas-fired 30600107 Industrial Processes: Petroleum Industry: Process Heaters: LPG-fired 30890004 

Industrial Processes: Rubber and Miscellaneous Plastics Products: Fuel Fired Equipment: Liquefied Petroleum Gas (LPG): Process Heaters 

31000404 Industrial Processes: Oil and Gas Production: Process Heaters: Natural Gas 31000414 Industrial Processes: Oil and Gas Production: Process Heaters: Natural Gas: Steam Generators 39000689 Industrial Processes: In-process Fuel Use: Natural Gas: General 39901001 Industrial Processes: Miscellaneous Manufacturing Industries: Process Heater/Furnace: LPG 40201004 

Petroleum and Solvent Evaporation: Surface Coating Operations: Coating Oven Heater: Liquefied Petroleum Gas 

(LPG) 

2101006000 Stationary Source Fuel Combustion: Electric Utility: Natural Gas: Total: Boilers and IC Engines 2101006001 Stationary Source Fuel Combustion: Electric Utility: Natural Gas: All Boiler Types 2101006002 Stationary Source Fuel Combustion: Electric Utility: Natural Gas: All IC Engine Types 2101007000 Stationary Source Fuel Combustion: Electric Utility: Liquefied Petroleum Gas (LPG): Total: All Boiler Types 2102006000 Stationary Source Fuel Combustion: Industrial: Natural Gas: Total: Boilers and IC Engines 2102006001 Stationary Source Fuel Combustion: Industrial: Natural Gas: All Boiler Types 2102006002 Stationary Source Fuel Combustion: Industrial: Natural Gas: All IC Engine Types 2102007000 Stationary Source Fuel Combustion: Industrial: Liquefied Petroleum Gas (LPG): Total: All Boiler Types 2103006000 Stationary Source Fuel Combustion: Commercial/Institutional: Natural Gas: Total: Boilers and IC Engines 
WRAP 2018 Base Case Inventory 2-7 

Version 1, January 2006 Table 2-2. Cont. SCC SCC_DESC 

2103007000 Stationary Source Fuel Combustion: Commercial/Institutional: Liquefied Petroleum Gas (LPG): Total: All Combustor Types 2103007005 Stationary Source Fuel Combustion: Commercial/Institutional: Liquefied Petroleum Gas (LPG): All Boiler Types 2103007010 

Stationary Source Fuel Combustion: Commercial/Institutional: Liquefied Petroleum Gas (LPG): Asphalt Kettle Heaters 

2104006000 Stationary Source Fuel Combustion: Residential: Natural Gas: Total: All Combustor Types 2104006010 Stationary Source Fuel Combustion: Residential: Natural Gas: Residential Furnaces 2104007000 Stationary Source Fuel Combustion: Residential: Liquefied Petroleum Gas (LPG): Total: All Combustor Types 2199007000 

Stationary Source Fuel Combustion: Total Area Source Fuel Combustion: Liquefied Petroleum Gas (LPG): Total: All Boiler Types 

20100202 Internal Combustion Engines: Electric Generation: Natural Gas: Reciprocating 20200202 Internal Combustion Engines: Industrial: Natural Gas: Reciprocating 20200204 Internal Combustion Engines: Industrial: Natural Gas: Reciprocating: Cogeneration 20200209 Internal Combustion Engines: Industrial: Natural Gas: Turbine: Exhaust 20200252 Internal Combustion Engines: Industrial: Natural Gas: 2-cycle Lean Burn 20200253 Internal Combustion Engines: Industrial: Natural Gas: 4-cycle Rich Burn 20200254 Internal Combustion Engines: Industrial: Natural Gas: 4-cycle Lean Burn 20200255 Internal Combustion Engines: Industrial: Natural Gas: 2-cycle Clean Burn 20200256 Internal Combustion Engines: Industrial: Natural Gas: 4-cycle Clean Burn 20300201 Internal Combustion Engines: Commercial/Institutional: Natural Gas: Reciprocating 20300203 Internal Combustion Engines: Commercial/Institutional: Natural Gas: Turbine: Cogeneration 20300204 Internal Combustion Engines: Commercial/Institutional: Natural Gas: Cogeneration 20300207 Internal Combustion Engines: Commercial/Institutional: Natural Gas: Reciprocating: Exhaust 20300209 Internal Combustion Engines: Commercial/Institutional: Natural Gas: Turbine: Exhaust 20301001 Internal Combustion Engines: Commercial/Institutional: Liquified Petroleum Gas (LPG): Propane: Reciprocating 20301002 Internal Combustion Engines: Commercial/Institutional: Liquified Petroleum Gas (LPG): Butane: Reciprocating 30290003 Industrial Processes: Food and Agriculture: Fuel Fired Equipment: Natural Gas: Process Heaters 30590003 Industrial Processes: Mineral Products: Fuel Fired Equipment: Natural Gas: Process Heaters 30600104 Industrial Processes: Petroleum Industry: Process Heaters: Gas-fired 30600106 Industrial Processes: Petroleum Industry: Process Heaters: Process Gas-fired Source: Huntley, 2005
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other factors in subsequent steps. Most of the ratios affect point sources (8-digit SCCs), 

although some area sources (10-digit SCCs) are affected as well. As the table shows, the impacts 

are significant, ranging from 92.3 to 95.4 percent decrease in PM10-Primary and 94.2 to 97.2 

percent decrease in PM2.5-Primary. (Although they are not shown on this table, U.S. EPA also 

recommended some PM-Condensable ratios). 

All of the adjustments shown on Tables 2-1 and 2-2 were applied to the 2002 inventory to 

achieve an intermediate inventory called “baseline planning inventory.” This intermediate 

inventory was used to check the impact of the adjustments made for reasonableness and quality 

assurance. The baseline planning inventory was the starting point for estimating the future year 

projections.
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3.0 POST-2002 CONTROL FACTORS 

Post-2002 control factors were calculated to reflect impacts from on-the-books controls 

(i.e., with implementation dates from 2003 to the end of 2018). These control factors are based 

on expected or actual post-2002 emission reductions from these general areas: 

• Compliance with consent decrees (CDs) resulting from enforcement of various federal 

regulations, such as New Source Review (NSR), Prevention of Significant Deterioration 

(PSD), and Title V permits, by U.S. EPA; 

• Air quality plan impacts from State Implementation Plan (SIP) implementation and other 

state programs to control air pollution, such as the Denver Early Action Compact (EAC) 

Ozone Plan, and implementation of Agricultural Best Management Practices in Maricopa 

County and Salt River SIP in Arizona; and 

• Public/private stakeholder agreements for improving air quality, such as the Denver 

Metro Emissions Reduction Project. 

In some cases, the effect of these post-2002 controls did not take the form of a factor, but 

rather an emission limit, shutdown of equipment, or some other condition. The post-2002 

controls applied to the WRAP 2002 inventory to develop the 2018 base case emissions inventory 

are summarized in Table 3-1. 

In addition to the controls summarized in Table 3-1 for which impacts were determined, 

there was a significant amount of information gathered for other types of control impacts that 

could not be quantified due to various reasons. Details pertaining to impacts that could not be 

quantified for some sources are described below. 

3.1 National Wood Products Initiative 

The wood products industry includes manufacturers of plywood, panelboard, medium 

density fiberboard (MDF), and oriented strand board. In 1988, the U.S. EPA began investigating 

the industry for a suspected nationwide pattern of noncompliance with the PSD regulations under 

the NSR provisions of the Clean Air Act and state rules. Within the WRAP region, settlements 

were reached with Willamette Industries (2000) and Boise Cascade Corporation (2002)1

. The 

 

1

http://www.epa.gov/compliance/resources/cases/civil/caa/wood/index.html 
WRAP 2018 Base Case Inventory 3-2 

Version 1, January 2006 Table 3-1. Summary of Post-2002 Point and Area Source Control Impacts Plant Name State or Tribe (County FIPS) Type of Control Impact and Exp

British Petroleum – Multiple Facilities (Bandami Development, Central Compressor Plant, Central Gas Facility, Central Power Station, Endicott Production Facility, Flow Station (#1, #2, #3), Gathering Center (#1, #2, #3), Lisburne Production Center, Milne Point Production Facility, Northstar Production Facility, Seawater Injection Plant East, Seawater Treatment Plant, PBU) 

AK (185) 

ConocoPhillips – Multiple Facilities (Central Production Facility (#1, #2, #3), Kaparuk Seawater Treatment Plant, Alpine Central Processing Facility) 

AK (185) 

Enforceable Agreement: Limits/reduces sulfur content in d

sources to 15 ppm or less before 2018. 

TEP – Springerville AZ (001) Consent Decree: Plant-wide NOx and SO2 cap allows cont

EGUs and construction of 1 new EGUs. Cap with 4 EGUs 

NOx by 12/31/09. 

Agricultural Tillage (SCC 280100003) AZ (027) Yuma County PM10 SIP: Reduction of 705 tons of PM10 d

agricultural best management practices (BMPs). 

Xcel – Comanche CO (101) Voluntary Agreement: This agreement allows construction 

reductions of 25% and SO2 reductions of 65% by July 09. 

Xcel: Arapahoe #1, #2, #3 Cherokee #2, #3, #4 Valmont #5 

CO (031) CO (001) CO (013) 

Denver Metro Emissions Reduction Project: Agreement sefor all plants combined (10,500 tons/year), and stipulates Adown (which occurred 12/31/02). Reductions realized in 2Cherokee #3 and #4 and Valmont #5. Increased scrubber eCherokee #2. 

Tri State – Craig #1, #2 CO (081) Visibility SIP: Agreement requires fabric filters to be insta

NOx reduced through over-fire air upgrades. All by 12/31/

through use of 2004 CAMD data for basis of 2018 base ca

Rocky Mountain Steel Mill CO (101) Consent Decree: In effect beginning 2005, includes shutdo

modification of electric arc furnace #4. New emission limi

emissions) as provided by CDPHE were used for 2018 bas

Condensate tanks at oil and gas wells and production facilities, and natural gas compressor and drip stations. 

CO (various) Denver Early Action Compact: VOC reduction of 47.5% a

Denver, Jefferson, Douglas, Broomfield, Boulder, Adams, Morgan, and Elbert counties by 2007. 

APS – Four Corners Power Plant Navajo Nation Voluntary Agreement: Post-2002 emission reductions for S

2004 CAMD data, and used as basis for 2018 base case pro
WRAP 2018 Base Case Inventory 3-3 

Version 1, January 2006 Table 3-1. Cont. Plant Name State (County FIPS) Type of Control Impact and Exp

SCE – Mohave #1, #2 NV (003) Consent Decree: Limits SO2 to 0.15 lb/MMBtu. Heat inpu

for each unit. Plant limits for 2 EGUs (per SCE and NDEP

tons SO2 by 12/31/05. Nevada Power – Reid Gardner NV (003) Agreement is currently under negotiation. 

Navajo Refining Co. – Artesia Refinery NM (015) Refinery Initiative/Consent Decree: Reductions effective b

decrease and 40% SO2 decrease from catalytic cracking un

NOx decrease from process heaters fired with process gas (

reductions provided by Navajo Refining Co. 

APS – San Juan Generating Station NM (045) Consent Decree: Requires reductions to PM, SO2, NOx, an

October 2007 (Unit 4); April 2008 (Unit 3); October 2008 2). Requires ultra low NOx burner for NOx (35% reduction

fabric filters for PM (70% reduction); SO2 control efficien

increase over current levels of control). 

Unnamed Power Plant ND Consent Decree: State is currently negotiating terms of CD Tesoro (BP Amoco) – Mandan Refinery ND (059) Refinery Initiative/Consent Decree: Reductions effective b

decrease from process heaters fired with gas (SCC 306001by North Dakota Department of Health. 

Lignite Gas Plant ND (013) Grasslands Plant ND (053) 

Both plants are now (2005) injecting all acid gas into deep 

emission from tail gas incinerator are now zero. 

Archer Daniels Midland – Corn Processing ND (067) Consent Decree: Reductions of 97 tons/year VOC, 10 tons

effective by April 2004. 

Boise Cascade – Medford and White City Plantsa OR (029) Wood Products Initiative/Consent Decree: Requires 95% V

installation of regenerative thermal oxidizers (RTOs). 

Boise Cascade – Elgin and La Grande Plantsa OR (061) Wood Products Initiative/Consent Decree: Requires 95% V

Regenerative thermal oxidizers (RTOs) installed in 2003. 

TransAlta – Centralia Power Plant WA (041) Consent Decree: Emission limits of 10,000 tons/year SO2 (

0.35 lb/mmBTU NOx; 0.010 g/dscf PM; 200 ppm CO (per 

effective 12/31/02. 

a Actual reductions not taken at White City and La Grande plants due to ambiguity between SCCs in inventory database and as indicated by Oregon D

approximately 273 tons in 2004, and could be taken if 2018 base case is revised.
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Willamette facilities affected within the WRAP states were located in Bend (now closed), 

Eugene, Foster, Springfield, and Albany, Oregon. The Boise Cascade facilities affected with the 

WRAP states were Emmett, Idaho (now closed); Kettle Falls, Washington; and, Island City (La 

Grande), Elgin, Medford, and White City, Oregon. In general, the settlements with both 

companies required significant VOC reductions (i.e., 90 to 95 percent), while minimizing NOx

and CO emissions. For the most part, VOC reductions were to be achieved through regenerative 

catalytic oxidation (RCO) or regenerative thermal oxidation (RTO) installed on the wood/veneer 

dryers. 

All of the operating Willamette facilities have achieved compliance with their respective 

settlement CDs as of 2002, thus it is not necessary to reflect on-the-books controls. Future VOC 

control impacts were estimated for the Boise Cascade facilities in Medford and Elgin, Oregon. 

VOC controls impacts (i.e., 273 tons achieved in 2004) for the Boise Cascade facilities in White 

City and La Grande, Oregon, were not applied to the 2018 base case inventory due to the 

inability to match the inventory SCCs with the information provided by Oregon DEQ; however, 

these could be applied to future versions of the WRAP 2018 emissions inventory, and have been 

included in Appendix B. 

3.2 National Petroleum Refinery Initiative 

U.S. EPA’s national petroleum refinery initiative is an enforcement and compliance 

strategy to address air emissions from the nation’s petroleum refineries. Since 2000, U.S. EPA 

has entered into 17 settlements with U.S. companies that refine over 75 percent of the nation’s 

petroleum2. The settlements focus on four main areas of the Clean Air Act (CAA): 

• NSR/PSD (affecting fluidized catalytic cracking units and heaters and boilers); 

• New Source Performance Standards (NSPS) (affecting flares, sulfur recovery units, and 

fuel gas combustion devices); 

• Leak detection and repair requirements; and 

• Benzene National Emissions Standards for Hazardous Air Pollutants (NESHAP). 

 

2

 http://www.epa.gov/compliance/resources/cases/civil/caa/oil/index.html 
WRAP 2018 Base Case Inventory 

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Table 3-2 lists the refineries within the WRAP region with CDs that have been negotiated 

as part of the national petroleum refinery initiative. As part of the development of the 2018 base 

case inventory, each CD was reviewed to determine the types of controls, emission limits, 

applicable equipment, and deadline for achieving reductions. However, most of the CD 

requirements call for preliminary studies to determine the most feasible and effective types of 

controls, installation of equipment that meets NSPS requirements, and other types of 

programmatic approaches. As a result, the specific mass reductions expected (e.g., mainly NOx, 

SO2, and PM) are not provided in the CD, or have yet to be fully negotiated. Of the 14 refineries 

listed in Table 3-2, specific emission reductions estimates were only available for two: BP 

Amoco Mandan Refinery and (Navajo Refining) Artesia Refinery; these are included in Table 3-

1 (above). 

Table 3-2. Refineries in WRAP States Subject to the National Petroleum Refinery 

Initiative 

State EPA Region Refinery 

CO 8 Conoco (Suncor Energy) Refinery (Denver) 

CO 8 Valero (Colorado Refining) Refinery (Denver) 

MT 8 Exxon Mobile (Billings) 

MT 8 Montana Refining (Great Falls) 

MT 8 Conoco Refinery (Billings) 

MT 8 Centex Harvest States (Laurel) 

ND 8 BP Amoco Mandan Refinery 

NM 6 Artesia Refinery 

NM 6 Lea Refinery 

UT 8 Chevron Salt Lake Refinery 

UT 8 BP Amoco Salt Lake City Refinery 

WA 10 Equilon-Puget Sound Refining (Anacortes) 

WA 10 ConocoPhillips (Ferndale) 

WA 10 BP Cherry Point Refinery (Blaine) 

3.3 Maximum Achievable Control Technology Standards 

An attempt was made to determine the criteria air pollutant (CAP) impacts from 

implementation of NESHAPs on visibility pollutants emitted by WRAP point and area sources. 

The maximum achievable control technology (MACT) impacts were assessed by collecting all 

readily available information on the emission impacts of the rules. Emissions information was 

gathered from rulemaking preambles and U.S. EPA Fact Sheets supporting each rule, and 
WRAP 2018 Base Case Inventory 

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emissions analyses were obtained for some rules by contacting contractor staff who worked on 

the rules. After compiling and analyzing these data, it was concluded that credible estimates of 

MACT impacts could not be developed based on readily available information and that 

substantial effort would be required to gather the necessary data. As a result, MACT emission 

reductions from WRAP sources were not estimated. 

The most significant challenges associated with assessing MACT impacts on WRAP 

emission sources included the following: 

• Determining CAP pollutant reductions due to NESHAP implementation (i.e., MACT) at 

the source level is a significant effort involving the determination of the current level of 

MACT compliance, followed by a unit level emissions and control analysis; 

• While MACT reductions in tons of pollutant are available from U.S. EPA rulemaking 

preambles, Federal Register notices, and Fact Sheets, these are generally done at a 

national level, using some broad assumptions (e.g., nationwide VOC reductions from a 

given MACT may be 45 percent, although the actual reduction at a given plant may be 0 

percent or 99 percent); and 

• Some VOC controls will cause increases in NOx and SO2 emissions (e.g., thermal 

oxidizers will increase NOx emissions and, if there is sulfur in the exhaust stream as in 

pulp mills, SO2 as well), so these impacts would need to be estimated along with 

reductions in VOC. 

A target list of applicable MACT standards was identified using two methods. First, the 

most significant emitting source categories (SCCs) for NOx, SO2, VOC, and PM10 in the 2002 

inventory were examined for applicable NESHAPs having an implementation of 2003 or later. 

