# 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, 2006WRAP 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 Contro l 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 ................................................................................................... 6-9WRAP 2018 Base Case Inventory Version 1, January 2006 

### ii 

# 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 Ca se Inventory (Version 1) Summaries

APPENDIX B: Errata

Tables Page

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

2-2 Correction Ratios for Combusti on 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 Petr oleum Refinery Initiative ........ 3-5 4-1 Future Electricity Generation Analysis – Coal-Fired EGUs............................................ 4-5 4-2 Future Electricity Generation Anal ysis – Natural Gas-Fired EGUs................................ 4-5

4-3 Coal-Fired EGUs that are Ne w (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 Replaceme nt Reduction Factors............................................................. 5-4 5-3 Information Used to Develop Retireme nt 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 SO 2 

### Milestone Report, and with 2002 SO 2 

### Emissions Less than 100 Tons.......................................................... 6-8

7-1 2002 and 2018 Base Case – Point Source Emi ssions by State and Tribe, Version 1 ...... 7-2WRAP 2018 Base Case Inventory Version 1, January 2006 

### iii 

# 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 Emissi ons by State and Tribe, Version 1....... 7-8

7-4 2002 and 2018 Base Case – Area Source NO x 

### Emissions by Sector, Version 1........... 7-10

7-5 2002 and 2018 Base Case – Area Source SO 2 

### Emissions by Sector, Version 1 ........... 7-14

7-6 2002 and 2018 Base Case – Area Source PM 10 

### 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 NO x 

### Emissions, Version 1................... 7-23

7-2 WRAP Point and Area Source 2002 and 2018 SO 2 

### Emissions, Version 1.................... 7-24

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

7-4 WRAP Point and Area Source 2002 and 2018 PM 10 

### Emissions, Version 1.................. 7-26WRAP 2018 Base Case Inventory Version 1, January 2006 

### iv 

# 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 Inventor y 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 GroupWRAP 2018 Base Case Inventory Version 1, January 2006 

### v FCCU fluidized catalytic cracking unit

GF growth factor

HI heat input

IAS Integrated Assessment System

IDA Inventory Data Analyzer

lbs pounds

MACT maximum achievab le 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

NH 3 

### ammonia

NIF National Emissions Inventory Format

NO x 

### nitrogen oxides

NSCR non-selective catalytic reduction

NSPS New Source Performance Standards

NSR New Source Review

PM particulate matter

PM 2.5 

### particulate matter less than 2.5 mi crometers in aerodynamic diameter

PM 10 

### particulate matter less than 10 mi crometers in aerodynamic diameterWRAP 2018 Base Case Inventory Version 1, January 2006 

### vi PSD Prevention of Significant Deterioration

RCO regenerative catalytic oxidation

RHR Regional Haze Rule

RICE reciprocating inte rnal 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 Oper ator Kernel Emissions

SO 2 

### 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 micrometerWRAP 2018 Base Case Inventory Version 1, January 2006 

### vii 

# 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 princi ples of Federal Indian law, and as provided by the Clean Air Act §301(d) and the Tribal Au thority 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 a nd receive delegation of federal authority to implement CAA programs, including visibili ty 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 reas onable 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 stat utory and regulatory requirements.

3. The Regional Haze Rule expressly provides that tribal visibility programs are “not dependent on the strategies selected by the st ate 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 Impl ementation Plan (FIP) within reasonable timeframes to protect air quali ty 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 wh ere necessary (See, e.g. 63 Fed. Reg. 7263-64).

It is our hope that the findings and recomme ndations of this report will prove useful to tribes, whether they choose to submit full or par tial 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 sove reignty and autonomy as reflecte d in the above framework. Any inconsistency with this framework is strict ly inadvertent and not an attempt to impose requirements on tribes which are not present under existing law.WRAP 2018 Base Case Inventory Version 1, January 2006 

### 1-1 

# 1.0 INTRODUCTION

The Western Regional Air Partnership (WRA P) 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 Foru m (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, ENVI RON International Corporation and Alpine Geophysics, LLC, for the WRAP SSJF under Contract No. 30204-101 with the Western Governors’ Association (WGA). Th is 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-oi l 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 ar ea sources (non-oil and gas) emissions inventory;

• Task 2: Control t echnology 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 th e data and methods use d, and results achieved for Task 1C (2018 base case) and Task 4 (Calif ornia inventories for 2018). Also, in order to provide a comprehensive set of em issions inventory summaries in this report, the results from Tasks 1A, 1B, and 3 are incorporated.

The specific objectives of the 2018 base cas e 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 agenci es; and stakeholders;WRAP 2018 Base Case Inventory Version 1, January 2006 

### 1-2 • Use information collected from the tribal, stat e, and local agencies, and stakeholders to the greatest extent possible;

• Provide a technically sound basis for developmen t of control strategies to be used in regional haze analyses;

• Establish a format that facilitates conversi on of results into vari ous formats including U.S. EPA’s National Emissions Inventory Format (NIF) Ve rsion 3.0 and Inventory Data Analyzer (IDA) format for use with the Sp arse 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 fo r 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 “a ttainment” year for visib ility 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 Mi ssion Indians of the Cabazon Reservation, the Coeur d’Alene Tribe of the Coeur d’Al ene Reservation, Confederated Tribes and Bands of the Yakama Nation, Confederated Tribes of the Colville Reservation, Confederated Tribes of the Umatilla Reservat ion, Fort Mojave Indian Tribe of Arizona, Gila River Indian Community of the Gila River Indian Re servation, La Posta Band of Diegueno Mission Indians of the La Posta Indi an Reservation, Navajo Nation, Pueblo of Laguna, Pueblo of Santa Ana, Salt River Pi ma-Maricopa Indian Co mmunity 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 L ac Tribe and the Leech Lake Band of Ojibwe).WRAP 2018 Base Case Inventory 

### 1-3 Version 1, January 2006Figure 1-1. WRAP and CENRAP States and Tribes Included in the WRAP2018 Base Case Emissions InventoryWRAP 2018 Base Case Inventory Version 1, January 2006 

### 1-4 The sources included in the 2018 base case inventory are point sources and area (nonpoint) stationary sources. Certain ar ea source categories that were not included in this project, but were dealt with in other WRAP projects and co ntracts include the following:

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

• Windblown dust (27014xxxxx, 27301xxxxx);

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

• Agricultural production-livestock (SCCs 2805xxxxxx).

Also, no nonroad mobile sources (e.g., commercia l 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 (NO x 

### ), sulfur dioxide (SO 2 

### ), volatile organic compounds (VOC), carbon monoxide (CO), particulate matter (PM) with an aerodynamic diameter of less than 10 micrometers (μm) (PM 10 

### ) and less than 2.5 μm (PM 2.5 

### ), and ammonia (NH 3 

### ).

The actual pollutants included in the 2018 base case inventory for a given point or area source category are dependent upon those polluta nts included in the 2002 WRAP inventory for that source. For example, if only PM 10 

### -Filterable and PM 2.5 

### -Filterable (and not PM 10 

### -Primary

and PM 2.5 

### -Primary) are included in the 2002 inventor y for a given source, then only those pollutants are included in the 2018 base case in ventory (i.e., no 2002 emi ssions 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 proj ect the WRAP 2002 emi ssions 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 sp readsheet for the WRAP tribes. The types of information used in each step are described as follows:

• 2002 Emissions Inventory. This informati on 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 Version 1, January 2006 

### 1-5 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 All Others EGUs Point Oil and Gas All Others Fuel Combustion Agricultural Sources All Others EGUs Point Oil and 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 Facilit ies, PM Adjustments

Oil and Gas Growth Factors All Others Fuel Combustion Agricultural Sources Area Source Oil and Gas Emissions CA Emissions Revised WRAP 2002 Point and 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 AdjustmentsWRAP 2018 Base Case Inventory Version 1, January 2006 

### 1-6 ⎯ 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 retire d in 2003 or 2004 and will not return to operation in the future

⎯ Other (i.e., ratios to correct certain PM 10 

### and PM 2.5 

### 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 regula tions 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 s cenarios that have yet to be determined.

• Growth Factors: SCC-specific growth factor s developed from EGAS projection factor model; special analysis of EGU growth relative to unit capacity threshold.

• Retirement and replacement rates: Eff ects of retirement estimated using annual retirement rates based on expected equipmen t lifetimes. Retired equipment replaced byWRAP 2018 Base Case Inventory Version 1, January 2006 

### 1-7 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 sour ces in the Grand Canyon Visibi lity Transport States (i.e., AZ, CA, CO, ID, NV, NM, OR, UT, a nd WY) whose 2002 facility-level SO 2 

### emissions are at least 100 tons/year.

An extensive data collection effort was c onducted to identify the information needs for the adjustments, control factors, growth factor s, 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 calcula ted, and results are described in detail in the remaining sections of this report.

Part of this WRAP 2018 pr ojection process included num erous telephone conferences with the WRAP SSJF Projections Workgroup, w ho provided input and feedback on proposed methods for various source sectors, especially electric generating units. A draft 2018 base case inventory was generated and distribu ted to all affected states and tribal entities for review. Based upon comments received, the 2018 base case was revi sed and is published in this report. The inventory spreadsheets were used to develop emissions inventory summaries and dist ribute to the WRAP states, tribes, and other st akeholders as Version 1. The re sults 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 modeli ng 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 adjustme nts that were made to the 2002 emissions inventory to reflect post-2002 conditions for point and area so urces. These include post2002 changes such as new facilities, retired f acilities, and PM emission factor corrections for natural gas combustion.

• Section 3.0 – Explanation of th e types of on-the-books contro ls (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 baseWRAP 2018 Base Case Inventory Version 1, January 2006 

### 1-8 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 grow th factors and rates used to project the 2002 inventory forward to 2018. This discussion also covers the details of how th e emission projections for California were developed and incorporat ed 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 tur nover of older equipment with new equipment emitting at (generally) BACT levels.

• Section 6.0 – Explanation of th e other information used to develop and report the 2018 base case inventory, includi ng 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 i nventory at the state and sector levels, including comparisons with the 2002 emissions inventory.

• Section 8.0 – Listing of refe rences 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 poten tial changes to Version 1 of the 2018 base case inventory.

Also, in addition to this repor t and its appendices, several se ts of electronic files have been delivered under the scope of this project; these include the following:

• Zipped spreadsheets containing the detailed ca lculations 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.xlsWRAP 2018 Base Case Inventory Version 1, January 2006 

### 1-9 ⎯ 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 cont rol factors provided by the California Air Resources Board: CA_growth_control_2018.xlsWRAP 2018 Base Case Inventory Version 1, January 2006 

### 2-1 

# 2.0 POST-2002 ADJUSTMENTS

To provide the basis for an accurate projecti ons inventory, adjustments were made to the WRAP 2002 point and area so urce inventory to reflect changes in sources and emissions that have occurred since the 2002. These adjustments had th e 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 va rious reasons, needed to be corrected from their 2002 levels (e.g., emissions reported to the U.S. EPA Clean Air Market ing Division [CAMD]

database but not included in the 2002 WRAP inve ntory, 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 existe nce is known, they could not be added to the projections due to lack of info rmation (e.g., hourly emissions instead of annual emissions, etc.). These included the North Border #5, Manning, S ilurian, Golva Compressor Stations in North Dakota; and, the South Pavilion Compressor St ation on the Wind River Reservation (Arapahoe Tribe, Wyoming).