This review showed that relatively few of the top-emitting categories were affected by new 

NESHAPs, either because there is not applicable rule (e.g., utility boilers), the rule will impose 

no emission control requirements (e.g., natural gas-fired industrial boilers), or the compliance 

date for the rule has already passed (e.g., oil and gas production). The NESHAPs determined to 

have the potentially greatest impact on high-emitting SCCs in the WRAP region were as follows: 

• Reciprocating internal combustion engines (RICE) 

• Petroleum bulk stations and terminals 

• Petroleum refineries (i.e., fluidized catalytic cracking units [FCCUs], sulfur plants) 

• Primary copper smelters 
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Secondly, a subjective determination was made as to the NESHAPs that were likely to 

have the largest impact on CAPs in the WRAP region based on the number of potentially 

affected sources. The NESHAPs determined to affect the greatest number of WRAP sources 

were as follows: 

• Industrial boilers and process heaters (coal-fired) 

• Miscellaneous organic NESHAP 

• Pulp and paper mills 

• Plywood and composition wood products 

• Gas turbines 

• Miscellaneous metal parts surface coating 

• Plastic parts surface coating 

Next, using the combined list of MACT standards from above, available information 

from federal rules and preambles related to national tonnage reductions and/or percentage 

reduction from MACT implementation was compiled. This presented a challenge because CAP 

information is not readily available in a useful form from these references. For most source 

categories, developing more precise information on specific pollutant emission reductions at 

individual sources or geographic regions would have required research into the rulemaking 

docket for each rule, which was beyond the scope of this effort. Still, some initial data analysis 

was performed by which the national tons/year reductions in CAPs were divided by national 

tons/year emissions from the 2002 NEI for the MACTs covering RICE, plywood and composite 

wood products, industrial/commercial/institutional boilers and process heaters, primary copper, 

and pulp and paper production. There was an extremely high level of uncertainty in the results, 

such as percentage reductions exceeding 100 percent (i.e., MACT tons per year [TPY] reductions 

exceeded the 2002 NEI TPY) and very insignificant percentage reductions (i.e., due to conditions 

such as of having MACT already implemented by certain source categories). Also, during the 

course of this project, other information was gathered pertaining to MACT standards being 

implemented on a local level. Due to these data limitations, it was decided not to apply MACT 

reductions to CAP emissions from WRAP sources. 
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3.4 Other Unquantified Regulatory Impacts 

During the data collection process with the state and tribal environmental agencies, 

several types of control programs were identified as having on-the-books controls that could 

affect emissions by the year 2018. These are listed as follows, along with the reasons that their 

impacts could not be quantified: 

• Natural Events Action Plans (NEAPs) in Alamosa and Lamar, Colorado. These plans 

both include several best available control measures (BACM) for fugitive dust control; 

however, no specific (i.e., SCC-level, annual emissions) were quantified in the SIP 

document. 

• Smelter Rule (R18-2-715) in Arizona. This rule sets hourly SO2 emission limits at 

ASARCO Hayden Mill (295 lbs/hour) and Phelps Dodge Miami smelter (604 lbs/hour); 

however, these limits could not be taken in the projections without a significant 

assumption of hours/year of operation. 

• Salt River (Arizona) PM10 SIP emission reductions from “one brick manufacturer.” The 

SIP does not contain enough detail (e.g., facility ID, applicable SCCs) to apply these onthe-books reductions. Also, the SIP indicates emission reductions of non-stack PM10

sources from all industrial facilities of 60%, although specific facilities and SCCs are not 

provided. 

• EGUs that have been identified as having potential post-2002 voluntary reductions (i.e., 

although no specific reductions were applied): 

⎯ Salt River Project (SRP) - Coronado Generating Station, AZ 

⎯ Arizona Electric Power Cooperative - Apache, AZ 

⎯ Nevada Power Company - Reid Gardner, NV 

⎯ Huntington Power Plant, UT 

⎯ Intermountain Generation Station, UT
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4.0 GROWTH FACTOR AND RATE ANALYSIS 

In addition to post-2002 control factors, the 2018 projections also account for the effects 

of future growth from 2002 to 2018. The methodologies used to estimate future growth varied 

depending upon specific source type. For instance, a specialized methodology was developed 

for coal-fired EGUs in order to incorporate detailed information regarding EGU operation, while 

a generalized approach was used for the majority of the other sources. The growth factor and 

rate analysis methodologies are described in detail below. 

4.1 Electricity Generating Units 

Because EGUs are the largest source of NOx and SO2 in the WRAP inventory domain, 

considerable effort was spent to develop projections for them. In particular, projections were 

developed on an EGU-by-EGU basis, rather than for the sector as a whole. 

The starting point of this effort was the revised 2002 WRAP point sources inventory; all 

EGU sources were then extracted from the overall inventory. Under a separate task of this 

project, NOx and SO2 emissions data had already been incorporated into the inventory for all 

EGUs that had continuous emissions monitors (CEMs) and reported to U.S. EPA’s Clean Air 

Markets Division (CAMD) database (identified as “CAMD EGUs”) (U.S. EPA, 2005a). The 

methodology was applied only to CAMD EGUs; EGUs not contained in the CAMD database 

were treated like other non-EGU point sources (see Section 4.2). Methodology details specific to 

coal-fired CAMD EGUs are presented in Section 4.1.1, while methodology details for all other 

CAMD EGUs are described in Section 4.1.2. 

4.1.1 Coal-Fired EGUs 

After the coal-fired EGUs were extracted from the overall inventory, new coal-fired 

EGUs that commenced operation after 2002 were added to the inventory (i.e., Wygen 1). 

Likewise, coal-fired EGUs that retired since 2002 were removed from the list of coal-fired EGU 

sources (i.e., Arapahoe Units 1 and 2). After the list of CAMD coal-fired EGUs was compiled, 

then the following data were downloaded from the CAMD website for each of the units3

: 

 

3

 http://cfpub.epa.gov/gdu 
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• Nameplate unit capacity (megawatts [MW]) 

• 2002 gross electricity generation (megawatt-hours [MWh]) 

• 2002 heat input (million British thermal units [MMBtu]) 

• 2002 NOx emissions (tpy) 

• 2002 SO2 emissions (tpy) 

• 2004 NOx emissions (tpy) 

• 2004 SO2 emissions (tpy) 

For each CAMD unit, a 2002 capacity factor (CF) was calculated using the following 

equation: 

CF = (gross generated electricity [MWh])/(nameplate unit capacity [MW] × 8760 hours) 

After calculating the 2002 capacity factor, a capacity threshold (CT) was used to 

calculate the appropriate growth factor (GF) for each coal-fired EGU. The GF value represents 

how much growth is needed to project from the current level of operation up to the CT value. 

The equation used is as follows: 

GF = CT/CF 

The capacity threshold represents the theoretical level of generation at which the utilities 

will need to begin construction of a new EGU to meet additional demand requirements. For 

coal-fired EGUs, a CT value of 0.85 was assumed based on input from the Projections Work 

Group. The use of this CT value was based upon historical precedent; the value was previously 

used many years ago in the WRAP Integrated Assessment System (IAS) and has been carried 

forward to the present time. 

For all pollutants except NOx and SO2, the 2002 emissions were then multiplied by the 

calculated GF value in order to determine the 2018 emissions using the following equation: 

Emissions2018 = Emissions2002 × GF 

An expanded methodology was utilized for NOx and SO2. The calculated GF was 

multiplied by the 2002 heat input (HI) to obtain a projected 2018 HI: 

HI2018 = HI2002 × GF 
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The most recent full-year (i.e., 2004) NOx and SO2 emission rates (ER) in pounds (lbs) 

per MMBtu were generated by dividing 2004 emissions by 2004 HI as follows: 

ERNOx = EmissionsNOx,2004/HI2004 

ERSO2 = EmissionsSO2,2004/HI2004

Based on the guidance of WRAP SSJF, the CAMD 2004 NOx and SO2 emission rates, 

which are the most current full year emission rates for coal-fired EGUs, were used to represent 

coal-fired EGU operation in 2018. Emissions were calculated as follows: 

EmissionsNOx,2018 = HI2018 × ERNOx

EmissionsSO2,2018 = HI2018 × ERSO2 

As a final step, projected emissions were reduced by any relevant emission caps or permit 

limits. The specific emission caps or permit limits are discussed in Section 3.0 and apply to the 

following facilities: 

• Tucson Electric Power (TEP) – Springerville, AZ 

• Xcel Energy – Comanche, CO 

• Xcel Energy – Arapahoe, CO 

• Xcel Energy – Cherokee, CO 

• Xcel Energy – Valmont, CO 

• Tri-State Generation – Craig, CO 

• Arizona Public Service Co. – San Juan, NM 

• Southern California Edison (SCE) – Mohave, NV 

4.1.2 Other EGUs 

The methodology used to project other EGUs was similar to that used for the coal-fired 

EGUs. As with the coal-fired EGUs, the other EGUs were extracted from the overall inventory 

with adjustments made for post-2002 new EGUs and retired EGUs. After the list of CAMD 

EGUs was compiled, then the following data were downloaded from the CAMD website for 

each of the units: 
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• Nameplate unit capacity (MW) 

• 2002 gross electricity generation (MWh) 

• 2002 NOx emissions (tpy) 

• 2002 SO2 emissions (tpy) 

The 2002 capacity factor (CF) was calculated using the following equation: 

CF = (gross generated electricity [MWh])/(nameplate unit capacity [MW] × 8760 hours) 

After calculating the 2002 capacity factor, a capacity threshold (CT) was used to 

calculate the appropriate growth factor (GF) for each other EGU. The GF value represents how 

much growth is needed to project from the current level of operation up to the CT value. The 

equation used is as follows: 

GF = CT/CF 

Different CT values were used for the other non-coal fired EGUs depending upon the fuel 

and technology present. These CT values used were 0.50 for oil-/diesel-fired EGUs, 0.25 for 

simple cycle natural gas-fired turbines, and 0.60 for natural gas-fired combined cycle EGUs. 

For all pollutants, the 2002 emissions were then multiplied by the calculated GF value in 

order to determine the 2018 emissions using the following equation: 

Emissions2018 = Emissions2002 × GF 

4.1.3 Future EGUs 

Another unique aspect of the growth analysis for EGUs as compared to other point 

sources is the identification of future EGUs that will need to be built in order to meet projected 

electricity demand in 2018. The basis of the projected electricity demand is the Energy 

Information Administration’s (EIA) annual energy projections out to the year 2025 (EIA, 2005). 

Historical statistics for 2002 and projections for 2018 were obtained from the EIA 

documentation for 4 of the 13 electricity market module regions: 

• Northwest Power Pool (Idaho, Oregon, Utah, Washington, Wyoming; and parts of 

California, Montana, Nevada, and South Dakota); 
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• Rocky Mountain Power Area, Arizona, New Mexico, and Southern Nevada (Arizona and 

Colorado; and parts of Nevada, New Mexico, and Texas); 

• Mid-Continent Area Power Pool (North Dakota, Nebraska; and parts of Montana, South 

Dakota, Minnesota, Iowa, and Wisconsin); and 

• California (parts of California). 

The analysis of future electricity generation for coal and natural gas is summarized in 

Table 4-1 and Table 4-2. These generation values do not necessarily correspond to physical 

locations; rather, they indicate the assignment of EGUs to electricity market module regions. 

Table 4-1. Future Electricity Generation Analysis – Coal-Fired EGUs 

Growth Parameter 

Western States (including CA)

(billion kWh) 

North Dakota/ 

South Dakota 

(billion kWh) 

2002 Electricity Generation 223.59 35.11 

2018 Electricity Generation 328.31 45.60a

Needed Generation 104.72 10.49 

Unused Capacity at Existing 2002 Facilities 16.11 0.49 

New Capacity at 2003-2004 Facilities 0.66 0.00 

Capacity Currently Under Construction 9.61 0.00 

Capacity Currently Being Permitted 21.82 0.00 

Remaining Capacity to be Allocated 56.54 10.00 

a

 Disaggregated from the Mid-Continent Area Power Pool based upon existing generation. 

Table 4-2. Future Electricity Generation Analysis – Natural Gas-Fired EGUs 

Growth Parameter 

Western States 

(excluding CA) 

(billion kWh) 

CA 

(billion kWh) 

North Dakota/ 

South Dakota 

(billion kWh) 

2002 Electricity Generation 55.57 93.41 0.14 

2018 Electricity Generation 143.81 153.69 0.39a

Needed Generation 88.24 60.28 0.25 

Unused Capacity at Existing 2002 

Facilities 

25.66 2.80 0.54 

New Capacity at 2003-2004 

Facilities 

40.61 19.39 0.00 

Capacity Currently Under 

Construction 

12.39 31.44 0.00 

Capacity Currently Being Permitted 15.98 38.20 0.00 

Remaining Capacity to be Allocated -6.40 -31.55 -0.29 

a

Disaggregated from the Mid-Continent Area Power Pool based upon existing generation.
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Coal 

As shown in Table 4-1, 115.21 billion kWh of coal-fired electricity generation is 

projected by EIA for the West in 2018. North Dakota and South Dakota generation is separated 

out from the rest of the Western states because those two states are on a different power grid and 

considerable amounts of lignite coal are used. Based upon the growth analysis methodology 

described in Section 4.1.1, 16.60 billion kWh of this needed generation can be obtained from 

unused capacity (i.e., capacity between existing 2002 generation and the 0.85 capacity factor). 

An additional 32.09 billion kWh of coal-fired generation has been identified from facilities that 

either came on-line in 2003 or 2004, are currently under construction, or are currently being 

permitted. All of these facilities were added to the 2018 inventory, and are listed in Table 4-3. 

Table 4-3. Coal-Fired EGUs that are New (2003 or 2004), Under Construction, 

or Being Permitted 

Facility Name Current Status State

County 

(FIPS) 

Nameplate Capacity 

(MW) 

Wygen Station #1 New in 

2003/2004 

WY (005) 88 

Rocky Mountain Power/Hardin 

Generating Station 

Under 

Construction 

MT (003) 160 

Bull Mountain Plant/Roundup Plant Under 

Construction 

MT (065) 750 

Wygen Station #2/Black Hills Corp Under 

Construction 

WY (005) 100 

Two Elk/Bechtel Under 

Construction 

WY (005) 280 

Springerville #3 and #4 Being Permitted AZ (001) 760 (combined) 

Comanche #3 Being Permitted CO (101) 750 

Northern Nevada Energy/Newmont Being Permitted NV (011) 200 

NEVCO Energy Company Being Permitted UT (041) 270 

Intermountain Power Plant #3 Being Permitted UT (027) 950 

 

After considering the facilities listed in Table 4-3, 66.54 billion kWh (i.e., 10.00 billion 

kWh in North Dakota and South Dakota and 56.54 billion kWh in the remaining WRAP states) 

of coal-fired electricity generation still remained. Based upon input from the Projections Work 

Group, it was assumed that a typical future coal-fired EGU has a nameplate capacity of 500 MW 

and operates up to the capacity threshold of 0.85. It was then estimated that a total of 18 typical 

future coal-fired EGUs will need to be built prior to 2018, of which 3 will need to be located in 

North Dakota or South Dakota. The allocation of these future coal-fired EGUs was based upon 
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current state-level capacity (i.e., sum of existing, under construction, and permitted). This 

allocation is shown in Table 4-4; it should be noted that the allocation for North Dakota and 

South Dakota was conducted separately from the other WRAP states. It should also be noted 

that in addition to Oregon, Washington, and South Dakota, no future coal-fired EGUs are 

expected to be built in California. 

Table 4-4. Allocation of Future Coal EGUs 

State 

2002 

Existing 

(MW) 

2004 

New 

(MW) 

Under 

Construction 

(MW) 

Permitted 

(MW) 

Total 

(MW) Fraction 

No. of 

Plants 

Modified 

No. of 

Plants 

AZ 3,341 0 0 760 4,101 0.109 1.65 2

a

CO 5,075 0 0 750 5,825 0.155 2.35 2

a

ID 0 0 0 0 0 0.000 0.00 1

b

MT 2,567 0 910 0 3,477 0.092 1.40 1

a

NM 2,105 0 0 0 2,105 0.056 0.85 1

a

NV 2,769 0 0 200 2,969 0.079 1.20 1

a

OR 601 0 0 0 601 0.016 0.24 0

c

UT 4,745 0 0 1,220 5,965 0.158 2.41 2

a

WA 1,460 0 0 0 1,460 0.039 0.59 0

c

WY 5,995 88 380 0 6,463 0.172 2.61 3

a

Tribes 

(Navajo) 

4,678 0 0 0 4,678 0.124 1.89 2

a

ND 4,185 0 0 0 4,185 0.902 2.42 3

d

SD 456 0 0 0 456 0.098 0.26 0

c

Western 

(excluding 

ND/SD) 

33,336 88 1,290 2,930 37,644 15.19 15

ND/SD 4,641 0 0 0 4,641 2.69 3

a Number of units rounded. 

b Number of units set to 1 based upon input from state air agency. 

c Number of units set to 0 to reflect the unlikely siting of coal-fired EGU. 

d Number of units rounded up. 

After allocation of the future coal-fired EGUs at the state-level, the EGUs were then 

allocated to specific counties. The basis of this allocation was based upon two factors: 

• Announcements of plans to build coal-fired EGUs. 

• Locations of existing coal-fired EGUs and associated infrastructure. 
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The two future coal-fired EGUs allocated to Navajo Nation were split between the 

Arizona and New Mexico portion of that NAR. The county location of the 18 future coal-fired 

EGUs is presented in Table 4-5. 

Table 4-5. County-Level Allocation of Future Coal-Fired EGUs 

Assigned EGU Name State (County FIPS) 

Arizona A AZ (001) 

Arizona B AZ (003) 

Colorado A CO (099) 

Colorado B CO (087) 

Idaho A ID (053) 

Montana A MT (013) 

New Mexico A NM (031) 

Nevada A NV (033) 

Utah A UT (015) 

Utah B UT (047) 

Wyoming A WY (005) 

Wyoming B WY (037) 

Wyoming C WY (009) 

Navajo Nation A AZ 

Navajo Nation B NM 

North Dakota A ND (055) 

North Dakota B ND (057) 

North Dakota C ND (065) 

 

The emission rates used to develop emission estimates for these future new coal-fired 

EGUs, as well as those currently under construction or being permitted, are presented in Table 4-6. 

Natural Gas 

As shown in Table 4-2, a total of 148.77 billion kWh of natural gas-fired electricity 

generation is required by 2018. Based upon the growth analysis methodology described in 

Section 4.1.2, 29.00 billion kWh of this generation can be obtained from unused capacity. An 

additional 158.01 billion kWh of natural-gas fired generation has been identified from facilities 

that either came on-line in 2003 or 2004, are currently under construction, or are currently being 

permitted. All of these facilities were added to the 2018 inventory. Because the identified 

generation exceeded the projected 2018 needed generation, no additional future natural gas-fired 

EGUs are expected to be needed in the WRAP Region. The emission rates used to develop 

emission estimates for natural gas-fired EGUs that are currently under construction or being 

permitted are presented in Table 4-7. 
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Table 4-6. Emission Rates for Future New Coal-Fired EGUs 

Pollutant lb/ton lb/MMBtua lb/MWhb Source 

NOx n/a 0.0900 0.9000 BACTc

SO2 n/a 0.0900 0.9000 BACTd

VOC 0.06 0.0022 0.0222 AP-42, Table 1.1-19 (U.S. EPA, 1995)

CO n/a 0.1500 1.5000 BACTe

PM10-PRI n/a 0.0180 0.1800 BACTf

PM2.5-PRI n/a 0.0047 0.0470 AP-42, Table 1.1-6 (U.S. EPA, 1995) 

a Converted from lb/ton to lb/MMBtu using conversion factor of 13,500 Btu/lb coal. 

b Converted from lb/MMBtu to lb/MWh using conversion factor of 10,000 Btu/kWh. c Obtained from range of values (0.06 to 0.1) from 12 Western facilities (U.S. EPA, 2005b); value selected with input from 

Projections Work Group. 

d Obtained from range of values (0.038 to 0.11) from 12 Western facilities (U.S. EPA, 2005b); value selected with input from 

Projections Work Group. 

e Obtained from range of values (0.012 to 0.52) from 12 Western facilities (U.S. EPA, 2005b); value selected with input from 

Projections Work Group. 

f Obtained from range of values (0.1 to 0.16) from 12 Western facilities (U.S. EPA, 2005b); value selected with input from 

Projections Work Group. 

Table 4-7. Emission Rates for Future New Natural Gas-Fired EGUs 

Pollutant lb/MMscf lb/MMBtua lb/MWhb Source 

NOx n/a 0.0900 0.6750 BACTc

SO2 0.60 0.0006 0.0043 AP-42, Table 1.4-2 (U.S. EPA, 1995) 

VOC 5.50 0.0052 0.0393 AP-42, Table 1.4-2 (U.S. EPA, 1995) 

CO 84.00 0.0800 0.6000 AP-42, Table 1.4-1 (U.S. EPA, 1995) 

PM10-PRI 7.60 0.0072 0.0543 AP-42, Table 1.4-2 (U.S. EPA, 1995) 

PM2.5-PRI 7.60 0.0072 0.0543 AP-42, Table 1.4-2 (U.S. EPA, 1995) 

a Converted from lb/MMscf to lb/MMBtu using conversion factor of 1,050 Btu/scf natural gas. 

b Converted from lb/MMBtu to lb/MWh using conversion factor of 7,500 Btu/kWh. c Value assumed to be the same as coal.

4.2 Other Point Sources 

For all other non-EGU point sources, growth factors were obtained from one of two 

sources: the EGAS growth factor model or the oil and gas emission task (1B). 

4.2.1 EGAS Growth Factor Model 

The U.S. EPA’s Economic Growth and Analysis System growth factor model (EGAS), 

Version 5.0 generates SCC-specific growth factors for a specified geographic area, base year 

(i.e., 2002), and future year (i.e., 2018) using various socio-economic data (U.S. EPA, 2004; Abt, 
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2004). At the present time, the EGAS model run with default data can only generate growth 

factors at the state-level. County-level growth factors can be generated by EGAS if detailed 

county-level socio-economic data are input into the model; however, this was not done for this 

analysis because these data were not available. Also, although some local demographic data 

were made available for the projections (i.e., Maricopa County in Arizona, a number of counties 

in Colorado, and all counties in Utah), EGAS Version 5.0 does not currently allow these data to 

be input and run without errors. As a result, default modeling was conducted without these 

demographic data. 

Default model runs were made for every state within the inventory with the exception of 

California; California growth factors are discussed in Section 4.4. Growth factors from the 

default model runs were matched using SCCs to each inventory record. In the event that an 

inventory record SCC did not match any of the SCCs in the EGAS output, a growth factor of 

1.0000 was assigned. In most cases, unmatched SCCs were caused by the input of incorrect 

SCCs in the inventory record. 

4.2.2 Oil and Gas Growth Factors 

As part of Task 1B under the overall WRAP SSJF project, county-specific growth factors 

for oil and gas production area sources (ENVIRON, 2005). These growth factors were also 

applied to the point source inventory by mapping the oil and gas area source categories to the 

corresponding point source SCCs. The oil and gas point sources were limited to the following 

point source SCCs: 

• 310xxxxx 

• 404003xx 

• 202002xx, 203002xx, or 306xxxxx under SICs 1300, 1311, 1321, 1382, 1389, 4612, 

4922, 4923, or 4925 

If an SCC/county-specific growth factor did not exist for a particular inventory record, 

then regional growth factors obtained from EIA forecasts were applied (EIA, 2005). These 

regional growth factors are presented in Table 4-8. 
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Table 4-8. Regional 2002 to 2018 Oil and Gas Growth Factors 

Region Oil Production Gas Production 

Rocky Mountain (AZ, CO, ID, MT, ND, NV, SD, UT, 

WY and western half of NM) 

1.334 1.458 

Southwest (eastern half of NM and western TX) 0.866 1.354 

West Coast (CA, OR, and WA) 0.601 0.568 

Alaska 0.876 4.395 

4.3 Area Sources 

For area sources, growth factors were obtained from one of three sources: the EGAS 

growth factor model, energy projections from EIA, or agricultural crop projections from the U.S. 

Department of Agriculture (USDA). The EGAS area source projection factors were obtained in 

the same manner as the EGAS point source projection factors (see Section 4.2.1). The other two 

growth factor sources are explained below. 

4.3.1 EIA Energy Projections 

As discussed in Section 4.1.3, the EIA has issued annual energy projections out to the 

year 2025 (EIA, 2005). Historical statistics from 2002 combined with projected use quantities 

for 2018 were used to derive projection factors for use with area source fuel combustion sources. 

These EIA-based projection factors were used for the following source categories: 

• Industrial fuel combustion (SCC 2102xxxxxx) 

• Commercial/institutional fuel combustion (SCC 2103xxxxxx) 

• Residential fuel combustion (SCC 2104xxxxxx) 

4.3.2 USDA Agricultural Projections 

Growth factors for agricultural tilling (SCC 2801000003) were obtained from harvested 

acreage projections developed by USDA (USDA, 2005). The USDA projections covered a 12-

year period from 2003 to 2014 and included harvested acreage estimates for eight major field 

crops (i.e., wheat, barley, corn, rice, oats, soybeans, sorghum, and upland cotton). Extrapolation 

was used to extend the time series back to 2002 and forward to 2018. The 2002 harvested 

acreage was estimated to be 226.9 millions acres; while the 2018 harvested acreage was 

estimated to be 235.1 millions acres. This corresponds to a growth factor of 1.0361. 
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4.4 California Point and Area Sources 

The California 2018 base case emissions were developed using an entirely different 

methodology than has been described in this report for the other WRAP states. The California 

Air Resources Board (ARB) used the California Emission Forecasting System (CEFS) to 

develop California’s 2018 base case inventory and provided it directly to the WRAP (Johnson 

and Lakhanpal, 1997). The California 2018 base case inventory was provided in the CEFS 

output format shown in Table 4-9. 

Table 4-9. CEFS Modeling File Format 

Field Length Field Name Definition 

2 CO County 

3 AB Air Basin 

9 FACID Facility ID 

6 DEV Device ID 

14 PROID CEIDARS Process ID 

4 FYEAR Forecast Year 

16 SCENARIO Forecast Scenario 

4 SUBCO Sub-County (Not Used) 

14 SCC 8-digit SCC for Point Sources, 14-digit EIC for Area Source 

14 SIC 4-digit SIC for Point Sources, 14-digit EIC for Area Sources 

8 SPATIAL Spatial Surrogate Name (for Area Sources) 

12 AAEMS Annual Average Emissions 

12 SEMS Summer Average Emissions 

12 WEMS Winter Average Emissions 

5 POL Pollutant Code 

2 EMSUNIT Emissions Units (Tons per Day) 

2 UZ UTM Zonea

6 UE UTM Eastern Coordinatea

7 UN UTM Northern Coordinatea

30 FACNAME Facility Name 

30 FACSTREET Facility Street Location 

20 CITY City 

5 ZIP Zip Code 

CEIDARS = California Emission Inventory Development and Reporting System 

EIC = Emission inventory code (unique to California) 

a

Although UTM coordinates are a CEFS field, these were not provided to the WRAP. 

CEFS uses two separate forecast algorithms: TREND forecast module for aggregating 

emissions by air district, air basin, and county, and GIS forecast module for developing forecasts 

at the facility/device/process level for use in gridded inventory inputs for modeling. 
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TREND module was used to develop the 2018 base case inventory for the WRAP. Within this 

module, the following factors were applied: 

• Temporal factors, or season adjustment factors, for apportioning emissions into “average 

annual operating day.” 

• Growth factors from county-specific economic activity profiles, population forecasts, and 

other socio/demographic activity. Many of the CEFS growth factors were updated in 

2001 for the entire state (Pechan, 2001). Also, two air districts, South Coast Air Quality 

Management District (SCAQMD) and Bay Area Air Quality Management District 

(BAAQMD) provided their own growth factors to CEFS. Growth factors are region (i.e., 

air district/air basin/ county) specific. The growth factors used in CEFS for developing 

WRAP’s 2018 base case inventory for California are provided in a spreadsheet 

accompanying this report. 

• Control Factors, provided entirely by the air districts in California, to quantify the 

impacts of on-the-books controls from ARB regulations, district rules. Control factors 

comprise three components: control efficiency, rule effectiveness, and rule penetration. 

The control factors are region, control measure, source category, and pollutant dependent. 

The control factors used in CEFS for developing the WRAP 2018 base case inventory for 

California are provided in a spreadsheet accompanying this report. 

CEFS 2018 database files for point sources (i.e., 128,425 records; 20,914 facilities) and 

area sources (i.e., 16,340 records; 618 SCCs across all counties) were provided in the format 

shown in Table 4-9, in units of tons per day. The pollutants were NOx, SO2, reactive organic 

gases (ROG), CO, PM10, and PM2.5. ROG was taken to be equivalent to VOC; no NH3

emissions were provided. 

The following steps were then performed to place the CEFS emissions into the proper 

format, eliminate inconsistencies with the remaining WRAP inventory, and fill data gaps for 

required NIF and IDA fields: 

• Point Sources: 

⎯ SCCs were checked for validity; invalid SCCs were removed. 

⎯ Tons per day were converted to tons per year by multiplying by 365. 

⎯ PM10 and PM2.5 records were adjusted according to the U.S. EPA correction 

factors for natural gas combustion (see Section 2.2). 

⎯ Latitude/longitude coordinates were assigned to the 2018 records using 

information from California’s 2002 inventory (compiled under Task 1A of this 
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project). County centroids were assigned to 2018 sources that could not be 

matched to 2002 records. 

⎯ Area Sources: 

− Certain EICs were removed, as these are not included in this particular 

inventory effort (i.e., wildfires, prescribed burning, forest fires, rangeland 

burning, agricultural burning, and windblown dust). 

− Remaining EICs were mapped to SCCs. 

− Tons per day were converted to tons per year by multiplying by 365. 

After these steps were completed, then the California files were converted to NIF3.0 and 

IDA formats for use in subsequent steps of the 2018 base case inventory process.
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5.0 POINT SOURCE RETIREMENT AND 

REPLACEMENT 

In addition to controls and growth, the 2018 projected inventory also includes the effects 

of point source retirement and replacement. The assumptions used to apply the concepts of point 

source retirement and replacement were handled as follows: 

• All point sources have a finite lifetime (of ‘x’ number of years); 

• Upon reaching that finite lifetime, a point source will be retired; 

• A retired point source will be replaced by a point source of similar size; 

• The new replacement point source will have lower controlled emissions than the 

emissions from the retired point source; and 

• Point source retirement/replacement is entirely separate from future growth. 

Because future year emission rates could not be quantified for some source types, point 

source retirement/replacement was only applied to a limited number of source types (i.e., SCCs). 

The general methodology is outlined below, along with specific modifications that were made 

for the special case of EGUs. 

5.1 SCC Identification 

Retirement and replacement was applied for a subset of the point sources contained in the 

2002 WRAP inventory. A list of the point sources and SCCs is provided in Table 5-1 along with 

expected facility lifetime, annual retirement rate, and projection retirement rate. The annual 

retirement rate is the percentage of sources under a particular SCC that are expected to retire in a 

given year; the annual retirement rate is defined as (1/lifetime). For example, an SCC with an 

expected lifetime of 50 years has an annual retirement rate of 0.02 (i.e., 1/50 years). The 

projection retirement rate is the percentage of sources under a particular SCC that are expected to 

retire over the period of the projection (i.e., from 2002 to 2018, or 16 years). In the case of the 

SCC example above, the projection retirement rate is 0.32 (i.e., 0.02 × 16 years). 
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Table 5-1 Retirement and Replacement SCCs, Lifetimes, and Retirement Rates 

Category Applicable SCCs 

Lifetime 

(years)a Annual 

Retirement Rate 

Projection 

Retirement Rate 

Utility Oil Boiler 101004xx, 101005xx, 

10102101, 10101302 

60 0.0167 0.2667

Utility Natural Gas 

Boilers 

101006xx 60 0.0167 0.2667

Utility Renewable 

Boilers 

10101501, 10101502, 

10101801 

60 0.0167 0.2667

Utility Oil Turbine 20100101, 20100108, 

20100109, 20101302 

30 0.0333 0.5333

Utility Natural Gas 

Turbine 

20100201, 20100208, 

20100209 

30 0.0333 0.5333

Utility Cogeneration 10200219, 10200229, 

10200307, 10200405, 

10200505, 10200604, 

10200710 

45 0.0222 0.3556

Industrial Coal Boilers 102001xx, 102002xx, 

102003xx, 10500102 

45 0.0222 0.3556

Industrial Oil Boilers 102004xx, 102005xx, 

10201302, 10500105, 

10500113, 10500114 

45 0.0222 0.3556

Industrial Natural Gas 

Boilers 

102006xx, 10500106 30 0.0333 0.5333

Industrial Wood 

Boilers 

102009xx 45 0.0222 0.3556

Industrial Oil Turbines 20200101, 20200103, 

20200108, 20200109 

30 0.0333 0.5333

Industrial Natural Gas 

Turbines 

20200201, 20200203, 

20200208, 20200209 

30 0.0333 0.5333

Industrial IC Engines All other 202002xx 30 0.0333 0.5333

Oil and Gas 

Production 

310002xx 30 0.0333 0.5333

Cement Kilns 305006xx 32.5 0.0308 0.4923

Petroleum Refining 30600105, 30600201, 

30600202 

30 0.0333 0.5333

a

 Source: Pechan, 2001. 
WRAP 2018 Base Case Inventory 

Version 1, January 2006

5-3

For each of the SCCs listed in Table 5-1, reduction factors were developed for NOx, SO2, 

and PM10. These factors were based on the expected reduction as an uncontrolled source is 

retired and replaced by a new controlled source. Reduction factors are presented in Table 5-2; a 

blank cell indicates that a reduction factor either could not be found or could not be quantified. 

The information used to develop the reduction factors is provided in Table 5-3. Reduction 

factors were calculated using the following equation: 

Reduction Factor = (Retired Rate – Replacement Rate)/(Retired Rate) 

As an example, the reduction factor for PM10 from industrial coal boilers was calculated as 

follows: 

Reduction Factor = (0.051 lb/MMBtu – 0.03 lb/MMBtu)/0.051 lb/MMBtu = 0.412 

The effects of retirement and replacement were applied as a sector-wide adjustment to 

each record in that sector based on SCC. In addition, if a particular SCC had reduction factors 

applied to it, then the reduction factors were also applied to new growth as well. This is shown 

in the following equations where R is equal to the retirement rate, G is the growth rate, and C is 

the reduction rate for a particular pollutant: 

Total 2018 Emissions = Unretired 2002 Emissions + Retired/Replaced 2002 Emissions 

+ Grown 2018 Emissions 

Total 2018 Emissions = (2002 Emissions × [1 – R]) + (2002 Emissions × R × [1 – C]) 

+ (2002 Emissions × [G – 1] × [1 – C]) 

5.2 Modifications to Methodology for EGUs 

The retirement/replacement methodology described above was applied to all point 

sources that matched the SCCs in Table 5-1. The one key exception was for EGUs. Instead of 

applying annual retirement rates to EGUs, the age of the EGU based upon known start-up dates 

was compared to expected lifetimes as shown in Table 5-1 (U.S. EPA, 2005a). If the age of any 

EGU exceeded its expected lifetime in 2018, then that EGU was assumed to be replaced by a 

similarly-sized EGU grown up to capacity (as described in Section 4.1) with the appropriate 

reduced emission rates. If the start-up date of an EGU was not known, then the methodology 

presented in Section 5.1 was used instead. 
WRAP 2018 Base Case Inventory 

Version 1, January 2006

5-4

Table 5-2. Retirement and Replacement Reduction Factors 

Category Applicable SCCs NOx SO2 PM10

Utility Oil Boiler 101004xx, 101005xx, 

10102101, 10101302 

0.633 0.500

Utility Natural Gas 

Boilers 

101006xx 0.640 0.500

Utility Renewable 

Boilers 

10101501, 10101502, 

10101801 

0.267 0.500

Utility Oil Turbine 20100101, 20100108, 

20100109, 20101302 

0.267 0.500

Utility Natural Gas 

Turbine 

20100201, 20100208, 

20100209 

0.720 0.500

10200219, 10200229, 

10200307 

0.756 0.500

10200405, 10200505 0.633 

Utility Cogeneration 

10200604, 10200710 0.640 

Industrial Coal Boilers 102001xx, 102002xx, 

102003xx, 10500102 

0.500 0.900 0.412

Industrial Oil Boilers 102004xx, 102005xx, 

10201302, 10500105, 

10500113, 10500114 

0.500 0.900 0.700

Industrial Natural Gas 

Boilers 

102006xx, 10500106 0.500 0.900 

Industrial Wood 

Boilers 

102009xx 0.500 0.700

Industrial Oil Turbines 20200101, 20200103, 

20200108, 20200109 

0.500 0.900 

Industrial Natural Gas 

Turbines 

20200201, 20200203, 

20200208, 20200209 

0.500 

Industrial IC Engines All other 202002xx 0.900 

Oil and Gas 

Production 

310002xx 0.900 

Cement Kilns 305006xx 0.300 

Petroleum Refining 30600105 0.500 

30600201, 30600202 0.600 0.850 
WRAP 2018 Base Case Inventory 

Version 1, January 2006

5-5

Table 5-3. Information Used to Develop Retirement and Replacement Reduction Factors 