## 2.2 PM/Combustion Emission Corrections

Table 2-2 lists the ratios devel oped and distributed by U.S. EPA to correct certain natural gas and liquefied petroleum gas combustion emissi on factors (Huntley, 2005). As it is currently understood, U.S. EPA will apply thes e ratios when finalizing the 2002 National Emissions Inventory (NEI), thus it was felt that the WR AP inventory should reflect this ch ange 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 inconsiste ncy with most 2002 state emission inventories.) These ratios were applied at th e SCC level to adjust the WRAP 2002 emissions prior to applyingWRAP 2018 Base Case Inventory Version 1, January 2006 

### 2-2 Table 2-1. Summary of New and Retire d Facilities, and Other Adjustments

Type of Adjustment a

Facility Name State or Tribe (County

FIPS) New Retire CAMD Add b 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 (0 87) 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) 9WRAP 2018 Base Case Inventory Version 1, January 2006 

### 2-3 Table 2-1. Cont.

Type of Adjustment a

Facility Name State or Tribe (County

FIPS) New Retire CAMD Add b 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 Syst ems 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) 9WRAP 2018 Base Case Inventory Version 1, January 2006 

### 2-4 Table 2-1. Cont.

Type of Adjustment a

Facility Name State or Tribe (County

FIPS) New Retire CAMD Add b 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 = NO x and SO 2 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 2006Table 2-2.Correction Ratios for Combustion Emission Factors, by SCCSCCSCC_DESCPM10-PRI ratioPM25-PRI ratio10100601 External Combustion Boilers: Electric Generation: Natural Gas: Boilers > 100 Million Btu/hr except Tangential 0.0684210.05657910100602 External Combustion Boilers: Electric Generation: Natural Gas: Boilers < 100 Million Btu/hr except Tangential 0.0684210.05657910100604 External Combustion Boilers: Electric Generation: Natural Gas: Tangentially Fired Units 0.068421 0.05657910100701 External Combustion Boilers: Electric Generation: Process Gas: Boilers > 100 Million Btu/hr 0.059770 0.05810810100702 External Combustion Boilers: Electric Generation: Process Gas: Boilers < 100 Million Btu/hr 0.059770 0.05810810101001 External Combustion Boilers: Electric Generation: Liquefied Petroleum Gas (LPG): Butane 0.068421 0.05657910101002 External Combustion Boilers: Electric Generation: Liquefied Petroleum Gas (LPG): Propane 0.068421 0.05657910101003External Combustion Boilers: Electric Generation: Liquefied Petroleum Gas (LPG): Butane/Propane Mixture:Specify Percent Butane in Comments0.068421 0.05657910200601 External Combustion Boilers: Industrial: Natural Gas: > 100 Million Btu/hr 0.068421 0.05657910200602 External Combustion Boilers: Industrial Natural Gas: 10-100 Million Btu/hr 0.068421 0.05657910200603 External Combustion Boilers: Industrial: Natural Gas: < 10 Million Btu/hr 0.068421 0.05657910200604 External Combustion Boilers: Industrial: Natural Gas: Cogeneration 0.068421 0.05657910200701 External Combustion Boilers: Industrial: Process Gas: Petroleum Refinery Gas 0.059770 0.04942510200704 External Combustion Boilers: Industrial: Process Gas: Blast Furnace Gas 0.060465 0.05000010200707 External Combustion Boilers: Industrial: Process Gas: Coke Oven Gas 0.052000 0.04831510201001 External Combustion Boilers: Industrial: Liquefied Petroleum Gas (LPG): Butane 0.068421 0.05657910201002 External Combustion Boilers: Industrial: Liquefied Petroleum Gas (LPG): Propane 0.068421 0.05657910201003External Combustion Boilers: Industrial: Liquefied Petroleum Gas (LPG): Butane/Propane Mixture: Specify PercentButane in Comments0.068421 0.05657910201401 External Combustion Boilers: Industrial: CO Boiler: Natural Gas 0.068421 0.05657910201402 External Combustion Boilers: Industrial: CO Boiler: Process Gas 0.068421 0.05657910300601 External Combustion Boilers: Commercial/Institutional: Natural Gas: > 100 Million Btu/hr 0.068421 0.05657910300602 External Combustion Boilers: Commercial/Institutional: Natural Gas: 10-100 Million Btu/hr 0.068421 0.05657910300603 External Combustion Boilers: Commercial/Institutional: Natural Gas: < 10 Million Btu/hr 0.068421 0.05657910301001 External Combustion Boilers: Commercial/Institutional: Liquefied Petroleum Gas (LPG): Butane 0.068421 0.05657910301002 External Combustion Boilers: Commercial/Institutional: Liquefied Petroleum Gas (LPG): Propane 0.068421 0.05657910301003External Combustion Boilers: Commercial/Institutional: Liquefied Petroleum Gas (LPG): Butane/Propane Mixture:Specify Percent Butane in Comments0.068421 0.05657910500106 External Combustion Boilers: Space Heaters: Industrial: Natural Gas 0.068421 0.05657910500110 External Combustion Boilers: Space Heaters: Industrial: Liquefied Petroleum Gas (LPG) 0.068421 0.05657910500206 External Combustion Boilers:Space Heaters: Commercial/Institutional: Natural Gas 0.068421 0.056579WRAP 2018 Base Case Inventory 

### 2-6 Version 1, January 2006Table 2-2. Cont.SCCSCC_DESCPM10-PRI ratioPM25-PRI ratio10500210 External Combustion Boilers: Space Heaters: Commercial/Institutional: Liquefied Petroleum Gas (LPG) 0.0684210.05657920100201 Internal Combustion Engines: Electric Generation: Natural Gas: Turbine 0.046269 0.02835820200201 Internal Combustion Engines: Industrial: Natural Gas: Turbine 0.046269 0.02835820200203 Internal Combustion Engines: Industrial: Natural Gas: Turbine: Cogeneration 0.046269 0.02835820300202 Internal Combustion Engines: Commercial/Institutional: Natural Gas: Turbine 0.046269 0.02835820400301 Internal Combustion Engines: Engine Testing: Turbine: Natural Gas 0.046269 0.02835827300320Internal Combustion Engines: Off-highway LPG-fueled Engines: Industrial Equipment: Industrial Fork Lift:Liquefied Petroleum Gas (LPG)0.068421 0.05657930290005Industrial Processes: Food and Agriculture: Fuel Fired Equipment: Liquefied Petroleum Gas (LPG): ProcessHeaters0.068421 0.05657930500209 Industrial Processes: Mineral Products: Asphalt Concrete: Asphalt Heater: LPG 0.068421 0.05657930590005 Industrial Processes: Mineral Products: Fuel Fired Equipment: Liquefied Petroleum Gas (LPG): Process Heaters 0.0684210.05657930600105 Industrial Processes: Petroleum Industry: Process Heaters: Natural Gas-fired 0.068421 0.05657930600107 Industrial Processes: Petroleum Industry: Process Heaters: LPG-fired 0.068421 0.05657930890004Industrial Processes: Rubber and Miscellaneous Plastics Products: Fuel Fired Equipment: Liquefied Petroleum Gas(LPG): Process Heaters0.068421 0.05657931000404 Industrial Processes: Oil and Gas Production: Process Heaters: Natural Gas 0.068421 0.05657931000414 Industrial Processes: Oil and Gas Production: Process Heaters: Natural Gas: Steam Generators 0.068421 0.05657939000689 Industrial Processes: In-process Fuel Use: Natural Gas: General 0.068421 0.05657939901001 Industrial Processes: Miscellaneous Manufacturing Industries: ProcessHeater/Furnace: LPG0.068421 0.05657940201004Petroleum and Solvent Evaporation: Surface Coating Operations: Coating Oven Heater: Liquefied Petroleum Gas(LPG)0.068421 0.0565792101006000 Stationary Source Fuel Combustion: Electric Utility: Natural Gas: Total: Boilers and IC Engines 0.068421 0.0565792101006001 Stationary Source Fuel Combustion: Electric Utility: Natural Gas: All Boiler Types 0.068421 0.0565792101006002 Stationary Source Fuel Combustion: Electric Utility: Natural Gas: All IC Engine Types 0.068421 0.0565792101007000 Stationary Source Fuel Combustion: Electric Utility: Liquefied Petroleum Gas (LPG): Total: All Boiler Types 0.0684210.0565792102006000 Stationary Source Fuel Combustion: Industrial: Natural Gas: Total: Boilers and IC Engines 0.068421 0.0565792102006001 Stationary Source Fuel Combustion: Industrial: Natural Gas: All Boiler Types 0.068421 0.0565792102006002 Stationary Source Fuel Combustion: Industrial: Natural Gas: All IC Engine Types 0.068421 0.0565792102007000 Stationary Source Fuel Combustion: Industrial: Liquefied Petroleum Gas (LPG): Total: All Boiler Types 0.068421 0.0565792103006000 Stationary Source Fuel Combustion: Commercial/Institutional: Natural Gas: Total: Boilers and IC Engines 0.068421 0.056579WRAP 2018 Base Case Inventory 

### 2-7 Version 1, January 2006Table 2-2. Cont.SCCSCC_DESCPM10-PRI ratioPM25-PRI ratio2103007000Stationary Source Fuel Combustion: Commercial/Institutional: Liquefied Petroleum Gas (LPG): Total: AllCombustor Types0.068421 0.0565792103007005 Stationary Source Fuel Combustion: Commercial/Institutional: Liquefied Petroleum Gas (LPG): All Boiler Types 0.068421 0.0565792103007010Stationary Source Fuel Combustion: Commercial/Institutional: Liquefied Petroleum Gas (LPG): Asphalt KettleHeaters0.068421 0.0565792104006000 Stationary Source Fuel Combustion: Residential: Natural Gas: Total: All Combustor Types 0.068421 0.0565792104006010 Stationary SourceFuel Combustion: Residential: Natural Gas:Residential Furnaces0.068421 0.0565792104007000 Stationary Source Fuel Combustion: Residential: Liquefied Petroleum Gas (LPG): Total: All Combustor Types 0.068421 0.0565792199007000Stationary Source Fuel Combustion: Total Area Source Fuel Combustion: Liquefied Petroleum Gas (LPG): Total:All Boiler Types0.068421 0.05657920100202 Internal Combustion Engines: Electric Generation: Natural Gas: Reciprocating 0.046000 0.05700020200202 Internal Combustion Engines: Industrial: Natural Gas: Reciprocating 0.046000 0.05700020200204 Internal Combustion Engines: Industrial: Natural Gas: Reciprocating: Cogeneration 0.046000 0.05700020200209 Internal Combustion Engines: Industrial: Natural Gas: Turbine: Exhaust 0.046000 0.05700020200252 Internal Combustion Engines: Industrial: Natural Gas: 2-cycle Lean Burn 0.046000 0.05700020200253 Internal Combustion Engines: Industrial: Natural Gas: 4-cycle Rich Burn 0.046000 0.05700020200254 Internal Combustion Engines: Industrial: Natural Gas: 4-cycle Lean Burn 0.046000 0.05700020200255 Internal Combustion Engines: Industrial: Natural Gas: 2-cycle Clean Burn 0.046000 0.05700020200256 Internal Combustion Engines: Industrial: Natural Gas: 4-cycle Clean Burn 0.046000 0.05700020300201 Internal Combustion Engines: Commercial/Institutional: Natural Gas: Reciprocating 0.046000 0.05700020300203 Internal Combustion Engines: Commercial/Institutional: Natural Gas: Turbine: Cogeneration 0.046000 0.05700020300204 Internal Combustion Engines: Commercial/Institutional: Natural Gas: Cogeneration 0.046000 0.05700020300207 Internal Combustion Engines: Commercial/Institutional: Natural Gas: Reciprocating: Exhaust 0.046000 0.05700020300209 Internal Combustion Engines: Commercial/Institutional: Natural Gas: Turbine: Exhaust 0.046000 0.05700020301001 Internal Combustion Engines: Commercial/Institutional: Liquified Petroleum Gas (LPG): Propane: Reciprocating 0.0460000.05700020301002 Internal Combustion Engines: Commercial/Institutional: Liquified Petroleum Gas (LPG): Butane: Reciprocating 0.046000 0.05700030290003 Industrial Processes: Food and Agriculture: Fuel Fired Equipment: Natural Gas: Process Heaters 0.046000 0.05700030590003 Industrial Processes: Mineral Products: Fuel Fired Equipment: Natural Gas: Process Heaters 0.068000 0.05700030600104 Industrial Processes: Petroleum Industry: Process Heaters: Gas-fired 0.068000 0.05700030600106 Industrial Processes: Petroleum Industry: Process Heaters: Process Gas-fired 0.068000 0.057000Source: Huntley, 2005WRAP 2018 Base Case Inventory Version 1, January 2006 

### 2-8 other factors in subsequent step s. Most of the ratios affect point sources (8-digit SCCs), although some area sources (10-digit SCCs) are affect ed as well. As the table shows, the impacts are significant, ranging from 92.3 to 95.4 percent decrease in PM 10 

### -Primary and 94.2 to 97.2 percent decrease in PM 2.5 

### -Primary. (Although they are not show n on this table, U.S. EPA also recommended some PM-Condensable ratios).

All of the adjustments shown on Tables 2-1 a nd 2-2 were applied to the 2002 inventory to achieve an intermediate inventory called “bas eline planning inventory.” This intermediate inventory was used to check the impact of the adjustments made for reasonableness and quality assurance. The baseline planni ng inventory was the starting point for estimating the future year projections.WRAP 2018 Base Case Inventory Version 1, January 2006 

### 3-1 

# 3.0 POST-2002 CONTROL FACTORS

Post-2002 control factors were calculated to reflect impact s 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) resul ting 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 Implem entation Plan (SIP) implementation and other state programs to control ai r pollution, such as the Denve r 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 fo r improving air quality, such as the Denver Metro Emissions Reduction Project.

In some cases, the effect of these post-2002 cont rols did not take the form of a factor, but rather an emission limit, shutdown of equipmen t, 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 manuf acturers of plywood, panelboard, medium density fiberboard (MDF), and oriented strand bo ard. In 1988, the U.S. EPA began investigating the industry for a suspected nati onwide pattern of noncompliance with the PSD regulations under the NSR provisions of the Clean Air Act and stat e rules. Within the WRAP region, settlements were reached with Willamette Industries ( 2000) and Boise Cascade Corporation (2002) 1 

### . The

1 http://www.epa.gov/complia nce/resources/cases/civ il/caa/wood/index.htmlWRAP 2018 Base Case Inventory 

### 3-2 Version 1, January 2006Table 3-1. Summary of Post-2002 Point and Area Source Control ImpactsPlant NameState or Tribe(County FIPS)Type of Control Impact and ExplanationBritish Petroleum – Multiple Facilities (BandamiDevelopment, Central Compressor Plant, CentralGas Facility, Central Power Station, EndicottProduction Facility, Flow Station (#1, #2, #3),Gathering Center (#1, #2, #3), Lisburne ProductionCenter, Milne Point Production Facility, NorthstarProduction Facility, Seawater Injection Plant East,Seawater Treatment Plant, PBU)AK (185)ConocoPhillips – Multiple Facilities (CentralProduction Facility (#1, #2, #3), Kaparuk SeawaterTreatment Plant, Alpine Central ProcessingFacility)AK (185)Enforceable Agreement: Limits/reduces sulfur content in diesel fuel used at stationarysources to 15 ppm or less before 2018.TEP – Springerville AZ (001) Consent Decree: Plant-wide NOxand SO2cap allows continued operation of 2 existingEGUs and construction of 1 new EGUs. Cap with 4 EGUs = 10,800 tons SOxand 9,600 tonsNOxby 12/31/09.Agricultural Tillage (SCC 280100003) AZ (027) Yuma County PM10SIP: Reduction of 705 tons of PM10due to implementation ofagricultural best management practices (BMPs).Xcel – Comanche CO (101) Voluntary Agreement: This agreement allows construction of new EGU and requires NOxreductions of 25% and SO2reductions of 65% by July 09.Xcel:Arapahoe #1, #2, #3Cherokee #2, #3, #4Valmont #5CO (031)CO (001)CO (013)Denver Metro Emissions Reduction Project: Agreement sets SO2emission reduction targetfor all plants combined (10,500 tons/year), and stipulates Arapahoe #1 and #2 to be shutdown (which occurred 12/31/02). Reductionsrealized in 2003 with new lime sprayers atCherokee #3 and #4 and Valmont #5. Increasedscrubber efficiency at Arapahoe #3 andCherokee #2.Tri State – Craig #1, #2 CO (081) Visibility SIP: Agreement requires fabric filters to be installed, scrubbers to be upgraded,NOxreduced through over-fire air upgrades. All by 12/31/04. (Reductions were incorporatedthrough use of 2004 CAMD data for basis of 2018 base case projection.)Rocky Mountain Steel Mill CO (101) Consent Decree: In effectbeginning 2005, includes shutdown of electric arc furnace #3 andmodification of electric arc furnace #4. Newemission limits (i.e., reductions over 2002emissions) as provided by CDPHE were used for 2018 base case projections.Condensate tanks at oil and gas wells andproduction facilities, and natural gas compressorand drip stations.CO (various) Denver Early Action Compact: VOC reduction of 47.5% across all sources located inDenver, Jefferson, Douglas, Broomfield, Boulder, Adams, Arapahoe, Weld, Larimer,Morgan, and Elbert counties by 2007.APS – Four Corners Power Plant Navajo Nation Voluntary Agreement: Post-2002 emission reductions for SO2and NOxare reflected in the2004 CAMD data, and used as basis for 2018 base case projection.WRAP 2018 Base Case Inventory 

### 3-3 Version 1, January 2006Table 3-1. Cont.Plant NameState (CountyFIPS)Type of Control Impact and ExplanationSCE – Mohave #1, #2 NV (003) Consent Decree: Limits SO2to 0.15 lb/MMBtu. Heat input limit = 73,925,640 MMBtu/yearfor each unit. Plant limits for 2 EGUs (per SCE and NDEP) = 19,494 tons NOxand 8,700tons SO2by 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 by 2004 include 64% NOxdecrease and 40% SO2decrease from catalytic cracking units (SCC 30600201) and 59%NOxdecrease from process heaters fired with process gas (SCC 30600106). Actualreductions provided by Navajo Refining Co.APS – San Juan Generating Station NM (045) Consent Decree: Requires reductions to PM, SO2, NOx, and Hg beginning as soon asOctober 2007 (Unit 4); April 2008 (Unit 3);October 2008 (Unit 1); and March 2009 (Unit2). Requires ultra low NOxburner for NOx(35% reduction); electrostatic precipitator plusfabric filters for PM (70% reduction); SO2control efficiency from 83-90% (i.e., 40%increase over currentlevels of control).Unnamed Power Plant ND Consent Decree:State is currently negotiating terms of CD with an unnamed power plant.Tesoro (BP Amoco) – Mandan Refinery ND (059) Refinery Initiative/Consent Decree: Reductions effective by 2005 include 82% NOxdecrease from process heaters fired with gas (SCC 30600104). Actual reductions providedby 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 wells. All SO2and otheremission from tail gas incinerator are now zero.Archer Daniels Midland – Corn Processing ND (067) Consent Decree: Reductions of 97 tons/year VOC, 10 tons/year NOx, and 20 tons/year PM10effective by April 2004.Boise Cascade – Medford and White City PlantsaOR (029) Wood Products Initiative/Consent Decree: Requires 95% VOC reduction in dryers frominstallation of regenerative thermal oxidizers (RTOs).Boise Cascade – Elgin and La Grande PlantsaOR (061) Wood Products Initiative/Consent Decree: Requires 95% VOC reduction in dryers.Regenerative thermal oxidizers (RTOs) installed in 2003.TransAlta – Centralia Power Plant WA (041) Consent Decree: Emission limits of 10,000 tons/year SO2(12 month rolling average); 0.30-0.35 lb/mmBTU NOx; 0.010 g/dscf PM; 200 ppm CO (per calendar year average). Alleffective 12/31/02.aActual reductions not taken at White City and La Grande plants due to ambiguity betweenSCCs in inventory database and as indicated by Oregon DEQ. These reductions totalapproximately 273 tons in 2004, and couldbe taken if 2018 base case is revised.WRAP 2018 Base Case Inventory Version 1, January 2006 

### 3- 4 

### Willamette facilities affected within the WRAP states were located in Bend (now closed), Eugene, Foster, Springfield, and Albany, Oregon. Th e Boise Cascade facilitie s affected with the WRAP states were Emmett, Idaho (now closed); Kettle Falls, Washington; and, Island City (La Grande), Elgin, Medford, and White City, Oreg on. In general, the settlements with both companies required significant VOC reductions (i.e., 90 to 95 percent), while minimizing NO x 

### and CO emissions. For the most part, VOC reduc tions were to be achieved through regenerative catalytic oxidation (RCO) or rege nerative 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 Ca scade 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 applie d 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 i nventory, 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 na tion’s petroleum refineries. Since 2000, U.S. EPA has entered into 17 settlements with U.S. compan ies that refine over 75 percent of the nation’s petroleum 2 

### . The settlements focus on four ma in areas of the Clean Air Act (CAA):

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

• New Source Performance Standards (NSPS) (aff ecting 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/reso urces/cases/civil/caa/oil/index.htmlWRAP 2018 Base Case Inventory Version 1, January 2006 

### 3- 5 

### 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 determ ine the types of controls, emission limits, applicable equipment, and d eadline 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 m eets NSPS requirements, and other types of programmatic approaches. As a result, the sp ecific mass reductions expected (e.g., mainly NO x 

### , SO 2 

### , and PM) are not provided in the CD, or have ye t 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 (Navaj o Refining) Artesia Refinery; these are included in Table 3- 1 (above).

Table 3-2. Refineries in W RAP States Subject to the Na tional Petroleum Refinery Initiative

State EPA Region Refinery CO 8 Conoco (Suncor Energy) Refinery (Denver) CO 8 Valero (Colorado Re fining) Refinery (Denver) MT 8 Exxon Mobile (Billings) MT 8 Montana Refining (Great Falls) MT 8 Conoco Refinery (Billings) MT 8 Centex Harvest States (Laurel) N D 8 BP Amoco Mandan Refinery N M 6 Artesia Refinery N M 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 Cont rol 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 (MAC T) impacts were assessed by collecting all readily available information on the emission imp acts of the rules. Emissions information was gathered from rulemaking preambles and U. S. EPA Fact Sheets supporting each rule, andWRAP 2018 Base Case Inventory Version 1, January 2006 

### 3- 6 

### emissions analyses were obtained for some rule s 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 signifi cant effort involving the determin ation of the current level of MACT compliance, followed by a unit le vel emissions and control analysis;

• While MACT reductions in tons of pollutant are available from U.S. EPA rulemaking preambles, Federal Register notices, and F act 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 ac tual reduction at a given plant may be 0 percent or 99 percent); and

• Some VOC controls will cause increases in NO x 

### and SO 2 

### emissions (e.g., thermal oxidizers will increase NO x 

### emissions and, if there is sulfur in the exhaust stream as in pulp mills, SO 2 

### 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 NO x 

### , SO 2 

### , VOC, and PM 10 

### in the 2002 inventory were examined for applicable NESH APs 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 industri al boilers), or the compliance date for the rule has already passed (e.g., oil a nd gas production). The NESHAPs determined to have the potentially greatest im pact on high-emitting SCCs in the WRAP region were as follows:

• Reciprocating internal co mbustion engines (RICE)

• Petroleum bulk stations and terminals

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

• Primary copper smeltersWRAP 2018 Base Case Inventory Version 1, January 2006 

### 3- 7 

### Secondly, a subjective determination was made as to the NESHAPs that were likely to have the largest impact on CAPs in the WR AP 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 pro cess 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 st andards from above, available information from federal rules and preambles related to national tonnage reductions and/or percentage reduction from MACT implementation was compile d. 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 informati on on specific pollutant emission reductions at individual sources or geographi c 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 we re divided by national tons/year emissions from the 2002 NEI for th e MACTs covering RICE, plywood and composite wood products, industrial/commercia l/institutional boilers and process heaters, primary copper, and pulp and paper production. There was an extrem ely high level of uncerta inty in the results, such as percentage reductions exceeding 100 percen t (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 wa s 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.WRAP 2018 Base Case Inventory Version 1, January 2006 

### 3- 8 

## 3.4 Other Unquantified Regulatory Impacts

During the data collection process with the state and tribal environmental agencies, several types of control program s 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, annua l emissions) were quantified in the SIP document.

• Smelter Rule (R18-2-715) in Ariz ona. This rule sets hourly SO 2 

### emission limits at ASARCO Hayden Mill (295 lbs/hour) and Phel ps 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) PM 10 

### SIP emission reductions from “one brick manufacturer.” The SIP does not contain enough deta il (e.g., facility ID, applicab le SCCs) to apply these onthe-books reductions. Also, the SIP indicat es emission reductions of non-stack PM 10 

### sources from all industrial f acilities of 60%, alth ough specific facilities and SCCs are not provided.

• EGUs that have been identified as having potential post-2002 volunt ary reductions (i.e., although no specific reductions were applied):

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

⎯ Arizona Electric Power Cooperative - Apache, AZ

⎯ Nevada Power Company - Reid Gardner, NV

⎯ Huntington Power Plant, UT

⎯ Intermountain Generation Station, UTWRAP 2018 Base Case Inventory Version 1, January 2006 

### 4-1 

# 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 methodol ogies used to estimate future growth varied depending upon specific source type. For inst ance, a specialized methodology was developed for coal-fired EGUs in order to incorporate de tailed information regarding EGU operation, while a generalized approach was used for the majority of the other sources. The growth factor and rate analysis methodol ogies are described in detail below.