(lb/MMBtu) 

NOx SO2 PM10

Category Applicable SCCs 

(Retired 

Rate) 

(Replace 

Rate) 

(Retired 

Rate) 

(Replace 

Rate) 

(Retired 

Limit) 

(Replace 

Rate) 

Utility Oil Boiler 101004xx, 101005xx, 

10102101, 10101302 

0.3a

 0.11b 0.03e

 0.015b

Utility Natural Gas 

Boilers 

101006xx 0.25a

 0.09b,c 0.03e

 0.015b

Utility Renewable 

Boilers 

10101501, 10101502, 

10101801 

0.15a

 0.11b 0.03e

 0.015b

Utility Oil Turbine 20100101, 20100108, 

20100109, 20101302 

0.15a

 0.11b 0.03e

 0.015b

Utility Natural Gas 

Turbine 

20100201, 20100208, 

20100209 

0.32a

 0.11b 0.03e

 0.015b

10200219, 10200229, 

10200307 

0.45a

 0.11b 0.03e

 0.015b

10200405, 10200505 0.3a

 0.11b 0.03e

 0.015b

Utility Cogeneration 

10200604, 10200710 0.25a

 0.09b,c 0.03e

 0.015b

Industrial Coal 

Boilers 

102001xx, 102002xx, 

102003xx, 10500102 

0.2b,e f

 0.051g 0.03b

Industrial Oil Boilers 102004xx, 102005xx, 

10201302, 10500105, 

10500113, 10500114 

0.2b,e f 0.1g

 0.03b

Industrial Natural Gas 

Boilers 

102006xx, 10500106 0.2b,e f

Industrial Wood 

Boilers 

102009xx 0.2b,e 0.1g

 0.03b

Industrial Oil 

Turbines 

20200101, 20200103, 

20200108, 20200109 

0.2b,e f

Industrial Natural Gas 

Turbines 

20200201, 20200203, 

20200208, 20200209 

0.2b,e 

Industrial IC Engines All other 202002xx h 

Oil and Gas 

Production 

310002xx h 

Cement Kilns 305006xx i 

30600105 0.2b,e Petroleum Refining 

30600201, 30600202 j j

a

Retired NSPS values (1979-1997) obtained from 40 CFR 60.44a. 

b

Proposed future NSPS values obtained from 70 FR 9706-9735. 

c

Adjusted from 0.11 lb/MMBtu down to 0.09 lb/MMBtu to reflect more realistically achievable rates. 

d

Retired NSPS values (1979-2005) obtained from 40 CFR 60.42a. 

e

Limit based on selective catalytic reduction (SCR) and estimated to represent 50 percent reduction from 

combustion-controlled units (40 CFR 60.44b). 

f

Assumed 90 percent reduction of uncontrolled sources based on 40 CFR 60.42b and 70 FR 9706-9735. 

g

Retired NSPS values (1986-2005) obtained from 40 CFR 60.43b. 

h

Reduction based on BACT non-selective catalytic reduction (NSCR). 

i

Reduction based on ERG work for U.S. EPA on cement kiln BACT analysis. 

j

Reductions based on ERG work for U.S. EPA on National Petroleum Refinery Initiative. 
WRAP 2018 Base Case Inventory 

Version 1, January 2006

5-6

Further input from the WRAP SSJF Projections Work Group and other stakeholders 

indicated that the retirement/replacement methodology used for other point sources was not 

appropriate for coal-fired EGUs (i.e., no coal-fired EGUs in the WRAP region are expected to 

retire by 2018). Therefore, no retirement/replacement effects were applied to the coal-fired 

EGUs in the inventory.
WRAP 2018 Base Case Inventory 

Version 1, January 2006 

6-1

6.0 OTHER INFORMATION USED TO DEVELOP THE 

2018 BASE CASE PROJECTIONS 

After application of the various adjustments and factors discussed in above, an 

intermediate inventory value (i.e., “Initial 2018 Base Case”) was calculated. This intermediate 

inventory value was used to evaluate and indicate other information, which is discussed below. 

6.1 Permit Limits 

During review the draft 2018 base case, relevant state and tribal agencies and 

stakeholders were asked to compare permit limits for their point sources and equipment, to 

ensure that the projection method did not inadvertently cause the result predicted for 2018 to 

exceed any permit limit. In some cases, this was found to occur; the agency provided the permit 

limit(s) and the 2018 base case was adjusted in the “Permit Limit” column of the calculation 

spreadsheets for each relevant state. 

6.2 Section 309 Flags 

The WRAP SSJF requested that the 2018 base case projections data files to include a flag 

to indicate the sources subject to Section 309 requirements of the Regional Haze Rule. These 

include point sources located in the nine GCVTC states (AZ, CA, CO, ID, NV, NM, OR, UT, 

and WY) and having SO2 emissions of 100 tons/year or more. To indicate Section 309 

eligibility, a “Y” flag was placed in the Section 309 flag column of the calculation spreadsheets 

for each relevant state and source, based on 2002 facility-level emissions. Table 6-1 lists these 

facilities. One facility with SO2 emissions of 97 tons/year was also included in Table 6-1 

because it was listed in the 2003 SO2 Milestone report (WRAP, 2005) and its projected 2018 

emissions exceed 100 tons/year. 

Also, Table 6-2 was developed for the purpose of comparing the sources subject to 

Section 309 (as shown in Table 6-1) to the sources identified in Appendix A-1 of the 2003 SO2

Milestone report. All of the facilities listed in Table 6-2 were not flagged as Section 309 eligible 

(in Table 6-1) because their 2002 SO2 emissions were less than 100 tons, including those that 

came on-line after 2002 or were not in the 2002 inventory at all.
WRAP 2018 Base Case Inventory 6-2 

Version 1, January 2006 Table 6-1. WRAP Facilities Subject to RHR Section 309 Requirements, Based on 2002 

Tribe or State County FIPS Tribal or State Facility/ 2002 EI Identifier Plant SIC Facility Name 

Arapahoe Tribe of the Wind River Reservation 0 V-WR-0003-00.02 Peak Sulfur Inc (WY) Navajo Nation 0 NN-OP 99-03 1321 

ChevronTexaco, Aneth Natural Gas Processing Plant (UT) 

Navajo Nation 0 EGU0037 4911 Navajo Generating Station (AZ) Navajo Nation 0 EGU0793 4911 Four Corners Power Plant (NM) AZ 04001 EGU0034 4911 SRP Coronado Generating Station AZ 04001 EGU0035 4911 TEP – Springerville AZ 04003 EGU0036 4911 AEPCO - Apache Generating Station AZ 04007 0400701391 Phelps Dodge – Miami AZ 04007 040072435 3331 Ray Complex - Smelter and Mill AZ 04017 040171807 4911 Snowflake Pulp Mill AZ 04017 EGU0045 4911 Cholla Power Plant AZ 04019 0425 4931 Tucson Electric Power AZ 04019 EGU0047 4911 TEP - Irvington AZ 04025 040252393 3241 Phoenix Cement AZ 04025 040255992 3274 Nelson Lime Plant CA 06001 1130383 3321 United States Pipe & Foundry C CA 06001 1130311362 3221 Owens Brockway Glass Container CA 06013 7130323 2819 General Chemical Corporation CA 06013 7130311661 2819 Rhodia Inc CA 06013 7130316 2911 Conocophillips - San Francisco CA 06013 7130311 2911 Shell Martinez Refinery CA 06013 7130322 2999 Tosco Refining Company CA 06013 7130310 2911 Chevron Products Company CA 06013 7130314628 2911 Tesoro Refining And Marketing CA 06019 101430311 1311 Chevron Usa Inc CA 06019 101430598 3211 Guardian Industries Corp CA 06029 15143037 2911 Kern Oil & Refining Company CA 06029 1514301141 1311 Chevron Usa Inc 
WRAP 2018 Base Case Inventory 6-3 

Version 1, January 2006 Table 6-1. Cont. Tribe or State County FIPS Tribal or State Facility/ 2002 EI Identifier Plant SIC Facility Name 

CA 06029 1505129 3241 California Portland Cement Co. CA 06037 19102625070 4953 La Co., Sanitation District CA 06037 19102647232 3463 Arco Cqc Kiln CA 06037 1910267427 3221 Owens-Brockway Glass Container CA 06037 191026180001 4581 Los Angeles International CA 06037 191026114801 2819 Rhodia Inc. CA 06037 191026800362 2911 Tosco Refining Company CA 06037 191026800370 2911 Equilon Enterprises, Llc CA 06037 191026800026 2911 Ultramar Inc (Nsr Use Only) CA 06037 191026800363 2911 Tosco Refining Company CA 06037 191026800089 2911 Mobil Oil Corp CA 06037 191026800030 2911 Chevron U.S.A. Inc. CA 06037 191026131003 2911 West Coast Products Llc CA 06039 201430801 3221 Saint-Gobain Containers, Inc CA 06071 36051850001051 4911 Ace Cogeneration Co. CA 06071 361026800181 3241 California Portland Cement Co CA 06071 3605181200003 3241 Txi Riverside Cement Company CA 06071 36051811800001 3241 Mitsubishi Cement 2000 CA 06071 360518100005 3241 Cemex – Black Mountain Quarry CA 06077 391430802 4931 Stockton Cogen Company CA 06077 391430593 3221 Owens-Brockway Glass Container CA 06077 391430767 2873 J R Simplot Company CA 06077 391430477 3211 Pilkington North America, Inc CA 06079 40113113 2911 Conoco Phillips Santa Maria Fa CA 06083 4211251735 3295 Celite Corporation CA 06085 43130317 3241 Hanson Permanente Cement CA 06087 4407151186 3241 Rmc Pacific Materials CA 06095 48130312626 2911 Valero Refining Company - Cali CA 06099 5014301662 3221 Gallo Glass Company CO 08001 0004 2911 Colorado Refining Co., Total Petroleum CO 08001 0003 2911 Suncor Energy - Denver Refinery 
WRAP 2018 Base Case Inventory 6-4 

Version 1, January 2006 Table 6-1. Cont. Tribe or State County FIPS Tribal or State Facility/ 2002 EI Identifier Plant SIC Facility Name 

CO 08001 EGU0163 4911 Public Service Co Cherokee Plt CO 08013 EGU0164 4911 Public Service Co – Valmont CO 08031 BSCP157 3251 Robinson Brick Co CO 08031 EGU0165 4911 Public Service Co – Arapahoe CO 08041 EGU0169 4911 Colorado Springs Utilities-Nixon Plant CO 08041 EGU0167 4911 Colorado Springs Utilities-Drake Plant CO 08043 0001 3241 Holcim (Us) Inc. Portland Plant CO 08043 0003 4911 Aquila, Inc. – W.N. Clark Station CO 08059 0008 3221 Rocky Mountain Bottle Co CO 08059 0820 4961 Trigen - Colorado Energy Corporation CO 08069 0002 3241 Holcim (Us) Inc - Fort Collins Plant CO 08069 EGU0173 4911 Platte River Power Authority – Rawhide CO 08077 EGU0174 4911 Public Service Co Cameo Plt CO 08081 EGU0175 4911 Tri State Generation Craig CO 08085 EGU0176 4911 Tri State Generation Nucla CO 08087 EGU0179 4911 Public Service Co Pawnee Plt CO 08101 0048 3312 Cf&I Steel L P Dba Rocky Mtn Steel Mills CO 08101 EGU0182 4911 Public Service Co Comanche Plt CO 08107 EGU0183 4911 Public Service Co Hayden Plt ID 16027 02700010 2063 Tasco, Nampa ID 16029 02900003 2874 Nu West Industries ID 16029 02900001 2819 P4 Production LLC ID 16067 06700001 2063 Tasco, Paul ID 16077 07700006 2874 Jr Simplot Company Don Siding Complex ID 16083 08300001 2063 Tasco, Twin Falls NV 32003 0003 3275 Chemical Lime Company NV 32003 EGU0742 4911 Nevada Power Company NV 32003 EGU0744 4911 Southern California Edison NV 32007 AP32740261 3274 Graymont Western Us Inc NV 32011 AP10410404 1041 Newmont Gold Company NV 32011 AP10410739 1041 Barrick Goldstrike Mines Inc 
WRAP 2018 Base Case Inventory 6-5 

Version 1, January 2006 Table 6-1. Cont. Tribe or State County FIPS Tribal or State Facility/ 2002 EI Identifier Plant SIC Facility Name 

NV 32013 AP10410451 1041 Sante Fe Pacific Gold Corporation NV 32013 EGU0749 4911 North Valmy Station NV 32019 AP32410387 3241 Nevada Cement Company NM 35001 0001 Rio Grande Portland Cement NM 35007 350070001 4911 Raton Power Plant NM 35015 350150285 1321 Dagger Draw Gas Plant NM 35015 350150011 1321 Artesia Gas Plant NM 35015 350150010 2911 Artesia Refinery NM 35015 350150008 1311 Indian Basin Gas Plant NM 35015 350150024 1311 Agave Gas Plant NM 35025 350250063 1321 Saunders Plant NM 35025 350250007 1311 Denton Plant NM 35025 350250060 1321 Eunice Gas Plant NM 35025 350250061 1321 Monument Plant NM 35025 350250035 1321 Linam Ranch Gas Plant NM 35025 350250008 1321 Jal No. 3 NM 35025 350250044 1321 Eunice Gas Plant NM 35025 350250004 1321 Maljamar Gas Plant NM 35031 350310008 2911 Ciniza Refinery NM 35031 EGU0792 4911 Escalante Station NM 35045 350450247 1321 San Juan River Gas Plant NM 35045 350450023 2911 San Juan Refinery (Bloomfield) NM 35045 EGU0794 4911 San Juan Fly Ash OR 41007 00004 4961 Fort James Operating Company OR 41009 01849 4961 Boise Cascade Corporation OR 41041 00005 4961 Georgia-Pacific West, Inc. OR 41043 03501 4961 Pope & Talbot, Inc. OR 41043 00471 4961 Weyerhaeuser Company OR 41045 00002 4961 Amalgamated Sugar Company, The OR 41049 EGU0971 4911 Portland General Electric Company OR 41051 01876 3221 Owens-Brockway Glass Container Inc. 
WRAP 2018 Base Case Inventory 6-6 

Version 1, January 2006 Table 6-1. Cont. Tribe or State County FIPS Tribal or State Facility/ 2002 EI Identifier Plant SIC Facility Name 

OR 41071 06142 4961 Smurfit Newsprint Corporation UT 49007 10096 4911 Sunnyside Cogeneration Facility UT 49007 EGU1218 4911 Carbon Power Plant UT 49011 10122 2911 Flying J Refinery (Big West Oil Co.) UT 49011 10123 2911 Phillips Refinery UT 49011 10119 2911 Salt Lake Refinery UT 49015 EGU1220 4911 Hunter Power Plant UT 49015 EGU1221 4911 Huntington Power Plant UT 49027 10311 1099 Delta Mill UT 49027 10313 3274 Cricket Mountain Plant UT 49027 EGU1222 4911 Intermountain Generation Station UT 49035 12096 1531 I-15 Corridor Reconstruction UT 49035 10335 2911 Salt Lake City Refinery UT 49035 10346 3331 Kennecott Smelter & Refinery UT 49035 10572 1021 

Kennecott Utah Copper Corp -Power Plt/ Lab/ Tailings Impoundment 

UT 49037 10034 1311 Lisbon Natural Gas Processing Plant UT 49043 10676 3295 Shale Processing UT 49047 EGU1224 4911 Bonanza Power Plant UT 49049 10796 4911 Geneva Steel Manufacturing Facility UT 49049 10790 8221 BYU Main Campus WY 56001 5600100005 4911 University of Wyoming, Heat Plant WY 56001 5600100002 3241 Mountain Cement Co WY 56003 00016 Kcs Mountain Resrcs-Rushmore Flare WY 56005 EGU1324 4911 Black Hills Corporation_Simpson 2 WY 56005 5600500002 4911 Black Hills Corporation Simpson 1 WY 56005 EGU1323 4911 Pacificorp_Wyodak WY 56007 5600700001 2911 Sinclair Oil Corp-Sinclair Refinery WY 56009 EGU1325 4911 Pacificorp_Dave Johnston WY 56011 5601100002 1459 American Colloid_East Colony 
WRAP 2018 Base Case Inventory 6-7 

Version 1, January 2006 Table 6-1. Cont. Tribe or State County FIPS Tribal or State Facilit

y/ 

2002 EI Identifier 

Plant 

SIC Facility Name 

WY 56013 00011 1311 Santa Fe Snyder_Riverton Plant WY 56013 5601300028 1311 Burlington Resources_Lost Cabin WY 56015 5601500001 2063 Western Sugar Coop_Torrington Plant WY 56017 00009 Hallwood Petroleum-Feder Packsaddle 1-24 WY 56017 00006 1311 Kcs Mountain Resrcs_Golden Eagle Flare WY 56017 00008 Hallwood Petroleum-Federal Packsaddle #1 WY 56021 5602100001 2911 Frontier Refining, Inc. WY 56023 5602300013 1311 Exxon Shute Creek I WY 56023 EGU1326 4911 Pacificorp_Naughton Power Plant WY 56025 5602500005 2911 Sinclair Refinery - Casper WY 56029 00003 Celotex Corp. WY 56029 5602900007 1321 Marathon Oil Co _ Oregon Basin Gas Plant WY 56029 5602900012 1311 Howell Pet Corp_Elk Basin Gas Plant WY 56031 EGU1327 4911 Basin Electric_Laramie River Station WY 56035 00001 Exxon -Labarge Dehydration Facility WY 56037 5603700008 1321 Union Pac_Brady WY 56037 5603700003 5171 P4 Production_Rock Springs Facility WY 56037 5603700022 4911 Sf Phosphates, Inc WY 56037 5603700002 4911 General Chemical WY 56037 5603700048 2812 Fmc Corp_Green River Plant_Sodium Prod WY 56037 EGU1330 4911 Pacificorp_Jim Bridger WY 56041 5604100009 1311 Chevron Carter Creek WY 56041 5604100012 1311 Bp America - Whitney Canyon WY 56043 5604300003 1321 Hiland Partners, Llc_Hiland Gas Plant WY 56045 5604500001 2911 Wyoming Refining Co_Newcastle Refinery WY 56045 5604500005 4911 Black Hills Corporation _Osage 
WRAP 2018 Base Case Inventory 

Version 1, January 2006

6-8

Table 6-2. WRAP Facilities Shown in Appendix A-1 of 2003 SO2 Milestone Report, 

and with 2002 SO2 Emissions Less than 100 Tons 

State 

County 

FIPS 

State Facility 

Identifier Facility Name 

2002 SO2

Emissions 

(Tons) Comment 

AZ 041 11582 BHP San Manuel Smelter 0 Retired after 2002 

AZ 003 2148 Douglas Lime Plant 0 Temporary shutdown in 

2002 

NM 001 145 City of Albuquerque – Southside 

 Water Reclamation Plant 

11 

NM 017 0001 Phelps Dodge – Hidalgo Not in 2002 inventory 

NM 023 0003 Phelps Dodge – Chino Not in 2002 inventory 

NM 015 0138 Magnum/Pan Energy – Burton Flats 0 

NM 025 0051 Dynegy Midstream Services, Eunice 

South Gas Plant (old name: Warren 

Petroleum, Eunice Gas Plant) 

<1 

NM 015 0002 BP America Production, Empire Abo 

Plant (old name: Arco Permian Empire 

Abo Plant 

0 

OR 065 0001 Northwest Aluminum Company, Inc. Not in 2002 emissions 

inventory 

OR 005 2145 West Linn Paper Company <3 

WY 011 0003 American Colloid Mineral Company 48 

WY 037 0014 Anadarko E&P Company LP – Table 

Rock Gas Plant 

29 

WY 023 0001 Astaris Production – Coking Plant 0 Retired after 2002 

WY 003 0012 Big Horn Gas Processing, LLC – Big 

Horn/Byron Gas Plant 

0 

WY 005 0146 Black Hills Corporation, Wygen 1 0 

WY American Production Company – 

Whitney Canyon Gas Field 

 Not in 2002 emissions 

inventory 

WY Burlington Resources – Bighorn Wells 0 Came on-line after 2002; 

2018 base case = 3,284 

tons SO2

WY Chevron USA – Table Rock Field 0 Came on-line after 2002; 

2018 base case = 232 tons 

SO2

WY 013 5601300008 Devon Energy Corp – Beaver Creek Gas 

Plant 

40 

WY ExxonMobil Corporation – Black Canyon 

Dehydration Facility 

 Came on-line after 2002; 

2018 base case = 240 tons 

SO2

WY 037 5603700039 FMC Wyoming Corporation – Soda Ash 

Plant 

10 

WY 037 5603700005 Solvay Minerals – Soda Ash Plant 33 
WRAP 2018 Base Case Inventory 

Version 1, January 2006

6-9

6.3 Data Formatting 

Subsequent to development of the final 2018 base case inventory, the results were compiled 

using IDA format and submitted to the WRAP Regional Modeling Center (RMC) for use in 

modeling the “base18a” scenario. Also, the final 2018 base case inventory placed into NIF3.0 

format and submitted to the WRAP for uploading to the EDMS. The inventory will be accessible 

through the EDMS at www.wrapedms.org.
WRAP 2018 Base Case Inventory 

Version 1, January 2006 

7-1

7.0 2018 BASE CASE INVENTORY RESULTS 

The 2018 base case inventory is summarized in Tables 7-1 through 7-6. Table 7-1 

presents the overall 2002 and 2018 WRAP point source inventories at the tribal- and state-level, 

while Table 7-2 disaggregates the WRAP and CENRAP point source inventories into significant 

sectors (e.g., coal-fired EGUs, copper smelters, cement and lime kilns, etc.). The overall 2002 

and 2018 WRAP area source inventories are summarized in Table 7-3. The disaggregated area 

source inventories for NOx, SO2, and PM10 are presented in Tables 7-4 through 7-6 for WRAP 

and CENRAP, although, CENRAP 2018 non-EGU point sources and all area sources are not yet 

available. 

The inventories are also represented in bar charts in Figures 7-1 through 7-4 (for NOx, 

SO2, VOC, and PM10, respectively). Although similar information is presented in the tables and 

bar charts, some significant findings and trends can be readily identified through examination of 

the bar charts. These findings include the following: 

• The distribution of emissions between point and area sources varies by pollutant. Both 

VOC and PM10 are predominantly from area sources, while SO2 is mainly from point 

sources. NOx is similar to SO2; however, the area source contribution is larger. In fact, 

area source NOx exceeds point source NOx in California, Idaho, and New Mexico. 

• For most (but not all) states and pollutants there is moderate growth (i.e., less than 20 

percent). This is primarily driven by population and/or economic growth as expressed by 

growth factors from EGAS, as well as increased demands for electricity generation. 

• Significant decreases in emissions (e.g., point source SO2 emissions in Colorado and 

Nevada) are the result of consent decrees or permit limits. 

• Large increases in area source NOx and VOC emissions (i.e., near doubling or greater in 

New Mexico and Wyoming) are primarily caused by significant projected increases in oil 

and gas production activity. 

Appendix A contains additional 2018 base case inventory (Version 1) summaries, 

including “itemization” of the changes expected to occur in the point and area source inventories 

between 2002 and 2018 (e.g., tonnage change due to growth, tonnage change due to 

retirements/replacements, etc.). 
WRAP 2018 Base Case Inventory 7-2 

Version 1, January 2006 Table 7-1. 2002 and 2018 Base Case – Point Source Emissions by State and Tribe, V

2002 Emissions (tpy) 2018 Em

State State FIPS NOX SO2 VOC CO PM10-PRI PM25-PRI NH3 NOX SO2 VOC C

Alaska 02 74,471 6,811 5,688 27,910 5,933 1,237 578 67,959 7,777 6,633 2Arizona 04 64,084 93,756 5,464 15,232 9,533 1,059 531 77,737 106,113 9,459 3California 06 104,435 42,120 54,160 120,089 29,946 20,276 433 109,515 49,632 54,632 12Colorado 08 117,869 97,011 91,750 35,951 21,125 29 539 112,153 68,476 98,630 5Idaho 16 11,486 17,597 2,113 23,981 1,085 443 1,074 13,946 10,813 3,059 3Montana 30 53,415 36,879 7,577 33,199 8,127 309 318 62,583 43,055 10,446 6Nevada 32 59,737 50,720 2,213 11,083 4,738 1,075 629 69,016 24,041 4,113 2New Mexico 35 100,352 37,436 17,574 36,589 3,826 2,678 75 74,874 40,825 26,187 5North Dakota 38 87,425 156,668 2,086 11,944 3,277 2,712 518 91,895 162,705 2,494 2Oregon 41 24,959 17,587 27,846 35,494 10,442 8,885 948 31,761 21,687 41,344 5South Dakota 46 20,697 14,022 2,542 4,700 974 246 100 24,726 15,268 3,522 Utah 49 91,044 42,838 7,482 51,572 12,904 4,473 1,937 96,974 52,953 13,600 9Washington 53 43,631 52,969 18,616 114,317 9,910 3,642 3,863 49,397 51,355 28,013 18Wyoming 56 117,883 119,645 19,663 36,361 31,731 13,653 685 132,591 145,100 28,087 6Tribes (Total) 00 87,215 38,208 1,710 6,297 6,342 3,006 125 92,580 32,895 2,864 1Total 1,058,702 824,265 266,484 564,719 159,892 63,723 12,352 1,107,708 832,693 333,083 86

Tribe 

Tribal 

FIPS NOX SO2 VOC CO PM10-PRI PM25-PRI NH3 NOX SO2 VOC C

Arapahoe Tribe of the Wind River Reservation, Wyoming 281 54 939 60 11 44 1,511 158 Assiniboine and Sioux Tribes of the Fort Peck Indian Reservation, Montana 206 151 1 25 104 42 90 1 31 Cabazon Band of Cahuilla Mission Indians of the Cabazon Reservation, California 568 190 52 11 4 9 268 73 15 Coeur d'Alene Tribe of the Coeur d'Alene Reservation, Idaho 181 323 12 289 569 1,127 363 15 378 Confederated Tribes and Bands of the Yakama Nation, Washington 124 60 16 120 95 96 64 15 191 
WRAP 2018 Base Case Inventory 7-3 

Version 1, January 2006 Table 7-1. Cont. Tribe Tribal FIPS NOX SO2 VOC CO PM10-PRI PM25-PRI NH3 NOX SO2 VOC C

Confederated Tribes of the Colville Reservation, Washington 101 227 22 58 570 308 245 34 87 

Confederated Tribes of the Umatilla Reservation, Oregon 143 6 1 Fort Mojave Indian Tribe of Arizona, California & Nevada 604 13 225 12 271 Gila River Indian Community of the Gila River Indian Reservation, Arizona 614 65 15 124 69 181 86 17 180 La Posta Band of Diegueno Mission Indians of the La Posta Indian Reservation, California 577 1 0 0 0 5 2 0 0 Navajo Nation, Arizona, New Mexico & Utah 780 83,387 37,028 915 4,621 4,115 2,929 125 88,234 31,108 1,422 1Pueblo of Laguna, New Mexico 707 1,439 0 10 2,038 0 13 Pueblo of Santa Ana, New Mexico 715 209 53 49 64 54 209 53 49 Salt River Pima-Maricopa Indian Community of the Salt River Reservation, Arizona 615 212 64 29 95 284 69 180 50 41 Shoshone-Bannock Tribes of the Fort Hall Reservation of Idaho 180 855 1 20 106 2 484 2 29 Tohono O'Odham Nation of Arizona 610 42 3 68 48 3 Ute Mountain Tribe of the Ute Mountain Reservation, Colorado, New Mexico & Utah 751 23 7 Total 87,215 38,208 1,710 6,297 6,342 3,006 125 92,580 32,895 2,864 1
WRAP 2018 Base Case Inventory 7-4 

Version 1, January 2006 Table 7-2. 2002 and 2018 Base Case – Point Source Emissions by Sector, Versio

2002 Emissions (tpy) 2018 

State NOX SO2 VOC PM10-PRI PM25-PRI NH3 NOX SO2 VO

WRAP Point Sources Total 1,058,743 824,260 266,469 159,905 63,741 12,352 1,107,708 832,693 333,

Coal-fired EGUs Total 574,643 581,397 3,988 32,064 14,760 2,884 615,081 543,078 5,

Arizona 45,401 66,642 193 1,129 96 172 49,491 60,013 California 397 342 3 19 7 431 395 Colorado 72,513 89,157 450 2,455 0 299 71,406 59,919 Idaho 0 0 0 0 0 1,675 1,675 Montana 35,644 21,846 331 632 0 11 44,105 26,860 Nevada 38,872 49,198 186 2,657 426 127 39,823 21,912 New Mexico 33,997 18,233 184 1,769 399 5 25,392 17,170 North Dakota 75,950 140,534 781 2,911 2,349 378 82,738 152,827 Oregon 8,401 12,262 62 695 2 31 9,444 14,935 South Dakota 14,954 11,756 108 234 234 50 15,323 12,859 Utah 71,388 32,130 306 3,689 1,645 1,303 74,732 41,369 Washington 15,463 19,032 14,499 6,378 Wyoming 84,518 83,411 852 11,774 6,673 382 102,849 96,050 1,Tribes 77,146 36,854 533 4,100 2,929 125 83,174 30,716 

Other EGUs Total 66,689 19,811 10,671 10,510 4,933 1,295 97,977 22,464 16,

Alaska 11,077 3,339 153 814 2 13,061 5,298 Arizona 5,819 1,680 344 1,053 378 288 12,627 1,288 California 16,369 1,029 1,601 3,072 3,003 88 20,288 1,327 2,Colorado 4,327 96 553 821 29 154 6,268 162 Idaho 19 0 0 2 312 7 Montana 395 1,550 24 115 0 591 2,177 Nevada 13,070 108 449 712 117 342 18,053 212 1,New Mexico 3,075 46 148 186 70 7 6,139 66 North Dakota 31 Oregon 497 23 44 122 37 130 4,893 65 South Dakota 967 786 4 37 2,329 663 Utah 1,891 1,138 122 172 90 40 2,332 807 Washington 5,721 2,791 2,121 2,274 1,207 178 7,389 3,569 3,
WRAP 2018 Base Case Inventory 7-5 

Version 1, January 2006 Table 7-2. Cont. 2002 Emissions (tpy) 2018 

State NOX SO2 VOC PM10-PRI PM25-PRI NH3 NOX SO2 VO

Wyoming 3,243 7,171 5,098 1,108 36 3,164 6,733 7,Tribes 218 56 12 23 532 91 

Copper Smelters Total 538 25,044 205 832 155 0 818 44,191 

Arizona 377 24,105 195 639 0 555 42,501 Utah 161 939 10 194 155 0 264 1,690 

Cement and Lime Kilns Total 56,061 8,489 1,192 8,190 1,884 31 74,719 12,281 1,

Arizona 6,533 987 38 1,410 7,969 1,788 California 20,555 3,292 248 3,498 1,388 0 25,618 4,156 Colorado 3,844 670 208 958 5,454 1,098 Idaho 672 40 7 6 973 45 Montana 3,570 601 9 509 0 1 4,631 746 Nevada 4,547 426 144 6,321 560 New Mexico 804 15 37 97 1,055 25 Oregon 1,741 38 15 64 2,290 63 South Dakota 3,846 760 108 270 6,083 1,230 Utah 3,965 374 326 835 367 24 6,066 567 Washington 3,747 1,068 0 280 128 0 5,519 1,672 Wyoming 2,232 210 46 232 2,733 319 Tribes 6 9 4 38 7 11 

Oil & Gas Refining and Distribution Total 38,522 65,051 23,248 4,250 2,007 357 39,257 66,348 28,

Alaska 2,256 518 864 169 33 16 2,304 490 1,Arizona 1,559 1 39 24 10 10 1,564 1 California 14,077 22,305 8,070 1,675 1,599 12,328 25,407 9,Colorado 1,047 2,584 822 304 1 1,207 2,597 1,Montana 2,644 8,827 3,408 461 1 41 2,871 7,335 4,Nevada 82 93 62 112 123 New Mexico 1,572 3,645 2,777 276 194 4 1,522 2,898 3,North Dakota 4,345 10,245 356 0 4,135 4,109 Oregon 805 4 25 9 1 795 4 South Dakota 0 0 0 0 0 0
WRAP 2018 Base Case Inventory 7-6 

Version 1, January 2006 Table 7-2. Cont. 2002 Emissions (tpy) 2018 

State NOX SO2 VOC PM10-PRI PM25-PRI NH3 NOX SO2 VO

Utah 1,947 2,781 1,342 300 156 272 2,005 2,975 1,Washington 4,647 7,674 1,501 413 14 2 5,494 7,330 1,Wyoming 1,753 6,374 3,972 617 0 11 2,325 13,079 4,Tribes 1,789 0 10 1 2,595 0 

Oil & Gas Production Total 188,134 36,133 93,808 5,053 4,007 133 131,645 48,431 100,

Alaska 45,822 826 2,310 2,253 822 21 36,501 122 2,Arizona 2,735 3 233 48 3,468 10 California 16,707 2,556 7,101 1,698 1,699 7 13,390 1,988 4,Colorado 25,955 93 63,960 401 15,832 131 59,Idaho 2,590 7 78 1,734 10 Montana 4,275 11 687 22 0 2,554 16 1,Nevada 83 0 23 0 139 5 New Mexico 57,173 14,156 11,527 330 1,382 32 36,323 19,226 18,North Dakota 4,739 2,949 187 7 7 1 2,946 3,354 Oregon 1,182 8 40 15 0 608 4 South Dakota 323 10 26 128 311 15 Utah 3,311 1,457 852 22 24 73 2,314 2,125 3,Washington 1,281 19 64 72 54 703 11 Wyoming 15,015 13,822 6,283 27 18 0 9,713 20,902 10,Tribes 6,943 217 437 30 5,109 512 

All Other Point Sources Total 134,156 88,334 133,357 99,006 35,996 7,651 148,210 95,900 179,

Alaska 15,317 2,127 2,360 2,697 379 542 16,093 1,867 3,Arizona 1,661 334 4,410 5,226 570 59 2,064 512 7,California 36,330 12,597 37,136 19,984 12,580 339 37,460 16,360 37,Colorado 10,182 4,411 25,758 16,186 85 11,985 4,570 36,Idaho 8,206 17,550 2,027 1,085 442 1,068 9,252 9,076 2,Montana 6,887 4,044 3,118 6,388 307 265 7,831 5,921 4,Nevada 3,121 896 1,350 1,395 558 160 4,569 1,227 2,New Mexico 3,730 1,342 2,900 1,169 633 27 4,442 1,440 3,North Dakota 2,392 2,939 763 359 356 107 2,076 2,416 
WRAP 2018 Base Case Inventory 7-7 

Version 1, January 2006 Table 7-2. Cont. 2002 Emissions (tpy) 2018 

State NOX SO2 VOC PM10-PRI PM25-PRI NH3 NOX SO2 VO

Oregon 12,333 5,252 27,659 9,537 8,845 787 13,732 6,616 40,South Dakota 607 709 2,297 305 13 50 680 501 3,Utah 8,382 4,019 4,526 7,692 2,036 224 9,262 3,420 7,Washington 12,773 22,386 14,930 6,873 2,239 3,683 15,794 32,395 22,Wyoming 11,122 8,658 3,411 17,973 6,962 255 11,808 8,016 4,Tribes 1,113 1,071 714 2,137 77 1,163 1,565 

CENRAP Point Sources Total 1,826,695 2,225,082 532,620 376,018 233,158 194,467 597,336 1,279,135 11,

CENRAP EGUs Total 973,128 1,553,010 17,409 84,529 55,227 4,404 597,336 1,279,135 11,

Arkansas 39,303 70,367 476 1,173 586 1 33,097 82,605 Iowa 83,563 133,641 803 12,959 5,913 51,119 147,305 Kansas 94,665 129,720 1,087 15,475 13,696 4,166 83,333 81,486 Louisiana 116,018 108,657 3,089 10,441 7,943 28 30,432 74,262 Minnesota 91,497 105,826 728 10,122 6,301 59 41,029 85,847 Missouri 144,674 259,663 1,518 4,745 2,845 46 77,660 280,887 1,Nebraska 47,225 67,592 638 332 195 44 50,781 73,629 Oklahoma 86,222 110,837 988 4,365 2,639 61 76,048 113,680 1,Texas 269,961 566,708 8,082 24,918 15,109 153,837 339,433 4,