## 4.1 Electricity Generating Units

Because EGUs are the largest source of NO x 

### and SO 2 

### in the WRAP inventory domain, considerable effort was spent to develop projectio ns 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 re vised 2002 WRAP point sources inventory; all

EGU sources were then extracted from the overall inventory. Under a separate task of this project, NO x 

### and SO 2 

### emissions data had already been inco rporated into the inventory for all

EGUs that had continuous emissions monitors (CEMs) and reported to U.S. EPA’s Clean Air Markets Division (CAMD) databa se (identified as “CAMD EGUs ”) (U.S. EPA, 2005a). The methodology was applied only to CAMD EGUs; E GUs not contained in the CAMD database were treated like other non-EGU point sources (s ee Section 4.2). Method ology details specific to coal-fired CAMD EGUs are presented in S ection 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 inventor y (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 fr om the CAMD website for each of the units 3 

### :

3 http://cfpub.epa.gov/gduWRAP 2018 Base Case Inventory Version 1, January 2006 

### 4-2 • Nameplate unit capacity (megawatts [MW])

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

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

• 2002 NO x 

### emissions (tpy)

• 2002 SO 2 

### emissions (tpy)

• 2004 NO x 

### emissions (tpy)

• 2004 SO 2 

### emissions (tpy)

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

CF = (gross generated electricity [M Wh])/(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-fir ed 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 assume d based on input from the Projections Work Group. The use of this CT value was based upon hi storical 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 NO x 

### and SO 2 

### , the 2002 emissions were then multiplied by the

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

Emissions 2018 

### = Emissions 2002 

### × GF

An expanded methodology was utilized for NO x 

### and SO 2 

### . The calculated GF was multiplied by the 2002 heat input (HI) to obtain a projected 2018 HI:

HI 2018 

### = HI 2002 

### × GFWRAP 2018 Base Case Inventory Version 1, January 2006 

### 4-3 The most recent full-year (i.e., 2004) NO x 

### and SO 2 

### emission rates (ER) in pounds (lbs) per MMBtu were generated by dividing 2004 emissions by 2004 HI as follows:

ER NOx 

### = Emissions NOx,2004 

### /HI 2004


### ER SO2 

### = Emissions SO2,2004 

### /HI 2004 

### Based on the guidance of WR AP SSJF, the CAMD 2004 NO x 

### and SO 2 

### emission rates, which are the most current full year emission rate s for coal-fired EGUs, were used to represent coal-fired EGU operation in 2018. Emissions were calculated as follows:

Emissions NOx,2018 

### = HI 2018 

### × ER NOx


### Emissions SO2,2018 

### = HI 2018 

### × ER SO2


### As a final step, projected emissions were re duced 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 wa s 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. Af ter the list of CAMD EGUs was compiled, then the following data were downloaded from the CAMD website for

each of the units:WRAP 2018 Base Case Inventory Version 1, January 2006 

### 4-4 • Nameplate unit capacity (MW)

• 2002 gross electricity generation (MWh)

• 2002 NO x 

### emissions (tpy)

• 2002 SO 2 

### emissions (tpy)

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

CF = (gross generated electricity [M Wh])/(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 curre nt level of operation up to the CT value. The equation used is as follows:

GF = CT/CF

Different CT values were used for the ot her non-coal fired EGUs depending upon the fuel and technology present. These CT values us ed 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:

Emissions 2018 

### = Emissions 2002 

### × GF

4.1.3 Future EGUs

Another unique aspect of the growth analys is 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 elec tricity market module regions:

• Northwest Power Pool (Idaho, Oregon, Uta h, Washington, Wyoming; and parts of California, Montana, Nevada, and South Dakota);WRAP 2018 Base Case Inventory Version 1, January 2006 

### 4-5 • Rocky Mountain Power Area, Arizona, New Me xico, and Southern Nevada (Arizona and Colorado; and parts of Neva da, New Mexico, and Texas);

• Mid-Continent Area Power Pool (North Dakota, Nebraska; a nd parts of Montana, South Dakota, Minnesota, Iowa, and Wisconsin); and

• California (parts of California).

The analysis of future electricity generati on for coal and natural gas is summarized in Table 4-1 and Table 4-2. These generation va lues do not necessarily correspond to physical locations; rather, they indicate the assignment of EGUs to electricity market module regions.

Table 4-1. Future Electricity Gene ration 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 45.60 a Needed Generation 104.72 10.49 Unused Capacity at Existin g 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 Generati on 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 0.39 a 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.WRAP 2018 Base Case Inventory Version 1, January 2006 

### 4-6 

## 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 th e growth analysis methodology described in Section 4.1.1, 16.60 billion kWh of th is needed generation can be obtained from unused capacity (i.e., capacity between existing 2 002 generation and the 0 .85 capacity factor).

An additional 32.09 billion kWh of co al-fired generation has been id entified from facilities that

either came on-line in 2003 or 2004, are currently under construc tion, or are currently being permitted. All of these facilities were added to the 2018 inve ntory, 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 Perm itted AZ (001) 760 (combined) Comanche #3 Being Pe rmitted CO (101) 750 Northern Nevada Energy/Newm ont Being Permitted NV (011) 200 NEVCO Energy Company Being Permitted UT (041) 270 Intermountain Power Plant #3 Be ing 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 re maining WRAP states) of coal-fired electricity genera tion still remained. Based upon i nput 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 uponWRAP 2018 Base Case Inventory Version 1, January 2006 

### 4-7 current state-level capacity (i.e., sum of ex isting, 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 ot her WRAP states. It should also be noted that in addition to Oregon, Washington, and S outh 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 base d upon two factors:

• Announcements of plans to build coal-fired EGUs.

• Locations of existing coal-fired EGUs and associated infrastructure.WRAP 2018 Base Case Inventory Version 1, January 2006 

### 4-8 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 bill ion 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 curr ently under construction, or are currently being permitted. All of these facili ties were added to the 2018 inventory. Because the identified generation exceeded the projected 2018 needed gene ration, 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.WRAP 2018 Base Case Inventory Version 1, January 2006 

### 4-9 Table 4-6. Emissi on Rates for Future New Coal-Fired EGUs

Pollutant lb/ton lb/MMBtu a lb/MWh b Source NO x n/a 0.0900 0.9000 BACT c
SO 2 n/a 0.0900 0.9000 BACT d VOC 0.06 0.0022 0.0222 AP-42, Table 1.1-19 (U.S. EPA, 1995) CO n/a 0.1500 1.5000 BACT e

PM 10 -PRI n/a 0.0180 0.1800 BACT f

PM 2.5 -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 c onversion factor of 13,500 Btu/lb coal. b Converted from lb/MMBtu to lb/MWh usi ng conversion factor of 10,000 Btu/kWh.

c Obtained from range of values (0.06 to 0.1) from 12 Wester n facilities (U.S. EPA, 2005b); va lue selected with input from Projections Work Group. d Obtained from range of values (0.038 to 0.11) from 12 Wester n 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 Wester n 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 Wester n facilities (U.S. EPA, 2005b); va lue selected with input from Projections Work Group.



### Table 4-7. Emission Rates for Future New Na tural Gas-Fired EGUs

Pollutant lb/MMsc f lb/MMBtu a lb/MWh b Source NO x n/a 0.0900 0.6750 BACT c SO 2 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) PM 10 -PRI 7.60 0.0072 0.0543 AP-42, Table 1.4-2 (U.S. EPA, 1995) PM 2.5 -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 conve rsion factor of 1,050 Btu/scf natural gas. b Converted from lb/MMBtu to lb/MWh usi ng 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 Analys is System growth factor model (EGAS), Version 5.0 generates SCC-specific growth factors for a specifie d geographic area, base year (i.e., 2002), and future year (i.e ., 2018) using various socio-econo mic data (U.S. EPA, 2004; Abt,WRAP 2018 Base Case Inventory Version 1, January 2006 

### 4-10 2004). At the present time, the EGAS model run with default data can only generate growth

factors at the state-level. C ounty-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 resu lt, default modeling was conducted without these demographic data.

Default model runs were made for every state within the inventory w ith the exception of California; California growth f actors are discussed in Sectio n 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 cause d 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 (ENVIR ON, 2005). These growth factors were also applied to the point source inve ntory by mapping the oil and gas area source categories to the corresponding point source SCCs. The oil and ga s 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 EI A forecasts were applied (EIA, 2005). These regional growth factors ar e presented in Table 4-8.WRAP 2018 Base Case Inventory Version 1, January 2006 

### 4-11 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 obtaine d from one of three sources: the EGAS growth factor model, energy projections from EIA, or agricultural crop pr ojections 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 proj ection 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 i ssued 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 harves ted acreage estimates for eight major field crops (i.e., wheat, barley, corn, ri ce, oats, soybeans, sorghum, a nd 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 acre s; while the 2018 harvested acreage was

estimated to be 235.1 millions acres. This corresponds to a growth factor of 1.0361.WRAP 2018 Base Case Inventory Version 1, January 2006 

### 4-12 

## 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 repo rt for the other WRAP states. The California Air Resources Board (ARB) used the Califor nia Emission Forecasting System (CEFS) to develop California’s 2018 base case inventory an d 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 Zone a 6 UE UTM Eastern Coordinate a 7 UN UTM Northern Coordinate a 30 FACNAME Facility Name 30 FACSTREET Facility Street Location 20 CITY City 5 ZIP Zip Code

CEIDARS = California Emission Inventor y 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 algorith ms: TREND forecast module for aggregating emissions by air district, air basin, and county, an d GIS forecast module for developing forecasts at the facility/device/process level for use in gridded inventory inputs for modeling.WRAP 2018 Base Case Inventory Version 1, January 2006 

### 4-13 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 factor s, 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 Mana gement District (BAAQMD) provided their own grow th factors to CEFS. Grow th 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 Calif ornia are provided in a spreadsheet accompanying this report.

• Control Factors, provided entirely by the ai r districts in Califor nia, to quantify the impacts of on-the-books controls from ARB regulations, distri ct rules. Control factors comprise three components: control efficienc y, rule effectiveness, and rule penetration. The control factors are region, control measure, source category, and pollutant dependent. The control factors used in CEFS for devel oping the WRAP 2018 base case inventory for California are provided in a spread sheet 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 t ons per day. The pollutants were NO x 

### , SO 2 

### , reactive organic gases (ROG), CO, PM 10 

### , and PM 2.5 

### . ROG was taken to be equivalent to VOC; no NH 3 

### emissions were provided.

The following steps were then performed to place the CEFS emissions into the proper format, eliminate inconsistencies with the rema ining 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.

⎯ PM 10 

### and PM 2.5 

### records were adjusted according to the U.S. EPA correction factors for natural gas co mbustion (see Section 2.2).

⎯ Latitude/longitude coordinates were assigned to the 2018 records using information from California’s 2002 invent ory (compiled under Task 1A of thisWRAP 2018 Base Case Inventory Version 1, January 2006 

### 4-14 project). County centroids were assigne d to 2018 sources th at 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, pres cribed burning, forest fires, rangeland burning, agricultural bur ning, 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 Ca lifornia files were converted to NIF3.0 and IDA formats for use in subsequent step s of the 2018 base case inventory process.WRAP 2018 Base Case Inventory Version 1, January 2006 

### 5-1 

# 5.0 POINT SOURCE RETIREMENT AND REPLACEMENT

In addition to controls and growth, the 2018 pr ojected inventory also includes the effects of point source retirement and replacement. The a ssumptions used to apply the concepts of point source retirement and replacement were handled as follows:

• All point sources have a finite li fetime (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 en tirely 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 w ith specific modifications that were made for the special case of EGUs.



## 5.1 SCC Identification

Retirement and replacement was applied for a s ubset of the point sources contained in the 2002 WRAP inventory. A list of th e point sources and SCCs is pr ovided in Table 5-1 along with expected facility lifetime, annual retirement ra te, 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 re tirement rate of 0.02 (i.e., 1/50 years). The projection retirement rate is the percentage of sources under a pa rticular SCC that are expected to retire over the period of the proj ection (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).WRAP 2018 Base Case Inventory Version 1, January 2006 

### 5-2 Table 5-1 Retirement and Replacement S CCs, 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 NO x 

### , SO 2 

### , and PM 10 

### . These factors were based on the expect ed reduction as an uncontrolled source is retired and replaced by a new contro lled 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 PM 10 

### from industrial coal boi lers 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 th e 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 de scribed above was a pplied to all point

sources that matched the SCCs in Table 5-1. Th e one key exception was for EGUs. Instead of applying annual retirement rate s to EGUs, the age of the E GU 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 de scribed in Section 4.1) with the appropriate reduced emission rates. If the start-up da te 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 a nd Replacement Reduction Factors

Category Applicable SCCs NO x SO 2 PM 10 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 30600105 0.500 Petroleum Refining 30600201, 30600202 0.600 0.850WRAP 2018 Base Case Inventory Version 1, January 2006 

### 5-5 Table 5-3. Information Used to Develop Re tirement and Replacement Reduction Factors (lb/MMBtu)

NO x SO 2 PM 10 Category Applicable SCCs (Retired Rate) (Replace Rate) (Retired Rate) (Replace Rate) (Retired Limit) (Replace Rate) Utility Oil Boiler 101004xx, 101005xx, 10102101, 10101302 0.3 a 0.11 b 0.03 e 0.015 b

Utility Natural Gas Boilers 101006xx 0.25 a 0.09 b,c 0.03 e 0.015 b

Utility Renewable Boilers 10101501, 10101502, 10101801 0.15 a 0.11 b 0.03 e 0.015 b

Utility Oil Turbine 20100101, 20100108, 20100109, 20101302 0.15 a 0.11 b 0.03 e 0.015 b

Utility Natural Gas Turbine 20100201, 20100208, 20100209 0.32 a 0.11 b 0.03 e 0.015 b

10200219, 10200229, 10200307 0.45 a 0.11 b 0.03 e 0.015 b

10200405, 10200505 0.3 a 0.11 b 0.03 e 0.015 b Utility Cogeneration

10200604, 10200710 0.25 a 0.09 b,c 0.03 e 0.015 b

Industrial Coal Boilers 102001xx, 102002xx, 102003xx, 10500102 0.2 b,e f 0.051 g 0.03 b

Industrial Oil Boilers 102004xx, 102005xx, 10201302, 10500105, 10500113, 10500114 0.2 b,e f 0.1 g 0.03 b

Industrial Natural Gas Boilers 102006xx, 10500106 0.2 b,e f

Industrial Wood Boilers 102009xx 0.2 b,e 0.1 g 0.03 b

Industrial Oil Turbines 20200101, 20200103, 20200108, 20200109 0.2 b,e f

Industrial Natural Gas Turbines 20200201, 20200203, 20200208, 20200209 0.2 b,e

Industrial IC Engines All other 202002xx h

Oil and Gas Production 310002xx h

Cement Kilns 305006xx i

30600105 0.2 b,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) an d 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 Project ions Work Group and other stakeholders

indicated that the retiremen t/replacement methodology used fo r other point sources was not appropriate for coal-fired EGUs (i.e., no coal-fired EGUs in th e WRAP region are expected to retire by 2018). Therefore, no retirement/replace ment 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 va rious adjustments and factor s discussed in above, an intermediate inventory value (i.e., “Initial 2018 Ba se Case”) was calculated. This intermediate inventory value was used to eval uate and indicate other informa tion, which is discussed below.



## 6.1 Permit Limits

During review the draft 2018 base case, re levant 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 ina dvertently cause the resu lt predicted for 2018 to exceed any permit limit. In some cases, this wa s 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 th e Regional Haze Rule. These include point sources located in the nine GC VTC states (AZ, CA, CO , ID, NV, NM, OR, UT, and WY) and having SO 2 

### 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 f acility-level emissions. Table 6-1 lists these facilities. One facility with SO 2 

### emissions of 97 tons/year was also included in Table 6-1

because it was listed in the 2003 SO 2 

### Milestone report (WRAP, 2005) and its projected 2018 emissions exceed 100 tons/year.

Also, Table 6-2 was developed for the purpos e of comparing the sources subject to Section 309 (as shown in Table 6-1) to the s ources identified in Appendix A-1 of the 2003 SO 2 

### 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 SO 2 

### 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 2006Table 6-1. WRAP Facilities Subject to RHR Section 309 Requirements, Based on 2002 EmissionsTribe or StateCountyFIPSTribal or State Facility/2002 EI IdentifierPlantSICFacility Name2002 SO2Emissions(Tons)In 2003 SO2Milestone Report(A-1)Arapahoe Tribe of the WindRiver Reservation0 V-WR-0003-00.02Peak Sulfur Inc (WY) 897Navajo Nation 0 NN-OP 99-03 1321ChevronTexaco, Aneth Natural Gas Processing Plant(UT) 118Navajo Nation 0 EGU0037 4911 Navajo Generating Station (AZ) 4,007Navajo Nation 0 EGU0793 4911 Four Corners Power Plant (NM) 32,847AZ 04001 EGU0034 4911 SRP Coronado Generating Station 17,7279AZ04001 EGU0035 4911 TEP – Springerville 19,8629AZ04003 EGU0036 4911 AEPCO - Apache Generating Station 5,1679AZ04007 0400701391 Phelps Dodge – Miami 5,6679AZ04007 040072435 3331 Ray Complex - Smelter and Mill 18,4389AZ04017 040171807 4911 Snowflake Pulp Mill 1,5199AZ04017 EGU0045 4911 Cholla Power Plant 20,7709AZ04019 0425 4931 Tucson Electric Power 113AZ04019 EGU0047 4911 TEP - Irvington 3,1199AZ04025 040252393 3241 Phoenix Cement 2709AZ04025 040255992 3274 Nelson Lime Plant 7079CA 06001 1130383 3321 United States Pipe & Foundry C 151CA 06001 1130311362 3221 Owens Brockway Glass Container 187CA 06013 7130323 2819 General Chemical Corporation 224CA 06013 7130311661 2819 Rhodia Inc 419CA 06013 7130316 2911 Conocophillips - San Francisco 1,130CA 06013 7130311 2911 Shell Martinez Refinery 1,466CA 06013 7130322 2999 Tosco Refining Company 1,766CA 06013 7130310 2911 Chevron Products Company 1,829CA 06013 7130314628 2911 Tesoro Refining And Marketing 5,941CA 06019 101430311 1311 Chevron Usa Inc 115CA 06019 101430598 3211 Guardian Industries Corp 379CA 06029 15143037 2911 Kern Oil & Refining Company 140CA 06029 1514301141 1311 Chevron Usa Inc 401WRAP 2018 Base Case Inventory 

### 6-3 Version 1, January 2006Table 6-1. Cont.Tribe or StateCountyFIPSTribal or State Facility/2002 EI IdentifierPlantSICFacility Name2002 SO2Emissions(Tons)In 2003 SO2Milestone Report(A-1)CA 06029 1505129 3241 California Portland Cement Co. 929CA 06037 19102625070 4953 La Co., Sanitation District 119CA 06037 19102647232 3463 Arco Cqc Kiln 163CA 06037 1910267427 3221 Owens-Brockway Glass Container 177CA 06037 191026180001 4581 Los Angeles International 186CA 06037 191026114801 2819 Rhodia Inc. 210CA 06037 191026800362 2911 Tosco Refining Company 423CA 06037 191026800370 2911 Equilon Enterprises, Llc 703CA 06037 191026800026 2911 Ultramar Inc (Nsr Use Only) 726CA 06037 191026800363 2911 Tosco Refining Company 736CA 06037 191026800089 2911 Mobil Oil Corp 816CA 06037 191026800030 2911 Chevron U.S.A. Inc. 1,227CA 06037 191026131003 2911 West Coast Products Llc 1,576CA 06039 201430801 3221 Saint-Gobain Containers, Inc 116CA 06071 36051850001051 4911 Ace Cogeneration Co. 175CA 06071 361026800181 3241 California Portland Cement Co 181CA 06071 3605181200003 3241 Txi Riverside Cement Company 219CA 06071 36051811800001 3241 Mitsubishi Cement 2000 229CA 06071 360518100005 3241 Cemex – Black Mountain Quarry 427CA 06077 391430802 4931 Stockton Cogen Company 167CA 06077 391430593 3221 Owens-Brockway Glass Container 240CA 06077 391430767 2873 J R Simplot Company 313CA 06077 391430477 3211 Pilkington North America, Inc 314CA 06079 40113113 2911 Conoco Phillips Santa Maria Fa 3,760CA 06083 4211251735 3295 Celite Corporation 1,111CA 06085 43130317 3241 Hanson Permanente Cement 555CA 06087 4407151186 3241 Rmc Pacific Materials 722CA 06095 48130312626 2911 Valero Refining Company - Cali 7,009CA 06099 5014301662 3221 Gallo Glass Company 233CO 08001 0004 2911 Colorado Refining Co., Total Petroleum 394CO 08001 0003 2911 Suncor Energy - Denver Refinery 2,189WRAP 2018 Base Case Inventory 

### 6-4 Version 1, January 2006Table 6-1. Cont.Tribe or StateCountyFIPSTribal or State Facility/2002 EI IdentifierPlantSICFacility Name2002 SO2Emissions(Tons)In 2003 SO2Milestone Report(A-1)CO 08001 EGU0163 4911 Public Service Co Cherokee Plt 15,957CO 08013 EGU0164 4911 Public Service Co – Valmont 3,786CO 08031 BSCP157 3251 Robinson Brick Co 169CO 08031 EGU0165 4911 Public Service Co – Arapahoe 5,107CO 08041 EGU0169 4911 Colorado Springs Utilities-Nixon Plant 4,968CO 08041 EGU0167 4911 Colorado Springs Utilities-Drake Plant 8,530CO 08043 0001 3241 Holcim (Us) Inc. Portland Plant 242CO 08043 0003 4911 Aquila, Inc. – W.N. Clark Station 1,463CO 08059 0008 3221 Rocky Mountain Bottle Co 314CO 08059 0820 4961 Trigen - Colorado Energy Corporation 2,342CO 08069 0002 3241 Holcim (Us) Inc - Fort Collins Plant 378CO 08069 EGU0173 4911 Platte River Power Authority – Rawhide 898CO 08077 EGU0174 4911 Public Service Co Cameo Plt 2,095CO 08081 EGU0175 4911 Tri State Generation Craig 10,391CO 08085 EGU0176 4911 Tri State Generation Nucla 1,487CO 08087 EGU0179 4911 Public Service Co Pawnee Plt 14,833CO 08101 0048 3312 Cf&I Steel L P Dba Rocky Mtn Steel Mills 267CO 08101 EGU0182 4911 Public Service Co Comanche Plt 16,773CO 08107 EGU0183 4911 Public Service Co Hayden Plt 2,868ID 16027 02700010 2063 Tasco, Nampa 1,852ID 16029 02900003 2874 Nu West Industries 364ID 16029 02900001 2819 P4 Production LLC 12,210ID 16067 06700001 2063 Tasco, Paul 249ID 16077 07700006 2874 Jr Simplot Company Don Siding Complex 1,609ID 16083 08300001 2063 Tasco, Twin Falls 1,018NV 32003 0003 3275 Chemical Lime Company 178NV 32003 EGU0742 4911 Nevada Power Company 1,977NV 32003 EGU0744 4911 Southern California Edison 40,347NV 32007 AP32740261 3274 Graymont Western Us Inc 251NV 32011 AP10410404 1041 Newmont Gold Company 103NV 32011 AP10410739 1041 Barrick Goldstrike Mines Inc 193WRAP 2018 Base Case Inventory 

### 6-5 Version 1, January 2006Table 6-1. Cont.Tribe or StateCountyFIPSTribal or State Facility/2002 EI IdentifierPlantSICFacility Name2002 SO2Emissions(Tons)In 2003 SO2Milestone Report(A-1)NV 32013 AP10410451 1041 Sante Fe Pacific Gold Corporation 107NV 32013 EGU0749 4911 North Valmy Station 6,874NV 32019 AP32410387 3241 Nevada Cement Company 175NM 35001 0001 Rio Grande Portland Cement 1,1099NM 35007 350070001 4911 Raton Power Plant 2019NM 35015 350150285 1321 Dagger Draw Gas Plant 1709NM 35015 350150011 1321 Artesia Gas Plant 8389NM 35015 350150010 2911 Artesia Refinery 1,9759NM 35015 350150008 1311 Indian Basin Gas Plant 2,0409NM 35015 350150024 1311 Agave Gas Plant 2,0999NM 35025 350250063 1321 Saunders Plant 2719NM 35025 350250007 1311 Denton Plant 2959NM 35025 350250060 1321 Eunice Gas Plant 3939NM 35025 350250061 1321 Monument Plant 8389NM 35025 350250035 1321 Linam Ranch Gas Plant 9319NM 35025 350250008 1321 Jal No. 3 1,2069NM 35025 350250044 1321 Eunice Gas Plant 1,3309NM 35025 350250004 1321 Maljamar Gas Plant 2,4919NM 35031 350310008 2911 Ciniza Refinery 1,1029NM 35031 EGU0792 4911 Escalante Station 1,1929NM 35045 350450247 1321 San Juan River Gas Plant 5049NM 35045 350450023 2911 San Juan Refinery (Bloomfield) 5609NM 35045 EGU0794 4911 San Juan Fly Ash 16,7689OR 41007 00004 4961 Fort James Operating Company 1,3239OR 41009 01849 4961 Boise Cascade Corporation 1,1449OR 41041 00005 4961 Georgia-Pacific West, Inc. 3079OR 41043 03501 4961 Pope & Talbot, Inc. 979OR 41043 00471 4961 Weyerhaeuser Company 443OR 41045 00002 4961 Amalgamated Sugar Company, The 8139OR 41049 EGU0971 4911 Portland General Electric Company 12,2629OR 41051 01876 3221 Owens-Brockway Glass Container Inc. 1099WRAP 2018 Base Case Inventory 