CENRAP Other Point Sources Total 853,567 672,072 515,211 291,488 177,931 190,063 

Arkansas 29,564 20,401 102,032 38,811 30,881 2,910 Iowa 38,561 51,024 38,353 15,829 7,737 3,366 Kansas 70,620 10,651 26,371 31,606 11,376 59,749 Louisiana 196,616 177,393 85,936 62,892 52,956 9,209 Minnesota 63,645 25,716 40,242 40,989 21,236 28,614 Missouri 37,125 101,885 34,626 16,204 8,235 31,074 Nebraska 11,394 5,895 6,636 12,773 4,443 30,687 Oklahoma 72,749 38,015 35,998 13,644 7,137 24,196 Texas 332,396 241,090 144,993 58,611 33,833 255 Tribes 898 0 22 129 96 4 
WRAP 2018 Base Case Inventory 7-8 

Version 1, January 2006 Table 7-3. 2002 and 2018 Base Case – Area Source Emissions by State and Tribe, Ve

2002 Emissions (tpy) 2018 

State State FIPS NOX SO2 VOC CO PM10-PRI PM25-PRI NH3 NOX SO2 VOC 

Alaska 02 8,488 5,531 13,020 27,258 15,042 5,474 472 9,293 6,044 16,539 Arizona 04 9,049 2,677 108,332 49,957 99,963 28,290 5,922 12,559 3,410 171,415 California 06 114,471 8,314 343,778 374,891 179,932 85,948 7,510 117,717 9,772 357,746 Colorado 08 34,846 6,559 124,578 87,628 157,875 42,612 77 44,041 7,499 173,092 Idaho 16 30,318 2,916 123,944 34,271 50,992 5,729 1,684 42,068 2,721 194,210 Montana 30 12,072 3,299 55,104 36,903 153,207 35,456 460 36,053 3,432 67,477 Nevada 32 5,787 12,954 29,977 13,737 68,009 16,074 1,120 7,488 14,194 47,610 New Mexico 35 85,576 6,559 219,124 37,284 109,381 26,626 636 172,319 15,753 399,205 North Dakota 38 15,457 5,748 69,795 21,970 287,622 60,308 368 21,129 5,856 82,651 Oregon 41 14,825 9,932 251,802 352,955 177,460 69,096 227 17,027 8,422 334,872 South Dakota 46 6,345 10,167 42,661 24,249 209,041 45,029 381 7,207 11,667 50,072 Utah 49 11,335 3,581 85,320 42,929 30,256 4,975 1,320 21,636 3,587 173,344 Washington 53 18,355 7,388 198,283 222,555 283,542 93,472 4,471 22,746 8,667 253,710 Wyoming 56 34,891 17,902 140,248 29,292 37,511 10,804 389 79,196 23,109 436,885 Tribes (Total) 00 2,932 49 8,472 283 1,978 398 0 6,639 2 18,240 Total 404,749 103,577 1,814,439 1,356,163 1,861,810 530,289 25,034 617,116 124,136 2,777,068 

Tribe Tribal FIPs NOX SO2 VOC CO PM10-PRI PM25-PRI NH3 NOX SO2 VOC 

Arapahoe Tribe of the Wind River Reservation, Wyoming 281 1,169 46 3,961 49 2,963 0 10,436 Assiniboine and Sioux Tribes of the Fort Peck Indian Reservation, Montana 206 57 1 1,374 118 1,976 398 0 80 2 2,108 Cortina Indian Rancheria of Wintun Indians of California 513 0 0 0 2 2 0 0 1 
WRAP 2018 Base Case Inventory 7-9 

Version 1, January 2006 Table 7-3. Cont. Tribe Tribal FIPS NOX SO2 VOC CO PM10-PRI PM25-PRI NH3 NOX SO2 VOC 

La Posta Band of Diegueno Mission Indians of the La Posta Indian Reservation, California 577 0 0 0 0 0 0 0 0 0 Navajo Nation, Arizona, New Mexico & Utah 780 1,167 2 2,344 101 2,810 0 4,540 Ute Mountain Tribe of the Ute Mountain Reservation, Colorado, New Mexico & Utah 751 540 0 793 13 785 0 1,156 Total 2,932 49 8,472 283 1,978 398 0 6,639 2 18,240 
WRAP 2018 Base Case Inventory 

Version 1, January 2006 

7-10

Table 7-4. 2002 and 2018 Base Case – Area Source NOx Emissions by Sector, 

Version 1 

2002 (tons) 2018 (tons) 

WRAP Area Sources (all categories) 404,718 617,116

Commercial/Institutional Heating - Natural Gas 26,871 31,624

Alaska 760 948

Arizona 1,462 2,086

California 14,564 15,271

Colorado 1,893 2,700

Idaho 739 1,054

Montana 657 929

Nevada 483 683

New Mexico 613 874

North Dakota 522 569

Oregon 1,231 1,536

South Dakota 486 529

Utah 219 310

Washington 2,742 3,422

Wyoming 490 699

Tribes 9 13

Industrial Combustion - Bituminous Coal 9,807 10,332

Arizona 565 584

Idaho 1,631 1,683

Montana 530 567

Nevada 962 1,030

New Mexico 196 203

South Dakota 2,079 2,284

Utah 0 0

Washington 434 462

Wyoming 3,408 3,518

Industrial Combustion - Distillate Oil 12,235 14,729

Arizona 1,267 1,590

California 203 272

Colorado 1,371 1,720

Idaho 1,508 1,892

Montana 681 784

Nevada 1,037 1,193

New Mexico 412 518

North Dakota 1,440 1,531

Oregon 359 445

South Dakota 831 883

Washington 1,502 1,862

Wyoming 1,625 2,039
WRAP 2018 Base Case Inventory 

Version 1, January 2006 

7-11

Table 7-4. Cont. 

2002 (tons) 2018 (tons) 

Industrial Combustion - Natural Gas 75,563 92,947

Alaska 2,048 2,303

Arizona 301 374

California 33,875 42,249

Idaho 1,067 1,325

Montana 333 464

Nevada 621 863

New Mexico 16,821 20,894

North Dakota 6,908 8,232

Oregon 2,360 2,654

South Dakota 822 980

Washington 2,711 3,049

Wyoming 7,697 9,561

Oil and Gas Production 133,252 293,624

Alaska 886 568

California 8,071 7,695

Colorado 23,147 27,709

Montana 7,792 30,529

Nevada 62 72

New Mexico 60,446 138,551

North Dakota 4,631 8,678

Oregon 85 48

South Dakota 367 507

Utah 5,190 13,174

Wyoming 19,699 59,533

Tribes 2,875 6,559

Residential Heating - LPG 4,373 5,000

Alaska 32 41

Arizona 215 260

California 1,146 1,072

Colorado 549 666

Idaho 421 511

Montana 158 226

Nevada 124 177

New Mexico 340 412

North Dakota 301 307

Oregon 162 206

South Dakota 286 291

Utah 150 214

Washington 355 451
WRAP 2018 Base Case Inventory 

Version 1, January 2006 

7-12

Table 7-4. Cont. 

2002 (tons) 2018 (tons) 

Wyoming 107 130

Tribes 25 36

Residential Heating - Natural Gas 45,564 54,424

Alaska 751 902

Arizona 1,654 2,602

California 21,978 20,312

Colorado 5,419 8,528

Idaho 958 1,508

Montana 943 1,443

Nevada 1,499 2,293

New Mexico 1,688 2,657

North Dakota 515 572

Oregon 1,809 2,172

South Dakota 593 658

Utah 3,860 5,904

Washington 3,374 4,050

Wyoming 508 799

Tribes 15 23

Woodstoves and Fireplaces 13,649 14,230

Alaska 157 164

Arizona 183 191

California 3,761 3,938

Colorado 916 956

Idaho 170 177

Montana 273 290

Nevada 118 125

New Mexico 144 150

North Dakota 181 181

Oregon 4,293 4,470

South Dakota 213 213

Utah 150 159

Washington 2,851 2,968

Wyoming 238 248

Tribes 0 0

OTHER 83,404 100,206

Alaska 3,853 4,367

Arizona 3,402 4,872

California 30,872 26,906

Colorado 1,552 1,761

Idaho 23,824 33,917

Montana 704 821
WRAP 2018 Base Case Inventory 

Version 1, January 2006 

7-13

Table 7-4. Cont. 

2002 (tons) 2018 (tons) 

Nevada 880 1,051

New Mexico 4,886 8,060

North Dakota 959 1,060

Oregon 4,526 5,496

South Dakota 669 862

Utah 1,766 1,875

Washington 4,384 6,481

Wyoming 1,119 2,668

Tribes 7 9

CENRAP Area Sources 672,142 0

Arkansas 24,563 

Iowa 5,867 

Kansas 42,197 

Louisiana 97,974 

Minnesota 59,566 

Missouri 33,062 

Nebraska 14,720 

Oklahoma 115,134 

Texas 279,051 

Tribes 8 
WRAP 2018 Base Case Inventory 

Version 1, January 2006 

7-14

Table 7-5. 2002 and 2018 Base Case – Area Source SO2 Emissions by Sector, 

Version 1 

2002 (tons) 2018 (tons) 

WRAP Area Sources (all categories) 103,577 124,136

Commercial/Institutional Heating - Bituminous 

Coal 8,550 9,343

Alaska 2,474 2,828

Arizona 2 3

Colorado 2,054 2,260

Idaho 106 116

Montana 30 30

Nevada 11 11

New Mexico 63 70

South Dakota 1 2

Utah 1,749 1,753

Washington 186 212

Wyoming 1,872 2,059

Commercial/Institutional Heating - Natural Gas 138 159

Alaska 5 6

Arizona 7 10

California 72 72

Colorado 5 7

Idaho 4 6

Montana 4 6

Nevada 5 7

New Mexico 4 5

North Dakota 3 3

Oregon 8 10

South Dakota 3 3

Utah 2 2

Washington 16 21

Wyoming 1 1

Tribes 0 0

Industrial Combustion - Bituminous Coal 26,031 27,587

Arizona 918 948

Idaho 1,746 1,803

Montana 1,095 1,173

Nevada 4,935 5,283

New Mexico 508 525

South Dakota 6,966 7,653

Utah 0 0

Washington 750 798

Wyoming 9,111 9,404
WRAP 2018 Base Case Inventory 

Version 1, January 2006 

7-15

Table 7-5. Cont. 

2002 (tons) 2018 (tons) 

Industrial Combustion - Distillate Oil 26,956 31,953

Arizona 1,117 1,402

California 249 346

Colorado 2,920 3,665

Idaho 90 113

Montana 1,450 1,670

Nevada 7,301 8,404

New Mexico 878 1,102

North Dakota 3,068 3,263

Oregon 1,453 1,800

South Dakota 1,769 1,881

Washington 3,200 3,965

Wyoming 3,461 4,343

Industrial Combustion - Residual Oil 11,132 25,445

Alaska 130 22

Arizona 55 248

California 2,555 3,486

Idaho 7 32

Nevada 396 145

New Mexico 2,913 13,106

North Dakota 254 444

Oregon 2,693 449

South Dakota 752 1,317

Wyoming 1,377 6,196

Oil and Gas Production 3,828 110

Alaska 66 1

California 57 52

Colorado 260 9

Montana 227 8

Nevada 1 0

New Mexico 1,444 17

North Dakota 358 3

South Dakota 8 0

Utah 147 5

Wyoming 1,213 16

Tribes 48 1

Residential Heating - LPG 82 97

Alaska 0 0

Arizona 1 2

California 61 71
WRAP 2018 Base Case Inventory 

Version 1, January 2006 

7-16

Table 7-5. Cont. 

2002 (tons) 2018 (tons) 

Colorado 4 5

Idaho 3 4

Montana 1 1

Nevada 1 1

New Mexico 2 3

North Dakota 2 2

Oregon 1 1

South Dakota 2 2

Utah 1 1

Washington 2 3

Wyoming 1 1

Tribes 0 0

Residential Heating - Natural Gas 296 379

Alaska 5 6

Arizona 11 17

California 145 162

Colorado 35 54

Idaho 6 10

Montana 6 9

Nevada 9 14

New Mexico 11 17

North Dakota 3 4

Oregon 12 14

South Dakota 4 4

Utah 25 38

Washington 22 26

Wyoming 4 6

Woodstoves and Fireplaces 1,931 2,011

Alaska 24 25

Arizona 28 29

California 550 574

Colorado 177 185

Idaho 26 27

Montana 42 44

Nevada 11 11

New Mexico 22 23

North Dakota 28 28

Oregon 616 642

South Dakota 33 33

Utah 23 24

Washington 332 346
WRAP 2018 Base Case Inventory 

Version 1, January 2006 

7-17

Table 7-5. Cont. 

2002 (tons) 2018 (tons) 

Wyoming 20 21

Tribes 0 0

OTHER 24,633 27,051

Alaska 2,828 3,156

Arizona 538 753

California 4,625 5,010

Colorado 1,104 1,314

Idaho 928 610

Montana 443 491

Nevada 286 319

New Mexico 714 886

North Dakota 2,031 2,110

Oregon 5,149 5,506

South Dakota 628 773

Utah 1,635 1,764

Washington 2,879 3,296

Wyoming 843 1,062

Tribes 1 1

CENRAP Area Sources 321,088 0

Arkansas 27,887

Iowa 3,286

Kansas 14,023

Louisiana 83,292

Minnesota 15,558

Missouri 48,183

Nebraska 7,744

Oklahoma 11,731

Texas 109,383

Tribes 1
WRAP 2018 Base Case Inventory 

Version 1, January 2006 

7-18

Table 7-6. 2002 and 2018 Base Case – Area Source PM10 Emissions by Sector, 

Version 1 

2002 (tons) 2018 (tons) 

WRAP Area Sources (all categories) 1,861,810 2,208,103

Agriculture Production - Crops 812,343 838,372

Arizona 17,088 16,383

California 36,186 35,489

Colorado 90,207 93,467

Idaho 15,429 15,986

Montana 89,485 92,718

Nevada 559 579

New Mexico 17,158 17,778

North Dakota 235,684 244,201

Oregon 32,379 33,549

South Dakota 156,837 162,505

Utah 20,626 21,372

Washington 95,762 99,222

Wyoming 3,034 3,144

Tribes 1,910 1,979

Commercial/Institutional Heating - Natural Gas 2,139 152

Alaska 58 5

Arizona 86 8

California 1,177 64

Colorado 224 22

Montana 50 5

Nevada 75 7

New Mexico 47 5

North Dakota 40 3

Oregon 99 8

South Dakota 37 3

Washington 208 18

Wyoming 37 4

Tribes 1 0

Construction 669,647 922,721

Alaska 5,326 9,425

Arizona 61,695 94,032

California 70,655 83,839

Colorado 52,168 75,817

Idaho 27,050 36,130

Montana 27,913 36,366

Nevada 52,443 78,925

New Mexico 76,802 105,599

North Dakota 20,571 24,855
WRAP 2018 Base Case Inventory 

Version 1, January 2006 

7-19

Table 7-6. Cont. 

2002 (tons) 2018 (tons) 

Oregon 93,264 133,182

South Dakota 10,984 14,020

Utah 6,478 9,130

Washington 140,333 192,604

Wyoming 23,964 28,795

Tribes 2 2

Food and Kindred Products 23,256 26,603

Alaska 228 325

Arizona 1,973 2,569

California 12,288 12,269

Colorado 1,843 2,202

Idaho 431 630

Montana 365 441

Nevada 109 136

New Mexico 619 771

North Dakota 180 219

Oregon 1,746 2,481

South Dakota 252 280

Utah 605 758

Washington 2,411 3,284

Wyoming 205 237

Mining and Quarrying 146,311 191,970

Alaska 3,644 5,466

Arizona 9,923 12,096

California 1,377 1,514

Montana 29,250 37,670

Nevada 12,142 14,691

New Mexico 8,745 12,284

North Dakota 27,683 38,588

Oregon 6,246 9,370

South Dakota 34,473 43,091

Washington 6,767 9,003

Wyoming 5,999 8,117

Tribes 62 80

Oil and Gas Production 189 177

California 189 177

Open Burning - Land Clearing Debris 15,723 21,527

Arizona 2,189 3,461

Montana 888 1,031

Nevada 215 363

New Mexico 1,159 1,496
WRAP 2018 Base Case Inventory 

Version 1, January 2006 

7-20

Table 7-6. Cont. 

2002 (tons) 2018 (tons) 

North Dakota 37 39

Oregon 1,834 2,485

South Dakota 205 230

Washington 8,805 11,995

Wyoming 392 428

Open Burning - Residential Household Waste 24,803 33,324

Alaska 664 899

Arizona 2,773 4,385

Idaho 5,819 7,772

Montana 1,235 1,434

Nevada 367 620

New Mexico 1,936 2,498

North Dakota 884 948

Oregon 3,501 4,744

South Dakota 1,115 1,250

Utah 131 183

Washington 6,012 8,190

Wyoming 367 401

Residential Heating - Natural Gas 3,216 275

Alaska 61 5

Arizona 134 14

California 1,876 143

Colorado 438 47

Montana 76 8

Nevada 90 9

New Mexico 136 15

North Dakota 42 3

South Dakota 48 4

Washington 273 22

Wyoming 41 4

Tribes 1 0

Woodstoves and Fireplaces 130,820 136,235

Alaska 1,746 1,818

Arizona 2,097 2,188

California 41,298 43,069

Colorado 11,388 11,883

Idaho 2,263 2,362

Montana 3,025 3,206

Nevada 640 678

New Mexico 1,565 1,633

North Dakota 2,000 2,000
WRAP 2018 Base Case Inventory 

Version 1, January 2006 

7-21

Table 7-6. Cont. 