### 6-6 Version 1, January 2006Table 6-1. Cont.Tribe or StateCountyFIPSTribal or State Facility/2002 EI IdentifierPlantSICFacility Name2002 SO2Emissions(Tons)In 2003 SO2Milestone Report(A-1)OR 41071 06142 4961 Smurfit Newsprint Corporation 5479UT 49007 10096 4911 Sunnyside Cogeneration Facility 1,0139UT 49007 EGU1218 4911 Carbon Power Plant 6,7649UT 49011 10122 2911 Flying J Refinery (Big West Oil Co.) 2819UT 49011 10123 2911 Phillips Refinery 4529UT 49011 10119 2911 Salt Lake Refinery 1,3329UT 49015 EGU1220 4911 Hunter Power Plant 7,0269UT 49015 EGU1221 4911 Huntington Power Plant 13,7109UT 49027 10311 1099 Delta Mill 1239UT 49027 10313 3274 Cricket Mountain Plant 3109UT 49027 EGU1222 4911 Intermountain Generation Station 3,6489UT 49035 12096 1531 I-15 Corridor Reconstruction 103UT 49035 10335 2911 Salt Lake City Refinery 7129UT 49035 10346 3331 Kennecott Smelter & Refinery 9399UT49035 10572 1021Kennecott Utah Copper Corp -Power Plt/ Lab/ TailingsImpoundment 2,7889UT 49037 10034 1311 Lisbon Natural Gas Processing Plant 1,4539UT 49043 10676 3295 Shale Processing 1179UT 49047 EGU1224 4911 Bonanza Power Plant 981UT 49049 10796 4911 Geneva Steel Manufacturing Facility 1089UT 49049 10790 8221 BYU Main Campus 1429WY 56001 5600100005 4911 University of Wyoming, Heat Plant 1899WY 56001 5600100002 3241 Mountain Cement Co 2079WY 56003 00016 Kcs Mountain Resrcs-Rushmore Flare 118WY 56005 EGU1324 4911 Black Hills Corporation_Simpson 2 7079WY 56005 5600500002 4911 Black Hills Corporation Simpson 1 1,0849WY 56005 EGU1323 4911 Pacificorp_Wyodak 8,2919WY 56007 5600700001 2911 Sinclair Oil Corp-Sinclair Refinery 3,4559WY 56009 EGU1325 4911 Pacificorp_Dave Johnston 19,9789WY 56011 5601100002 1459 American Colloid_East Colony 1339WRAP 2018 Base Case Inventory 

### 6-7 Version 1, January 2006Table 6-1. Cont.Tribe or StateCountyFIPSTribal or State Facility/2002 EI IdentifierPlantSICFacility Name2002 SO2Emissions(Tons)In 2003 SO2Milestone Report(A-1)WY 56013 00011 1311 Santa Fe Snyder_Riverton Plant 193WY 56013 5601300028 1311 Burlington Resources_Lost Cabin 2,1749WY 56015 5601500001 2063 Western Sugar Coop_Torrington Plant 1609WY 56017 00009 Hallwood Petroleum-Feder Packsaddle 1-24 141WY 56017 00006 1311 Kcs Mountain Resrcs_Golden Eagle Flare 360WY 56017 00008 Hallwood Petroleum-Federal Packsaddle #1 971WY 56021 5602100001 2911 Frontier Refining, Inc. 1,4949WY 56023 5602300013 1311 Exxon Shute Creek I 1,8189WY 56023 EGU1326 4911 Pacificorp_Naughton Power Plant 19,3109WY 56025 5602500005 2911 Sinclair Refinery - Casper 1,0819WY 56029 00003 Celotex Corp. 299WY 56029 5602900007 1321 Marathon Oil Co _ Oregon Basin Gas Plant 3009WY 56029 5602900012 1311 Howell Pet Corp_Elk Basin Gas Plant 1,4659WY 56031 EGU1327 4911 Basin Electric_Laramie River Station 11,1349WY 56035 00001 Exxon -Labarge Dehydration Facility 115WY 56037 5603700008 1321 Union Pac_Brady 1449WY 56037 5603700003 5171 P4 Production_Rock Springs Facility 8599WY 56037 5603700022 4911 Sf Phosphates, Inc 2,0159WY 56037 5603700002 4911 General Chemical 4,9659WY 56037 5603700048 2812 Fmc Corp_Green River Plant_Sodium Prod 5,2589WY 56037 EGU1330 4911 Pacificorp_Jim Bridger 20,0879WY 56041 5604100009 1311 Chevron Carter Creek 6869WY 56041 5604100012 1311 Bp America - Whitney Canyon 6,2919WY 56043 5604300003 1321 Hiland Partners, Llc_Hiland Gas Plant 2649WY 56045 5604500001 2911 Wyoming Refining Co_Newcastle Refinery 3439WY 56045 5604500005 4911 Black Hills Corporation _Osage 2,8229WRAP 2018 Base Case Inventory Version 1, January 2006 

### 6-8 Table 6-2. WRAP Facilities S hown in Appendix A-1 of 2003 SO 2 

### Milestone Report, and with 2002 SO 2 

### Emissions Less than 100 Tons

State County FIPS State Facility Identifier Facility Name 2002 SO 2 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 SO 2 WY Chevron USA – Table Rock Field 0 Came on-line after 2002; 2018 base case = 232 tons SO 2 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 SO 2 WY 037 5603700039 FMC Wyoming Corporation – Soda Ash Plant 10

WY 037 5603700005 Solvay Minerals – Soda Ash Plant 33WRAP 2018 Base Case Inventory Version 1, January 2006 

### 6-9 

## 6.3 Data Formatting

Subsequent to development of the final 2018 ba se 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 fina l 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 sour ce inventories at the tr ibal- and state-level, while Table 7-2 disaggregates th e WRAP and CENRAP point sour ce inventories in to significant sectors (e.g., coal-fired EGUs, copper smelters, cement and lime kilns, etc.). The overall 2002

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

source inventories for NO x 

### , SO 2 

### , and PM 10 

### are presented in Tables 7-4 through 7-6 for WRAP and CENRAP, although, CENRAP 2 018 non-EGU point sources and a ll area sources are not yet

available.

The inventories are also repr esented in bar charts in Fi gures 7-1 through 7-4 (for NO x 

### , SO 2 

### , VOC, and PM 10 

### , respectively). Although similar informa tion is presented in the tables and bar charts, some significant findi ngs and trends can be readily id entified 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 PM 10 

### are predominantly from area sources, while SO 2 

### is mainly from point sources. NO x 

### is similar to SO 2 

### ; however, the area source contri bution is larger. In fact, area source NO x 

### exceeds point source NO x 

### 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 populat ion and/or economic gr owth as expressed by growth factors from EGAS, as well as in creased demands for electricity generation.

• Significant decreases in em issions (e.g., point source SO 2 

### emissions in Colorado and Nevada) are the result of cons ent decrees or permit limits.

• Large increases in area source NO x 

### and VOC emissions (i.e., n ear doubling or greater in New Mexico and Wyoming) are primarily cause d 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 chan ges expected to occur in the poi nt 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 2006Table 7-1. 2002 and 2018 Base Case – Point Source Emissions by Stateand Tribe, Version 12002 Emissions (tpy)2018 Emissions (tpy)StateState FIPSNOXSO2VOCCOPM10-PRIPM25-PRINH3NOXSO2VOCCOPM10-PRIPM25-PRINH3Alaska 02 74,471 6,811 5,688 27,910 5,933 1,237 578 67,959 7,777 6,633 25,876 2,879 355 1,104Arizona 04 64,084 93,756 5,464 15,232 9,533 1,059 531 77,737 106,113 9,459 33,242 9,889 1,638 728California 06 104,435 42,120 54,160 120,089 29,94620,276 433 109,515 49,632 54,632 123,795 33,192 19,497Colorado 08 117,869 97,011 91,750 35,951 21,12529 539 112,153 68,476 98,630 58,211 28,697 307 623Idaho 16 11,486 17,597 2,113 23,981 1,085 443 1,07413,946 10,813 3,059 38,019 1,736 642 1,650Montana 30 53,415 36,879 7,577 33,199 8,127309 318 62,583 43,055 10,446 62,354 11,266 692 422Nevada 32 59,737 50,720 2,213 11,083 4,738 1,075 62969,016 24,041 4,113 20,746 6,200 1,535 1,173New Mexico 35 100,352 37,436 17,574 36,589 3,8262,678 75 74,874 40,825 26,187 57,506 3,392 1,749 123North Dakota 38 87,425 156,668 2,086 11,944 3,2772,712 518 91,895 162,705 2,494 22,373 4,369 3,052 523Oregon 41 24,959 17,587 27,846 35,494 10,442 8,885948 31,761 21,687 41,344 53,656 13,515 16,660 1,016South Dakota 46 20,697 14,022 2,542 4,700 974 246 10024,726 15,268 3,522 6,852 1,044 257 102Utah 49 91,044 42,838 7,482 51,572 12,904 4,4731,937 96,974 52,953 13,60098,373 18,382 5,812 2,082Washington 53 43,631 52,969 18,616114,317 9,910 3,642 3,863 49,397 51,355 28,013 187,705 12,096 4,676 5,495Wyoming 56 117,883 119,645 19,663 36,361 31,731 13,653 685 132,591 145,100 28,087 60,997 42,819 19,496 811Tribes (Total) 00 87,215 38,208 1,710 6,297 6,342 3,006 125 92,580 32,895 2,864 12,988 7,749 3,206 125Total 1,058,702 824,265 266,484 564,719 159,892 63,72312,352 1,107,708 832,693 333,083862,693 197,226 79,572 15,977TribeTribalFIPSNOXSO2VOCCOPM10-PRIPM25-PRINH3NOXSO2VOCCOPM10-PRIPM25-PRINH3Arapahoe Tribe of the WindRiver Reservation, Wyoming281 54 939 60 11 44 1,511 158 17Assiniboine and Sioux Tribesof the Fort Peck IndianReservation, Montana 206 151 1 25 104 42 90 1 31 121 55Cabazon Band of CahuillaMission Indians of theCabazon Reservation,California568 190 52 11 4 9 268 73 15 6 13Coeur d'Alene Tribe of theCoeur d'Alene Reservation,Idaho 181 323 12 289 569 1,127 363 15 378 690 1,518Confederated Tribes andBands of the Yakama Nation,Washington124 60 16 120 95 96 64 15 191 144 123WRAP 2018 Base Case Inventory 

### 7-3 Version 1, January 2006Table 7-1. Cont.TribeTribalFIPSNOXSO2VOCCOPM10-PRIPM25-PRINH3NOXSO2VOCCOPM10-PRIPM25-PRINH3Confederated Tribes of theColville Reservation,Washington 101 227 22 58 570 308 245 34 87 867 306Confederated Tribes of theUmatilla Reservation, Oregon 143 6 1 7 1Fort Mojave Indian Tribe ofArizona, California & Nevada 604 13 225 12 271 116Gila River Indian Communityof the Gila River IndianReservation, Arizona 614 65 15 124 69 181 86 17 180 92 255La Posta Band of DieguenoMission Indians of the LaPosta Indian Reservation,California 577 1 0 0 0 5 2 0 0 1 6Navajo Nation, Arizona, NewMexico & Utah780 83,387 37,028 915 4,621 4,115 2,929 12588,234 31,108 1,422 10,767 4,771 3,104 125Pueblo of Laguna, NewMexico707 1,439 0 10 2,038 0 13Pueblo of Santa Ana, NewMexico715 209 53 49 64 54 209 53 49 64 64Salt River Pima-MaricopaIndian Community of the SaltRiver Reservation, Arizona 615 212 64 29 95 284 69 180 50 41 83 382 92Shoshone-Bannock Tribes ofthe Fort Hall Reservation ofIdaho 180 855 1 20 106 2 484 2 29 155 2Tohono O'Odham Nation ofArizona610 42 3 68 48 3 82Ute Mountain Tribe of the UteMountain Reservation,Colorado, New Mexico &Utah751 23 7 32 10Total 87,215 38,208 1,710 6,297 6,342 3,006 12592,580 32,895 2,864 12,988 7,749 3,206 125WRAP 2018 Base Case Inventory 

### 7-4 Version 1, January 2006Table 7-2. 2002 and 2018 Base Case – PointSource Emissions by Sector, Version 12002 Emissions (tpy)2018 Emissions (tpy)StateNOXSO2VOCPM10-PRIPM25-PRINH3NOXSO2VOCPM10-PRIPM25-PRINH3WRAP Point Sources Total 1,058,743 824,260 266,469 159,905 63,741 12,352 1,107,708 832,693 333,083 197,226 79,572 15,977Coal-fired EGUs Total 574,643 581,397 3,988 32,064 14,760 2,884 615,081 543,078 5,259 40,594 17,598 2,949Arizona45,401 66,642 193 1,129 96 172 49,491 60,013 352 2,385 470 187California397 342 3 19 7 431 395 0 18 8Colorado72,513 89,157 450 2,455 0 299 71,406 59,919 609 3,701 306 305Idaho0 0 0 0 0 1,675 1,675 41 335 87Montana35,644 21,846 331 632 0 11 44,105 26,860 499 1,676 247 13Nevada38,872 49,198 186 2,657 426 127 39,823 21,912 244 3,126 548 139New Mexico33,997 18,233 184 1,769 399 5 25,392 17,170 229 889 494 5North Dakota75,950 140,534 781 2,911 2,349 378 82,738 152,827 909 3,958 2,645 383Oregon8,401 12,262 62 695 2 31 9,444 14,935 73 818 2 37South Dakota14,954 11,756 108 234 234 50 15,323 12,859 112 243 243 52Utah71,388 32,130 306 3,689 1,645 1,303 74,732 41,369 489 5,177 2,033 1,303Washington15,463 19,032 14,499 6,378Wyoming84,518 83,411 852 11,774 6,673 382 102,849 96,050 1,031 13,499 7,411 400Tribes 77,146 36,854 533 4,100 2,929 125 83,174 30,716 669 4,770 3,104 125Other EGUs Total 66,689 19,81110,671 10,510 4,933 1,295 97,977 22,464 16,585 10,408 3,950 2,146Alaska11,077 3,339 153 814 2 13,061 5,298 186 583 0Arizona5,819 1,680 344 1,053 378 288 12,627 1,288 624 1,190 331 455California16,369 1,029 1,601 3,072 3,003 88 20,288 1,327 2,472 1,939 1,622Colorado4,327 96 553 821 29 154 6,268 162 765 301 1 232Idaho19 0 0 2 312 7 0 0Montana395 1,550 24 115 0 591 2,177 38 143 0Nevada13,070 108 449 712 117 342 18,053 212 1,368 1,203 221 872New Mexico3,075 46 148 186 70 7 6,139 66 294 456 132 40North Dakota31 31Oregon497 23 44 122 37 130 4,893 65 293 359 318 183South Dakota967 786 4 37 2,329 663 5 30Utah1,891 1,138 122 172 90 40 2,332 807 170 235 79 48Washington5,721 2,791 2,121 2,274 1,207 178 7,389 3,569 3,082 2,320 1,246 212WRAP 2018 Base Case Inventory 

### 7-5 Version 1, January 2006Table 7-2. Cont.2002 Emissions (tpy)2018 Emissions (tpy)StateNOXSO2VOCPM10-PRIPM25-PRINH3NOXSO2VOCPM10-PRIPM25-PRINH3Wyoming 3,243 7,171 5,098 1,108 36 3,164 6,733 7,002 1,499 73Tribes 218 56 12 23 532 91 288 148Copper Smelters Total 538 25,044 205 832 155 0 818 44,191 293 876 292 0Arizona 377 24,105 195 639 0 555 42,501 277 511 0Utah 161 939 10 194 155 0 264 1,690 16 365 292 0Cement and Lime Kilns Total 56,061 8,489 1,192 8,190 1,884 31 74,719 12,281 1,753 13,892 3,815 48Arizona6,533 987 38 1,410 7,969 1,788 66 1,873California20,555 3,292 248 3,498 1,388 0 25,618 4,156 284 7,008 3,043Colorado3,844 670 208 958 5,454 1,098 347 1,460Idaho672 40 7 6 973 45 12 11Montana3,570 601 9 509 0 1 4,631 746 13 755 1 2Nevada4,547 426 144 6,321 560 192New Mexico804 15 37 97 1,055 25 60 148Oregon1,741 38 15 64 2,290 63 25 104South Dakota3,846 760 108 270 6,083 1,230 172 451Utah3,965 374 326 835 367 24 6,066 567 507 1,287 577 36Washington3,747 1,068 0 280 128 0 5,519 1,672 0 415 194 0Wyoming2,232 210 46 232 2,733 319 70 341Tribes 6 9 4 38 7 11 5 49Oil & Gas Refiningand Distribution Total 38,522 65,051 23,248 4,250 2,007 357 39,257 66,348 28,801 3,197 931 438Alaska2,256 518 864 169 33 16 2,304 490 1,131 137 38 16Arizona1,559 1 39 24 10 10 1,564 1 60 15 1 16California14,077 22,305 8,070 1,675 1,599 12,328 25,407 9,022 784 702Colorado1,047 2,584 822 304 1 1,207 2,597 1,142 353 1Montana2,644 8,827 3,408 461 1 41 2,871 7,335 4,481 499 0 58Nevada82 93 62 112 123 81New Mexico1,572 3,645 2,777 276 194 4 1,522 2,898 3,775 237 144 6North Dakota4,345 10,245 356 0 4,135 4,109 453 0Oregon805 4 25 9 1 795 4 24 0 2South Dakota0 0 0 0 0 00 0WRAP 2018 Base Case Inventory 

### 7-6 Version 1, January 2006Table 7-2. Cont.2002 Emissions (tpy)2018 Emissions (tpy)StateNOXSO2VOCPM10-PRIPM25-PRINH3NOXSO2VOCPM10-PRIPM25-PRINH3Utah 1,947 2,781 1,342 300 156 272 2,005 2,975 1,765 206 42 325Washington 4,647 7,674 1,501 413 14 2 5,494 7,330 1,915 254 3 2Wyoming 1,753 6,374 3,972 617 0 11 2,325 13,079 4,938 712 0 14Tribes 1,789 0 10 1 2,595 0 15 0Oil & Gas Production Total188,134 36,133 93,808 5,053 4,007 133 131,645 48,431 100,811 777 386 244Alaska45,822 826 2,310 2,253 822 21 36,501 122 2,112 358 39 87Arizona2,735 3 233 48 3,468 10 345 11California16,707 2,556 7,101 1,698 1,699 7 13,390 1,988 4,962 170 152Colorado25,955 93 63,960 401 15,832 131 59,436 43Idaho2,590 7 78 1,734 10 114Montana4,275 11 687 22 0 2,554 16 1,024 3 2Nevada83 0 23 0 139 5 32 2New Mexico57,173 14,156 11,527 330 1,38232 36,323 19,226 18,339 114 146 44North Dakota4,739 2,949 187 7 7 1 2,946 3,354 262 1 0 2Oregon1,182 8 40 15 0 608 4 23 0 0South Dakota323 10 26 128 311 15 38 9Utah3,311 1,457 852 22 24 73 2,314 2,125 3,028 17 25 112Washington1,281 19 64 72 54 703 11 36 2 1Wyoming15,015 13,822 6,283 27 18 0 9,713 20,902 10,155 22 21 0Tribes 6,943 217 437 30 5,109 512 904 25All Other Point Sources Total 134,156 88,334 133,357 99,00635,996 7,651 148,210 95,900 179,581 127,483 52,601 10,152Alaska15,317 2,127 2,360 2,697 379 542 16,093 1,867 3,203 1,803 278 1,001Arizona1,661 334 4,410 5,226 570 59 2,064 512 7,737 3,904 835 70California36,330 12,597 37,136 19,984 12,580 339 37,460 16,360 37,892 23,273 13,970Colorado10,182 4,411 25,758 16,186 85 11,985 4,570 36,332 22,839 85Idaho8,206 17,550 2,027 1,085 442 1,068 9,252 9,076 2,891 1,401 554 1,640Montana6,887 4,044 3,118 6,388 307 265 7,831 5,921 4,392 8,189 443 350Nevada3,121 896 1,350 1,395 558 160 4,569 1,227 2,195 1,870 766 162New Mexico3,730 1,342 2,900 1,169 633 27 4,442 1,440 3,490 1,548 834 28North Dakota2,392 2,939 763 359 356 107 2,076 2,416 869 411 406 107WRAP 2018 Base Case Inventory 

### 7-7 Version 1, January 2006Table 7-2. Cont.2002 Emissions (tpy)2018 Emissions (tpy)StateNOXSO2VOCPM10-PRIPM25-PRINH3NOXSO2VOCPM10-PRIPM25-PRINH3Oregon12,333 5,252 27,659 9,537 8,845 787 13,732 6,616 40,907 12,233 16,338 797South Dakota607 709 2,297 305 13 50 680 501 3,196 311 14 50Utah8,382 4,019 4,526 7,692 2,036 224 9,262 3,420 7,624 11,095 2,765 258Washington12,773 22,386 14,930 6,873 2,239 3,683 15,794 32,395 22,980 9,104 3,232 5,281Wyoming11,122 8,658 3,411 17,973 6,962 255 11,808 8,016 4,891 26,747 12,064 323Tribes 1,113 1,071 714 2,137 77 1,163 1,565 982 2,757 102CENRAP Point Sources Total 1,826,695 2,225,082 532,620 376,018 233,158 194,467 597,336 1,279,135 11,623 99,843 84,528 11,901CENRAP EGUs Total 973,128 1,553,010 17,409 84,529 55,227 4,404 597,336 1,279,135 11,623 99,843 84,528 11,901Arkansas 39,303 70,367 476 1,173 586 1 33,097 82,605 696 3,897 3,326 814Iowa 83,563 133,641 803 12,959 5,913 51,119 147,305 770 10,033 8,615 569Kansas 94,665 129,720 1,087 15,475 13,696 4,166 83,333 81,486 798 8,520 6,807 461Louisiana 116,018 108,657 3,089 10,441 7,943 28 30,432 74,262 660 3,966 3,590 919Minnesota 91,497 105,826 728 10,122 6,301 59 41,029 85,847 674 8,162 7,035 343Missouri 144,674 259,663 1,518 4,745 2,845 46 77,660 280,887 1,579 18,456 16,769 799Nebraska 47,225 67,592 638 332 195 44 50,781 73,629 450 2,296 1,915 217Oklahoma 86,222 110,837 988 4,365 2,639 61 76,048 113,680 1,008 5,561 4,840 1,355Texas 269,961 566,708 8,082 24,918 15,109 153,837 339,433 4,987 38,952 31,631 6,423CENRAP Other Point Sources Total 853,567 672,072 515,211 291,488 177,931 190,063Arkansas 29,564 20,401 102,032 38,811 30,881 2,910Iowa 38,561 51,024 38,353 15,829 7,737 3,366Kansas 70,620 10,651 26,371 31,606 11,376 59,749Louisiana 196,616 177,393 85,936 62,892 52,956 9,209Minnesota 63,645 25,716 40,242 40,989 21,236 28,614Missouri 37,125 101,885 34,626 16,204 8,235 31,074Nebraska 11,394 5,895 6,636 12,773 4,443 30,687Oklahoma 72,749 38,015 35,998 13,644 7,137 24,196Texas 332,396 241,090 144,993 58,611 33,833 255Tribes 898 0 22 129 96 4WRAP 2018 Base Case Inventory 