2002 (tons) 2018 (tons) 

Oregon 37,628 39,175

South Dakota 2,361 2,361

Utah 1,575 0

Washington 20,854 1,669

Wyoming 2,378 21,711

Tribes 0 2,482

OTHER 33,364 36,746

Alaska 3,316 3,590

Arizona 2,006 2,747

California 14,887 14,424

Colorado 1,606 1,799

Idaho 0 1

Montana 920 1,014

Nevada 1,369 1,747

New Mexico 1,214 2,211

North Dakota 502 415

Oregon 761 931

South Dakota 2,729 3,005

Utah 840 1,167

Washington 2,117 2,279

Wyoming 1,094 1,415

Tribes 2 0

CENRAP Area Sources 1,849,378 0

Arkansas 74,599

Iowa 55,303

Kansas 161,963

Louisiana 95,076

Minnesota 304,452

Missouri 93,331

Nebraska 36,332

Oklahoma 121,772

Texas 906,497

Tribes 52
WRAP 2018 Base Case Inventory 7-22 

Version 1, January 2006 Figure 7-1. WRAP Point and Area Source 2002 and 2018 NOx Emissions, Versio

0

20,00040,00060,00080,000

100,000120,000140,000160,000180,000200,000

Emissions (tpy)

2002-Point 74,472 64,084 104,435 117,869 11,487 53,415 59,775 100,352 87,425 24,959 20,698 91,044 2018-Point 67,959 77,737 109,515 112,153 13,946 62,583 69,016 74,874 91,895 31,761 24,726 96,974 2002-Area 8,488 9,049 114,471 34,846 30,318 12,072 5,787 85,576 15,457 14,825 6,345 11,335 2018-Area 9,293 12,559 117,717 44,041 42,068 36,053 7,488 172,319 21,129 17,027 7,207 21,636 

AK AZ CA CO ID MT NV NM ND OR SD UT 
WRAP 2018 Base Case Inventory 7-23 

Version 1, January 2006 Figure 7-2. WRAP Point and Area Source 2002 and 2018 SO2 Emissions, Versio

0

20,00040,00060,00080,000

100,000120,000140,000160,000180,000

Emissions (tpy)

2002-Point 6,809 93,752 42,120 97,011 17,597 36,879 50,722 37,436 156,668 17,587 14,021 42,838 2018-Point 7,777 106,113 49,632 68,476 10,813 43,055 24,041 40,825 162,705 21,687 15,268 52,953 2002-Area 5,531 2,677 8,314 6,559 2,916 3,299 12,954 6,559 5,748 9,932 10,167 3,581 2018-Area 6,044 3,410 9,772 7,499 2,721 3,432 14,194 15,753 5,856 8,422 11,667 3,587 

AK AZ CA CO ID MT NV NM ND OR SD UT 
WRAP 2018 Base Case Inventory 7-24 

Version 1, January 2006 Figure 7-3. WRAP Point and Area Source 2002 and 2018 VOC Emissions, Versio

0

50,000

100,000150,000200,000250,000300,000350,000400,000450,000500,000

Emissions (tpy)

2002-Point 5,686 5,451 54,160 91,750 2,113 7,577 2,213 17,574 2,086 27,845 2,542 7,482018-Point 6,633 9,459 54,632 98,630 3,059 10,446 4,113 26,187 2,494 41,344 3,522 13,62002-Area 13,020 108,332 343,778 124,578 123,944 55,104 29,977 219,124 69,795 251,802 42,661 85,32018-Area 16,539 171,415 357,746 173,092 194,210 67,477 47,610 399,205 82,651 334,872 50,072 173,3

AK AZ CA CO ID MT NV NM ND OR SD UT 
WRAP 2018 Base Case Inventory 7-25 

Version 1, January 2006 Figure 7-4. WRAP Point and Area Source 2002 and 2018 PM10-Primary Emissions, V

0

50,000

100,000150,000200,000250,000300,000350,000400,000

Emissions (tpy)

2002-Point 5,932 9,529 29,946 21,125 1,087 8,127 4,763 3,826 3,277 10,442 974 12,92018-Point 2,879 9,889 33,192 28,697 1,736 11,266 6,200 3,392 4,369 13,515 1,044 18,32002-Area 15,042 99,963 179,932 157,875 50,992 153,207 68,009 109,381 287,622 177,460 209,041 30,22018-Area 21,531 137,883 190,987 185,238 62,881 173,892 97,756 144,289 311,273 225,925 226,750 34,2

AK AZ CA CO ID MT NV NM ND OR SD UT 
WRAP 2018 Base Case Inventory 

Version 1, January 2006

8-1

8.0 REFERENCES 

Abt, 2004. Economic Growth and Analysis System: Getting Started with EGAS 5.0 Beta. 

Prepared for U.S. Environmental Protection Agency, Office of Air Quality Planning and 

Standards by Abt Associates Inc., Bethesda, MD. October. 

EIA, 2005. Annual Energy Outlook 2005 With Projections to 2025. DOE/EIA-0383(2005). 

Energy Information Administration, Washington, DC. February. 

ENVIRON, 2005. Oil and Gas Emission Inventories for the Western States, Draft Report. 

Prepared for the Western Regional Air Partnership, Stationary Sources Joint Forum. Prepared by 

ENVIRON International Corporation, Novato, CA. December. 

Huntley, 2005. Electronic file sent via electronic mail from Roy Huntley, U.S. Environmental 

Protection Agency, Research Triangle Park, NC. August 30. 

Johnson and Lakhanpal, 1997. Redesign of California’s Emission Forecasting System (CEFS). 

Martin E. Johnson, California Air Resources Board, Sacramento, CA, and Dr. Bharat Lakhanpal, 

Institute for Economic and Environmental Studies, California State University, Fullerton. Paper 

presented at the Air and Waste Management Association Specialty Conference on Emission 

Inventories, Research Triangle Park, NC. October 28-30, 1997. 

Pechan, 2001. Development of Emission Growth Surrogates and Activity Projections Used in 

Forecasting Point and Area Source Emissions. Final Report. Prepared for the California Air 

Resources Board, and the California Environmental Protection Agency, Planning and Technical 

Support Division, by E.H. Pechan & Associates, Durham, NC. February 26. 

USDA, 2005. USDA Agricultural Baseline Projections to 2014. Baseline Report OCE-2005-1. 

U.S. Department of Agriculture, Office of the Chief Economist. February. 

U.S. EPA, 1995. Compilation of Air Pollution Emission Factors (AP-42)–Volume I: Stationary 

Point and Area Sources, Fifth Edition (various sections). U.S. Environmental Protection 

Agency, Office of Air Quality Planning and Standards, Research Triangle Park, NC. 

U.S. EPA, 2004. EGAS Website. Internet address: http://www.epa.gov/ttn/ecas/egas5.htm. 

U.S. Environmental Protection Agency, Innovative Strategies and Economics Group. 

U.S. EPA, 2005a. Clean Air Markets – Data and Maps Website. Internet address: 

http://cfpub.epa.gov/gdm/. U.S. Environmental Protection Agency, Clean Air Markets Division. 

U.S. EPA, 2005b. National Coal-Fired Utility Projects. Internet address: http://www.epa.gov/

ttu/cat/dir1/natcoal.xls. U.S. Environmental Protection Agency. May 

WRAP, 2005. 2003 Regional SO2 Emissions and Milestone Report. Internet address: 

http://www.wrapair.org/forums/309/docs.html. Prepared by the Western Regional Air 

Partnership. April 21. 
APPENDIX A 

ADDITIONAL 2018 BASE CASE INVENTORY (VERSION 1) 

SUMMARIES 
A-1 

Table A-1. Itemization of Changes Projected to Point Source Emissions Between 2002 and 20

Version 1 

State 

2002 

Emissions

Actual Post2002 

Adjustments

Actual Post2002 

Controls Growth 

Retirements/

Replacements

Growth 

(New/future) 

WRAP Point Sources Total NOx 1,058,743 1,489 -182 92,310 -87,950 53,585 

Coal-fired EGUs Total 574,643 -1,897 -7 9,504 -737 44,297 

AK AZ 45,401 0 0 2,850 0 5,897 CA 397 CO 72,513 -2,508 0 -1,617 -203 5,864 ID 0 0 0 0 0 1,675 MT 35,644 0 0 3,835 -99 4,724 NV 38,872 0 0 2,060 0 2,345 NM 33,997 0 -7 -10,243 -30 1,675 ND 75,950 0 0 1,762 0 5,026 OR 8,401 0 0 1,043 0 0 SD 14,954 0 0 369 0 0 UT 71,388 0 0 -4,094 0 7,439 WA 15,463 0 0 -964 0 0 WY 84,518 611 0 11,826 -406 6,299 Tribes 77,146 0 0 2,678 0 3,351 

Other EGUs Total 66,689 4,237 0 19,643 -5,366 9,289 

AK 11,077 0 0 3,165 -748 0 AZ 5,819 2,297 0 4,071 -1,406 1,845 CA 16,369 CO 4,327 392 0 2,333 -784 0 ID 19 91 0 209 -7 0 MT 395 4 0 198 -6 0 NV 13,070 728 0 2,081 -339 2,513 NM 3,075 102 0 2,725 -207 443 ND OR 497 172 0 337 -34 3,920 SD 967 72 0 1,483 -193 0 UT 1,891 7 0 540 -445 340 WA 5,721 126 0 2,042 -727 227 
A-2 

Table A-1. Cont. 

State 

2002 

Emissions

Actual Post2002 

Adjustments

Actual Post2002 

Controls Growth 

Retirements/

Replacements

Growth 

(New/future) 

WY 3,243 45 0 347 -472 0 Tribes 218 200 0 114 0 0 

All Other Point SourcesTotal 417,411 -851 -174 63,163 -81,846 0 

AK 63,394 0 0 11,185 -15,503 0 AZ 12,864 -10 0 4,043 -1,276 0 CA 87,668 CO 41,029 0 0 6,697 -13,250 0 ID 11,468 0 0 2,648 -2,155 0 MT 17,376 10 0 3,268 -2,766 0 NV 7,833 66 0 3,302 -60 0 NM 63,280 -414 -174 6,321 -25,670 0 ND 11,475 -661 0 1,395 -3,051 0 OR 16,061 -63 0 3,866 -2,439 0 SD 4,777 0 0 2,477 -179 0 UT 17,765 0 0 4,811 -2,666 0 WA 22,448 72 0 6,483 -1,494 0 WY 30,122 148 0 4,649 -8,340 0 Tribes 9,851 0 0 2,019 -2,996 0 
A-3 

Table A-2. Itemization of Changes Projected to Point Source Emissions Between 2002 and 20

Version 1 

State Section 309 Flag 

2002 

Emissions

Actual Post2002 

Adjustments 

Actual Post2002 Controls Growth Retirements/ Replacements 

(

WRAP Point Sources Total SO2 824,262 3,225 -16,082 51,208 -18,950 

Coal-fired EGUs Total 545,350 532 -29 -6,163 -1,477 

AK AZ Section 309 Sources 66,642 0 0 -1,838 0 AZ 

Non-Section 309 Sources 0 0 0 0 0 

CA Section 309 Sources 342 CA 

Non-Section 309 Sources 

CO Section 309 Sources 53,891 0 0 -9,041 -328 CO 

Non-Section 309 Sources 0 0 0 0 0 

ID Section 309 Sources ID 

Non-Section 309 Sources 0 0 0 0 0 

MT 21,066 0 0 27 -110 NV Section 309 Sources 49,198 0 0 9,851 0 NV 

Non-Section 309 Sources 0 0 0 0 0 

NM Section 309 Sources 18,233 0 -29 -2,664 -45 NM 

Non-Section 309 Sources 0 0 0 0 0 

ND 140,534 0 0 7,266 0 OR Section 309 Sources 12,262 0 0 2,672 0 OR 

Non-Section 309 Sources 

SD 11,756 0 0 1,103 0 UT Section 309 Sources 32,130 0 0 1,801 0 UT 

Non-Section 309 Sources 0 0 0 0 0 

WA 19,032 0 0 -12,654 0 
A-4 

Table A-2. Cont. 

State Section 309 Flag 

2002 

Emissions

Actual Post2002 

Adjustments 

Actual Post2002 Controls Growth Retirements/ Replacements 

(

WY Section 309 Sources 83,411 0 0 6,752 -875 WY 

Non-Section 309 Sources 0 532 0 50 -119 

Tribes Section 309 Sources 36,854 0 0 -9,489 0 Tribes 

Non-Section 309 Sources 0 0 0 0 0 

Other EGUs Total 55,858 -1,659 0 -6,067 -2,980 

AK 3,339 0 0 2,164 -181 AZ Section 309 Sources 1,634 0 0 15 -522 AZ 

Non-Section 309 Sources 46 66 0 37 0 

CA Section 309 Sources CA 

Non-Section 309 Sources 1,029 

CO Section 309 Sources 35,266 -1,819 0 -11,579 0 CO 

Non-Section 309 Sources 96 13 0 52 0 

ID Section 309 Sources ID 

Non-Section 309 Sources 0 3 0 5 0 

MT 2,331 0 0 999 0 NV Section 309 Sources NV 

Non-Section 309 Sources 108 44 0 45 -1 

NM Section 309 Sources 0 0 0 9 0 NM 

Non-Section 309 Sources 46 3 0 13 -8 

OR Section 309 Sources OR 

Non-Section 309 Sources 23 6 0 11 0 

SD 786 4 0 48 -176 UT Section 309 Sources 1,121 0 0 16 -359 
A-5 

Table A-2. Cont. 

State Section 309 Flag 

2002 

Emissions

Actual Post2002 

Adjustments 

Actual Post2002 Controls Growth Retirements/ Replacements 

(

UT 

Non-Section 309 Sources 17 0 0 10 0 

WA 2,791 8 0 914 -145 WY Section 309 Sources 7,171 0 0 1,149 -1,589 WY 

Non-Section 309 Sources 0 2 0 0 0 

Tribes Section 309 Sources Tribes 

Non-Section 309 Sources 56 11 0 24 0 

All Other Point Sources Total SO2 223,053 4,351 -16,053 63,439 -14,492 

AK 3,472 0 -766 558 -475 AZ Section 309 Sources 25,082 0 0 18,995 0 AZ 

Non-Section 309 Sources 349 126 0 261 -2 

CA Section 309 Sources 37,565 CA 

Non-Section 309 Sources 3,184 

CO Section 309 Sources 6,329 0 0 1,396 -1,292 CO 

Non-Section 309 Sources 1,428 0 0 587 -53 

ID Section 309 Sources 17,302 0 -10,228 2,587 -891 ID 

Non-Section 309 Sources 295 0 0 83 -18 

MT 13,483 0 0 2,833 -2,297 NV Section 309 Sources 1,009 0 0 371 0 NV 

Non-Section 309 Sources 407 71 0 76 -17 

NM Section 309 Sources 18,152 0 -669 5,369 -624 NM 

Non-Section 309 Sources 1,005 -16 0 375 -3 

ND 16,134 -362 -4,390 1,621 -3,126 
A-6 

Table A-2. Cont. 

State Section 309 Flag 

2002 

Emissions

Actual Post2002 

Adjustments 

Actual Post2002 Controls Growth Retirements/ Replacements 

(

OR Section 309 Sources 4,784 0 0 1,556 -363 OR 

Non-Section 309 Sources 517 1 0 199 -9 

SD 1,480 0 0 505 -238 UT Section 309 Sources 8,809 0 0 2,186 -1,242 UT 

Non-Section 309 Sources 761 0 0 276 -14 

WA 31,146 -73 0 12,359 -2,024 WY Section 309 Sources 28,101 0 0 10,208 -1,743 WY 

Non-Section 309 Sources 962 4,604 0 240 -57 

Tribes Section 309 Sources 1,015 0 0 638 0 Tribes 

Non-Section 309 Sources 282 0 0 157 -4 
A-7

Table A-3. Itemization of Changes Projected to Area Sources Emissions Between 

2002 and 2018 (NOx), Version 1 

2002 (tons)

Actual Post-2002 

Adjustments Control Growth 2018 (tons)

WRAP Area Sources (All Categories) 404,718 0 -29,785 238,937 617,116

Commercial/Institutional Heating - 

Natural Gas 26,871 0 0 4,047 31,624

Alaska 760 0 0 188 948

Arizona 1,462 0 0 624 2,086

California 14,564 15,271

Colorado 1,893 0 0 807 2,700

Idaho 739 0 0 315 1,054

Montana 657 0 0 272 929

Nevada 483 0 0 200 683

New Mexico 613 0 0 261 874

North Dakota 522 0 0 47 569

Oregon 1,231 0 0 305 1,536

South Dakota 486 0 0 44 529

Utah 219 0 0 91 310

Washington 2,742 0 0 680 3,422

Wyoming 490 0 0 209 699

Tribes 9 0 0 4 13

Industrial Combustion - Bituminous 

Coal 9,807 0 0 525 10,332

Arizona 565 0 0 18 584

Idaho 1,631 0 0 53 1,683

Montana 530 0 0 37 567

Nevada 962 0 0 68 1,030

New Mexico 196 0 0 6 203

South Dakota 2,079 0 0 205 2,284

Utah 0 0 0 0 0

Washington 434 0 0 28 462

Wyoming 3,408 0 0 110 3,518

Industrial Combustion - Distillate 

Oil 12,235 0 0 2,425 14,729

Arizona 1,267 0 0 323 1,590

California 203 272

Colorado 1,371 0 0 349 1,720

Idaho 1,508 0 0 384 1,892

Montana 681 0 0 103 784

Nevada 1,037 0 0 157 1,193

New Mexico 412 0 0 105 518

North Dakota 1,440 0 0 91 1,531

Oregon 359 0 0 86 445

 
A-8

Table A-3. Cont. 

2002 (tons)

Actual Post-2002 

Adjustments Control Growth 2018 (tons)

South Dakota 831 0 0 53 883

Washington 1,502 0 0 359 1,862

Wyoming 1,625 0 0 414 2,039

Industrial Combustion - Natural Gas 75,563 0 0 9,010 92,947

Alaska 2,048 0 0 255 2,303

Arizona 301 0 0 73 374

California 33,875 42,249

Idaho 1,067 0 0 258 1,325

Montana 333 0 0 130 464

Nevada 621 0 0 242 863

New Mexico 16,821 0 0 4,074 20,894

North Dakota 6,908 0 0 1,324 8,232

Oregon 2,360 0 0 294 2,654

South Dakota 822 0 0 158 980

Washington 2,711 0 0 338 3,049

Wyoming 7,697 0 0 1,864 9,561

Oil and Gas Production 133,252 0 -29,785 190,533 293,624

Alaska 886 0 -308 -10 568

California 8,071 7,695

Colorado 23,147 0 -4,235 8,798 27,709

Montana 7,792 0 -4,624 27,361 30,529

Nevada 62 0 -9 19 72

New Mexico 60,446 0 -4,498 82,603 138,551

North Dakota 4,631 0 -709 4,756 8,678

Oregon 85 0 0 -37 48

South Dakota 367 0 -13 154 507

Utah 5,190 0 -1,216 9,200 13,174

Wyoming 19,699 0 -14,015 53,848 59,533

Tribes 2,875 0 -158 3,841 6,559

Residential Heating - LPG 4,373 0 0 700 5,000

Alaska 32 0 0 9 41

Arizona 215 0 0 46 260

California 1,146 1,072

Colorado 549 0 0 117 666

Idaho 421 0 0 90 511

Montana 158 0 0 67 226

Nevada 124 0 0 53 177

New Mexico 340 0 0 72 412

North Dakota 301 0 0 5 307

Oregon 162 0 0 44 206

South Dakota 286 0 0 5 291

 
A-9

Table A-3. Cont. 

2002 (tons)

Actual Post-2002 

Adjustments Control Growth 2018 (tons)

Utah 150 0 0 64 214

Washington 355 0 0 96 451

Wyoming 107 0 0 23 130

Tribes 25 0 0 11 36

Residential Heating - Natural Gas 45,564 0 0 10,526 54,424

Alaska 751 0 0 151 902

Arizona 1,654 0 0 949 2,602

California 21,978 20,312

Colorado 5,419 0 0 3,109 8,528

Idaho 958 0 0 550 1,508

Montana 943 0 0 500 1,443

Nevada 1,499 0 0 794 2,293

New Mexico 1,688 0 0 969 2,657

North Dakota 515 0 0 57 572

Oregon 1,809 0 0 363 2,172

South Dakota 593 0 0 65 658

Utah 3,860 0 0 2,044 5,904

Washington 3,374 0 0 677 4,050

Wyoming 508 0 0 291 799

Tribes 15 0 0 8 23

Woodstoves and Fireplaces 13,649 0 0 404 14,230

Alaska 157 0 0 6 164

Arizona 183 0 0 8 191

California 3,761 3,938

Colorado 916 0 0 40 956

Idaho 170 0 0 7 177

Montana 273 0 0 16 290

Nevada 118 0 0 7 125

New Mexico 144 0 0 6 150

North Dakota 181 0 0 0 181

Oregon 4,293 0 0 176 4,470

South Dakota 213 0 0 0 213

Utah 150 0 0 9 159

Washington 2,851 0 0 117 2,968

Wyoming 238 0 0 10 248

Tribes 0 0 0 0 0

OTHER 83,404 0 0 20,767 100,206

Alaska 3,853 0 0 514 4,367

Arizona 3,402 0 0 1,469 4,872

California 30,872 26,906

Colorado 1,552 0 0 209 1,761

 
A-10

Table A-3. Cont. 

2002 (tons)

Actual Post-2002 

Adjustments Control Growth 2018 (tons)

Idaho 23,824 0 0 10,093 33,917

Montana 704 0 0 118 821

Nevada 880 0 0 170 1,051

New Mexico 4,886 0 0 3,175 8,060

North Dakota 959 0 0 101 1,060

Oregon 4,526 0 0 970 5,496

South Dakota 669 0 0 192 862

Utah 1,766 0 0 108 1,875

Washington 4,384 0 0 2,097 6,481

Wyoming 1,119 0 0 1,550 2,668

Tribes 7 0 0 1 9

CENRAP Area Sources 672,142 0 0 0 0

Arkansas 24,563 

Iowa 5,867 

Kansas 42,197 

Louisiana 97,974 

Minnesota 59,566 

Missouri 33,062 

Nebraska 14,720 

Oklahoma 115,134 

Texas 279,051 

Tribes 8 
A-11

Table A-4. Itemization of Changes Projected to Area Sources Emissions Between 

2002 and 2018 (SO2), Version 1 

2002 (tons)

Actual Post-2002 

Adjustments 

Future 

Controls Growth 2018 (tons)

WRAP Area Sources (all categories) 103,577 0 0 22,814 124,136

Commercial/Institutional Heating - 

Bituminous Coal 8,550 0 0 793 9,343

Alaska 2,474 0 0 353 2,828

Arizona 2 0 0 0 3

Colorado 2,054 0 0 205 2,260

Idaho 106 0 0 11 116

Montana 30 0 0 0 30

Nevada 11 0 0 0 11

New Mexico 63 0 0 6 70

South Dakota 1 0 0 0 2

Utah 1,749 0 0 3 1,753

Washington 186 0 0 27 212

Wyoming 1,872 0 0 187 2,059

Commercial/Institutional Heating - 

Natural Gas 138 0 0 21 159

Alaska 5 0 0 1 6

Arizona 7 0 0 3 10

California 72 72

Colorado 5 0 0 2 7

Idaho 4 0 0 2 6

Montana 4 0 0 2 6

Nevada 5 0 0 2 7

New Mexico 4 0 0 2 5

North Dakota 3 0 0 0 3

Oregon 8 0 0 2 10

South Dakota 3 0 0 0 3

Utah 2 0 0 0 2

Washington 16 0 0 1 21

Wyoming 1 0 0 4 1

Tribes 0 0 0 0 0

Industrial Combustion - Bituminous 

Coal 26,031 0 0 1,556 27,587

Arizona 918 0 0 30 948

Idaho 1,746 0 0 56 1,803

Montana 1,095 0 0 77 1,173

Nevada 4,935 0 0 348 5,283

New Mexico 508 0 0 16 525

South Dakota 6,966 0 0 687 7,653

Utah 0 0 0 0 0

 
A-12

Table A-4. Cont. 

2002 (tons)

Actual Post-2002 

Adjustments 

Future 

Controls Growth 2018 (tons)

Wyoming 9,111 0 0 294 9,404

Industrial Combustion - Distillate Oil 26,956 0 0 4,900 31,953

Arizona 1,117 0 0 285 1,402

California 249 346

Colorado 2,920 0 0 744 3,665

Idaho 90 0 0 23 113

Montana 1,450 0 0 219 1,670

Nevada 7,301 0 0 1,104 8,404

New Mexico 878 0 0 224 1,102

North Dakota 3,068 0 0 194 3,263

Oregon 1,453 0 0 347 1,800

South Dakota 1,769 0 0 112 1,881

Washington 3,200 0 0 765 3,965

Wyoming 3,461 0 0 882 4,343

Industrial Combustion - Residual Oil 11,132 0 0 13,382 25,445

Alaska 130 0 0 -108 22

Arizona 55 0 0 193 248

California 2,555 3,486

Idaho 7 0 0 25 32

Nevada 396 0 0 -251 145

New Mexico 2,913 0 0 10,194 13,106

North Dakota 254 0 0 190 444

Oregon 2,693 0 0 -2,244 449

South Dakota 752 0 0 564 1,317

Wyoming 1,377 0 0 4,819 6,196

Oil and Gas Production 3,828 0 0 0 110

Alaska 66 1

California 57 52

Colorado 260 9

Montana 227 8

Nevada 1 0

New Mexico 1,444 17

North Dakota 358 3

South Dakota 8 0

Utah 147 5

Wyoming 1,213 16

Tribes 48 1

Residential Heating - LPG 82 0 0 5 97

Alaska 0 0 0 0 0

Arizona 1 0 0 0 2

 
A-13

Table A-4. Cont. 

2002 (tons)

Actual Post-2002 

Adjustments 

Future 

Controls Growth 2018 (tons)

California 61 71

Colorado 4 0 0 1 5

Idaho 3 0 0 1 4

Montana 1 0 0 0 1

Nevada 1 0 0 0 1

New Mexico 2 0 0 0 3

North Dakota 2 0 0 0 2

Oregon 1 0 0 0 1

South Dakota 2 0 0 0 2

Utah 1 0 0 0 1

Washington 2 0 0 0 3

Wyoming 1 0 0 1 1

Tribes 0 0 0 0 0

Residential Heating - Natural Gas 296 0 0 67 379

Alaska 5 0 0 1 6

Arizona 11 0 0 6 17

California 145 162

Colorado 35 0 0 20 54

Idaho 6 0 0 4 10

Montana 6 0 0 3 9

Nevada 9 0 0 5 14

New Mexico 11 0 0 6 17

North Dakota 3 0 0 0 4

Oregon 12 0 0 2 14

South Dakota 4 0 0 0 4

Utah 25 0 0 13 38

Washington 22 0 0 4 26

Wyoming 4 0 0 2 6

Woodstoves and Fireplaces 1,931 0 0 56 2,011

Alaska 24 0 0 1 25

Arizona 28 0 0 1 29

California 550 574

Colorado 177 0 0 8 185

Idaho 26 0 0 1 27

Montana 42 0 0 2 44

Nevada 11 0 0 1 11

New Mexico 22 0 0 1 23

North Dakota 28 0 0 0 28

Oregon 616 0 0 25 642

South Dakota 33 0 0 0 33

 
A-14

Table A-4. Cont. 

2002 (tons)

Actual Post-2002 

Adjustments 

Future 

Controls Growth 2018 (tons)

Utah 23 0 0 0 24

Washington 332 0 0 1 346

Wyoming 20 0 0 14 21

Tribes 0 0 0 1 0

OTHER 24,633 0 0 2,034 27,051

Alaska 2,828 0 0 328 3,156

Arizona 538 0 0 215 753

California 4,625 5,010

Colorado 1,104 0 0 211 1,314

Idaho 928 0 0 -318 610

Montana 443 0 0 48 491

Nevada 286 0 0 33 319

New Mexico 714 0 0 172 886

North Dakota 2,031 0 0 79 2,110

Oregon 5,149 0 0 357 5,506

South Dakota 628 0 0 144 773

Utah 1,635 0 0 129 1,764

Washington 2,879 0 0 417 3,296

Wyoming 843 0 0 219 1,062

Tribes 1 0 0 0 1

CENRAP Area Sources 321,088 0 0 0 0

Arkansas 27,887 

Iowa 3,286 

Kansas 14,023 

Louisiana 83,292 

Minnesota 15,558 

Missouri 48,183 

Nebraska 7,744 

Oklahoma 11,731 

Texas 109,383 

Tribes 1 
A-15

Table A-5. Itemization of Changes Projected to Area Sources Emissions Between 

2002 and 2018 (PM10), Version 1 

2002 (tons)

Actual Post-2002 

Adjustments 

Future 

Controls Growth 2018 (tons)

WRAP Area Sources (all categories) 1,861,810 -3,168 -705 339,110 2,208,103

Agriculture Production - Crops 812,343 0 -705 27,432 838,372

Arizona 17,088 0 -705 0 16,383

California 36,186 35,489

Colorado 90,207 0 0 3,260 93,467

Idaho 15,429 0 0 558 15,986

Montana 89,485 0 0 3,234 92,718

Nevada 559 0 0 20 579

New Mexico 17,158 0 0 620 17,778

North Dakota 235,684 0 0 8,517 244,201

Oregon 32,379 0 0 1,170 33,549

South Dakota 156,837 0 0 5,668 162,505

Utah 20,626 0 0 745 21,372

Washington 95,762 0 0 3,461 99,222

Wyoming 3,034 0 0 110 3,144

Tribes 1,910 0 0 69 1,979

Commercial/Institutional Heating - 

Natural Gas 2,139 -896 0 22 152

Alaska 58 -54 0 1 5

Arizona 86 -80 0 3 8

California 1,177 64

Colorado 224 -209 0 7 22

Montana 50 -47 0 1 5

Nevada 75 -70 0 2 7

New Mexico 47 -43 0 1 5

North Dakota 40 -37 0 0 3

Oregon 99 -93 0 2 8

South Dakota 37 -34 0 0 3

Washington 208 -194 0 4 18

Wyoming 37 -35 0 1 4

Tribes 1 -1 0 0 0

Construction 669,647 0 0 239,890 922,721

Alaska 5,326 0 0 4,099 9,425

Arizona 61,695 0 0 32,336 94,032

California 70,655 83,839

Colorado 52,168 0 0 23,649 75,817

Idaho 27,050 0 0 9,079 36,130

Montana 27,913 0 0 8,453 36,366

Nevada 52,443 0 0 26,483 78,925
A-16

Table A-5. Cont. 

2002 (tons)

Actual Post-2002 

Adjustments 

Future 

Controls Growth 2018 (tons)

New Mexico 76,802 0 0 28,797 105,599

North Dakota 20,571 0 0 4,284 24,855

Oregon 93,264 0 0 39,918 133,182

South Dakota 10,984 0 0 3,036 14,020

Utah 6,478 0 0 2,652 9,130

Washington 140,333 0 0 52,271 192,604

Wyoming 23,964 0 0 4,831 28,795

Tribes 2 0 0 0 2

Food and Kindred Products 23,256 0 0 3,366 26,603

Alaska 228 0 0 96 325

Arizona 1,973 0 0 596 2,569

California 12,288 12,269

Colorado 1,843 0 0 359 2,202

Idaho 431 0 0 199 630

Montana 365 0 0 76 441

Nevada 109 0 0 27 136

New Mexico 619 0 0 152 771

North Dakota 180 0 0 39 219

Oregon 1,746 0 0 735 2,481

South Dakota 252 0 0 28 280

Utah 605 0 0 153 758

Washington 2,411 0 0 873 3,284

Wyoming 205 0 0 32 237

Mining and Quarrying 146,311 0 0 45,522 191,970

Alaska 3,644 0 0 1,822 5,466

Arizona 9,923 0 0 2,173 12,096

California 1,377 1,514

Montana 29,250 0 0 8,420 37,670

Nevada 12,142 0 0 2,548 14,691

New Mexico 8,745 0 0 3,539 12,284

North Dakota 27,683 0 0 10,905 38,588

Oregon 6,246 0 0 3,123 9,370

South Dakota 34,473 0 0 8,618 43,091

Washington 6,767 0 0 2,236 9,003

Wyoming 5,999 0 0 2,118 8,117

Tribes 62 0 0 18 80

Oil and Gas Production 189 0 0 0 177

California 189 177

Open Burning - Land Clearing Debris 15,723 0 0 5,804 21,527

Arizona 2,189 0 0 1,272 3,461
A-17

Table A-5. Cont. 

2002 (tons)

Actual Post-2002 

Adjustments 

Future 

Controls Growth 2018 (tons)

Montana 888 0 0 143 1,031

Nevada 215 0 0 148 363

New Mexico 1,159 0 0 336 1,496

North Dakota 37 0 0 3 39

Oregon 1,834 0 0 651 2,485

South Dakota 205 0 0 25 230

Washington 8,805 0 0 3,190 11,995

Wyoming 392 0 0 36 428

Open Burning - Residential Household 

Waste 24,803 0 0 8,521 33,324

Alaska 664 0 0 236 899

Arizona 2,773 0 0 1,612 4,385

Idaho 5,819 0 0 1,953 7,772

Montana 1,235 0 0 199 1,434

Nevada 367 0 0 253 620

New Mexico 1,936 0 0 562 2,498

North Dakota 884 0 0 64 948

Oregon 3,501 0 0 1,243 4,744

South Dakota 1,115 0 0 136 1,250

Utah 131 0 0 52 183

Washington 6,012 0 0 2,178 8,190

Wyoming 367 0 0 34 401

Residential Heating - Natural Gas 3,216 -1,249 0 41 275

Alaska 61 -57 0 1 5

Arizona 134 -125 0 5 14

California 1,876 143

Colorado 438 -408 0 17 47

Montana 76 -71 0 3 8

Nevada 90 -84 0 3 9

New Mexico 136 -127 0 5 15

North Dakota 42 -39 0 0 3

South Dakota 48 -45 0 0 4

Washington 273 -254 0 4 22

Wyoming 41 -38 0 2 4

Tribes 1 -1 0 0 0

Woodstoves and Fireplaces 130,820 0 0 3,644 136,235

Alaska 1,746 0 0 72 1,818

Arizona 2,097 0 0 91 2,188

California 41,298 43,069

Colorado 11,388 0 0 495 11,883
A-18

Table A-5. Cont. 

2002 (tons)

Actual Post-2002 

Adjustments 

Future 

Controls Growth 2018 (tons)

Idaho 2,263 0 0 98 2,362

Montana 3,025 0 0 180 3,206

Nevada 640 0 0 38 678

New Mexico 1,565 0 0 68 1,633

North Dakota 2,000 0 0 0 2,000

Oregon 37,628 0 0 1,546 39,175

South Dakota 2,361 0 0 0 2,361

Utah 1,575 0 0 94 0

Washington 20,854 0 0 857 1,669

Wyoming 2,378 0 0 103 21,711

Tribes 0 0 0 0 2,482

OTHER 33,364 -1,024 0 4,869 36,746

Alaska 3,316 -148 0 421 3,590

Arizona 2,006 -38 0 779 2,747

California 14,887 14,424

Colorado 1,606 -32 0 225 1,799

Idaho 0 0 0 -3,233 1

Montana 920 -36 0 3,364 1,014

Nevada 1,369 -19 0 397 1,747

New Mexico 1,214 -125 0 1,122 2,211

North Dakota 502 -120 0 34 415

Oregon 761 -12 0 182 931

South Dakota 2,729 -36 0 312 3,005

Utah 840 -22 0 349 1,167

Washington 2,117 -236 0 399 2,279

Wyoming 1,094 -198 0 519 1,415

Tribes 2 -2 0 0 0

CENRAP Area Sources 1,849,378 0 0 0 0

Arkansas 74,599 

Iowa 55,303 

Kansas 161,963 

Louisiana 95,076 

Minnesota 304,452 

Missouri 93,331 

Nebraska 36,332 

Oklahoma 121,772 

Texas 906,497 

Tribes 52 
APPENDIX B 

ERRATA
B-1

Potential Changes to Version 1 of the WRAP 2018 Base Case 

Emissions Inventory 

• Wyoming: Wyoming’s point source inventory was revised on November 18, 2005. This 

revision was not included in the 2018 base case inventory since it came too late in the 

process. 

• Confederated Tribes of the Yakama Nation: Point source emissions for Yakama Forest 

Products were added to the 2002 inventory for this Native American Reservation after the 

2002 emissions inventory had been incorporated into the 2018 base case calculations. 

Thus, emissions were not projected for this point source. 

• North Dakota: Emissions for three new post-2002 facilities could not be included in the 

2018 base case inventory because only hourly emissions (and not annual emissions) were 

provided: 

⎯ North Border #5 Compressor Station 

⎯ Manning Compressor Station 

⎯ Silurian Compressor Station 

• Arapahoe Tribe of the Wind River Reservation: The tribal environmental agency 

indicated operation of a new post-2002 facility, South Pavilion Compressor Station, 

although annual emissions were not provided so this source could not be included in the 

2018 base case inventory. 

• Oregon: VOC emission reductions for two wood products facilities (Boise Cascade in 

White City and La Grande) were not included in the 2018 base case projections due to 

problems matching the SCCs in the 2002 inventory and information received from the 

State. If these problems were resolved, the VOC reductions (totaling approximately 273 

tons) could be applied to the 2018 base case inventory. 

• Wyoming and Washington: Emissions for six new post-2002 facilities could not be 

included in the 2018 base case files (NIF and IDA) files due to missing county FIPS): 

⎯ Burlington Resources, Big Horn Wells (WY, ID 00012) 

⎯ Chevron USA Table Rock Field (WY) 

⎯ Chevron USA Whitney Canyon, Carter Creek (WY) 

⎯ ExxonMobil Corporation, Black Canyon (WY) 

⎯ Sierra Pacific Industries (WA, ID 1118) 

⎯ Olympic Panel Products (WA, ID 2100284)
B-1

• Investigate potentially overestimated PM10 from construction/wind erosion (SCC 

2311000100) in Washington and Oregon.