### 7-8 Version 1, January 2006Table 7-3. 2002 and 2018 Base Case – Area SourceEmissions by State and Tribe, Version 12002 Emissions (tpy)2018 Emissions (tpy)StateState FIPSNOXSO2VOCCOPM10-PRIPM25-PRINH3NOXSO2VOCCOPM10-PRIPM25-PRINH3Alaska 02 8,488 5,53113,020 27,258 15,042 5,474 4729,293 6,044 16,539 29,056 21,531 6,878 639Arizona 04 9,049 2,677 108,332 49,957 99,963 28,290 5,92212,559 3,410 171,415 70,097 137,883 39,333 9,457California 06 114,471 8,314343,778 374,891 179,932 85,948 7,510117,717 9,772 357,746 384,967 190,987 152,778Colorado 08 34,846 6,559 124,578 87,628 157,875 42,612 7744,041 7,499 173,092 94,595 185,238 48,423 97Idaho 16 30,318 2,916 123,944 34,271 50,992 5,729 1,68442,068 2,721 194,210 40,971 62,881 7,703 2,288Montana 30 12,072 3,299 55,104 36,903 153,207 35,456 46036,053 3,432 67,477 41,415 173,892 40,015 608Nevada 32 5,787 12,954 29,977 13,737 68,009 16,074 1,1207,488 14,194 47,610 17,479 97,756 23,313 1,646New Mexico 35 85,576 6,559 219,124 37,284 109,381 26,626 636172,319 15,753 399,205 47,997 144,289 34,664 910North Dakota 38 15,457 5,748 69,795 21,970 287,62260,308 368 21,129 5,856 82,651 21,607 311,273 64,978 463Oregon 41 14,825 9,932 251,802 352,955 177,460 69,096 22717,027 8,422 334,872 380,524 225,925 81,745 250South Dakota 46 6,345 10,167 42,661 24,249 209,04145,029 381 7,207 11,667 50,072 25,112 226,750 48,648 502Utah 49 11,335 3,581 85,320 42,929 30,256 4,975 1,32021,636 3,587 173,344 45,962 34,279 5,761 1,680Washington 53 18,355 7,388 198,283222,555 283,542 93,472 4,471 22,746 8,667 253,710 252,447 348,329 113,985 7,022Wyoming 56 34,891 17,902140,248 29,292 37,511 10,804 38979,196 23,109 436,885 34,463 45,027 12,436 514Tribes (Total) 00 2,932 49 8,472 283 1,978 39806,639 2 18,240 564 2,062 412 0Total 404,749 103,577 1,814,4391,356,163 1,861,810 530,289 25,034617,116 124,136 2,777,068 1,487,257 2,208,103 681,071 26,075TribeTribal FIPsNOXSO2VOCCOPM10-PRIPM25-PRINH3NOXSO2VOCCOPM10-PRIPM25-PRINH3Arapahoe Tribe of theWind RiverReservation, Wyoming 281 1,16946 3,961 49 2,963 0 10,436 137Assiniboine and SiouxTribes of the Fort PeckIndian Reservation,Montana 206 57 1 1,374 118 1,976 398080 2 2,108 141 2,060 412 0Cortina IndianRancheria of WintunIndians of California 513 0 0 0 2 2 0 0 1 2 2WRAP 2018 Base Case Inventory 

### 7-9 Version 1, January 2006Table 7-3. Cont.TribeTribal FIPSNOXSO2VOCCOPM10-PRIPM25-PRINH3NOXSO2VOCCOPM10-PRIPM25-PRINH3La Posta Band ofDiegueno MissionIndians of the La PostaIndian Reservation,California 577 0 0 0 0 0 0 0 0 0 0 0 0Navajo Nation, Arizona,New Mexico & Utah 780 1,167 2 2,344 101 2,810 0 4,540 265Ute Mountain Tribe ofthe Ute MountainReservation, Colorado,New Mexico & Utah751 540 0 793 13785 0 1,156 18Total 2,932 49 8,472 283 1,978 39806,639 2 18,240 564 2,062 412 0WRAP 2018 Base Case Inventory Version 1, January 2006 

### 7-10 Table 7-4. 2002 and 2018 Base Case – Area Source NO x 

### 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 N evada 483 683 N ew Mexico 613 874 N o r th 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 N evada 962 1,030 N ew 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 N evada 1,037 1,193 N ew Mexico 412 518 N orth Dakota 1,440 1,531 Oregon 359 445 South Dakota 831 883 Washington 1,502 1,862 Wyoming 1,625 2,039WRAP 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 N evada 621 863 N ew Mexico 16,821 20,894 N orth 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 N evada 62 72 N ew Mexico 60,446 138,551 N orth 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 N evada 124 177 N ew Mexico 340 412 N orth Dakota 301 307 Oregon 162 206 South Dakota 286 291 Utah 150 214 Washington 355 451WRAP 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 N evada 1,499 2,293 N ew Mexico 1,688 2,657 N orth 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 N evada 118 125 N ew Mexico 144 150 N orth 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 821WRAP 2018 Base Case Inventory Version 1, January 2006 

### 7-13 Table 7-4. Cont.

2002 (tons) 2018 (tons) N evada 880 1,051 N ew Mexico 4,886 8,060 N orth 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 N ebraska 14,720 Oklahoma 115,134 Texas 279,051 Tribes 8WRAP 2018 Base Case Inventory Version 1, January 2006 

### 7-14 Table 7-5. 2002 and 2018 Base Case – Area Source SO 2 

### 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 N evada 11 11 N ew 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 N evada 5 7 N ew Mexico 4 5 N orth 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 N evada 4,935 5,283 N ew Mexico 508 525 South Dakota 6,966 7,653 Utah 0 0 Washington 750 798 Wyoming 9,111 9,404WRAP 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 N evada 7,301 8,404 N ew Mexico 878 1,102 N orth 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 N evada 396 145 N ew Mexico 2,913 13,106 N orth 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 N evada 1 0 N ew Mexico 1,444 17 N orth 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 71WRAP 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 N evada 1 1 N ew Mexico 2 3 N orth 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 N evada 9 14 N ew Mexico 11 17 N orth 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 N evada 11 11 N ew Mexico 22 23 N orth Dakota 28 28 Oregon 616 642 South Dakota 33 33 Utah 23 24 Washington 332 346WRAP 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 N evada 286 319 N ew Mexico 714 886 N orth 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 N ebraska 7,744 Oklahoma 11,731 Texas 109,383 Tribes 1WRAP 2018 Base Case Inventory Version 1, January 2006 

### 7-18 Table 7-6. 2002 and 2018 Base Case – Area Source PM 10 

### 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 N evada 559 579 N ew Mexico 17,158 17,778 N orth 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 N evada 75 7 N ew Mexico 47 5 N orth 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 N evada 52,443 78,925 N ew Mexico 76,802 105,599 N orth Dakota 20,571 24,855WRAP 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 N evada 109 136 N ew Mexico 619 771 N orth 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 N evada 12,142 14,691 N ew Mexico 8,745 12,284 N orth 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 N evada 215 363 N ew Mexico 1,159 1,496WRAP 2018 Base Case Inventory Version 1, January 2006 

### 7-20 Table 7-6. Cont.

2002 (tons) 2018 (tons) N orth 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 N evada 367 620 N ew Mexico 1,936 2,498 N orth 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 N evada 90 9 N ew Mexico 136 15 N orth 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 N evada 640 678 N ew Mexico 1,565 1,633 N orth Dakota 2,000 2,000WRAP 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 N evada 1,369 1,747 N ew Mexico 1,214 2,211 N orth 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 N ebraska 36,332 Oklahoma 121,772 Texas 906,497 Tribes 52WRAP 2018 Base Case Inventory 

### 7- 22 Version 1, January 2006Figure 7-1. WRAP Point and Area Source 2002 and 2018 NOxEmissions, Version 1020,00040,00060,00080,000100,000120,000140,000160,000180,000200,000

Emissions (tpy)2002-Point74,472 64,084 104,435 117,869 11,487 53,415 59,775 100,352 87,425 24,959 20,698 91,044 43,631 117,883 87,2152018-Point67,959 77,737 109,515 112,153 13,946 62,583 69,016 74,874 91,895 31,761 24,726 96,974 49,397 132,591 92,5802002-Area8,488 9,049 114,471 34,846 30,318 12,072 5,787 85,576 15,457 14,825 6,345 11,335 18,355 34,891 2,9322018-Area9,293 12,559 117,717 44,041 42,068 36,053 7,488 172,319 21,129 17,027 7,207 21,636 22,746 79,196 6,639AK AZ CA CO ID MT NV NM ND OR SD UT WA WY TribesWRAP 2018 Base Case Inventory 

### 7- 23 Version 1, January 2006Figure 7-2. WRAP Point and Area Source 2002 and 2018 SO2Emissions, Version 1020,00040,00060,00080,000100,000120,000140,000160,000180,000

Emissions (tpy)2002-Point6,809 93,752 42,120 97,011 17,597 36,879 50,722 37,436 156,668 17,587 14,021 42,838 52,969 119,645 38,2082018-Point7,777 106,113 49,632 68,476 10,813 43,055 24,041 40,825 162,705 21,687 15,268 52,953 51,355 145,100 32,8952002-Area5,531 2,677 8,314 6,559 2,916 3,299 12,954 6,559 5,748 9,932 10,167 3,581 7,388 17,902 492018-Area6,044 3,410 9,772 7,499 2,721 3,432 14,194 15,753 5,856 8,422 11,667 3,587 8,667 23,109 2AK AZ CA CO ID MT NV NM ND OR SD UT WA WY TribesWRAP 2018 Base Case Inventory 

### 7- 24 Version 1, January 2006Figure 7-3. WRAP Point and Area Source 2002 and 2018 VOC Emissions, Version 1050,000100,000150,000200,000250,000300,000350,000400,000450,000500,000

Emissions (tpy)2002-Point5,686 5,451 54,160 91,750 2,113 7,577 2,213 17,574 2,086 27,845 2,542 7,482 18,616 19,663 1,7102018-Point6,633 9,459 54,632 98,630 3,059 10,446 4,113 26,187 2,494 41,344 3,522 13,600 28,013 28,087 2,8642002-Area13,020 108,332 343,778 124,578 123,944 55,104 29,977 219,124 69,795 251,802 42,661 85,320 198,283 140,248 8,4722018-Area16,539 171,415 357,746 173,092 194,210 67,477 47,610 399,205 82,651 334,872 50,072 173,344 253,710 436,885 18,240AK AZ CA CO ID MT NV NM ND OR SD UT WA WY TribesWRAP 2018 Base Case Inventory 

### 7- 25 Version 1, January 2006Figure 7-4. WRAP Point and Area Source 2002 and 2018 PM10-Primary Emissions, Version 1050,000100,000150,000200,000250,000300,000350,000400,000

Emissions (tpy)2002-Point5,932 9,529 29,946 21,125 1,087 8,127 4,763 3,826 3,277 10,442 974 12,904 9,912 31,731 6,3292018-Point2,879 9,889 33,192 28,697 1,736 11,266 6,200 3,392 4,369 13,515 1,044 18,382 12,096 42,819 7,7492002-Area15,042 99,963 179,932 157,875 50,992 153,207 68,009 109,381 287,622 177,460 209,041 30,256 283,542 37,511 1,9782018-Area21,531 137,883 190,987 185,238 62,881 173,892 97,756 144,289 311,273 225,925 226,750 34,279 348,329 45,027 2,062AK AZ CA CO ID MT NV NM ND OR SD UT WA WY TribesWRAP 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 Inventori es for the Western States , Draft Report. Prepared for the Western Regional Air Partnership, Stationary Sources Joint Forum. Prepared by ENVIRON International Corporat ion, Novato, CA. December.

Huntley, 2005. Electronic file se nt via electronic mail from R oy Huntley, U.S. Environmental Protection Agency, Research Triangle Park, NC. August 30.

Johnson and Lakhanpal, 1997. Redesign of California’s Emis sion Forecasting System (CEFS)

. Martin E. Johnson, California Air Resources Boar d, Sacramento, CA, and Dr. Bharat Lakhanpal, Institute for Economic and Environmental Studies, California State Universi ty, Fullerton. Paper presented at the Air and Waste Management Association Specialty Conference on Emission Inventories, Research Triangl e Park, NC. October 28-30, 1997.

Pechan, 2001. Development of Emission Growth Surrogat es and Activity Projections Used in Forecasting Point and Area Source Emissions . Final Report. Prepared for the California Air Resources Board, and the California Environmen tal Protection Agency, Planning and Technical Support Division, by E.H. Pechan & Asso ciates, 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 Fa ctors (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 a ddress: http://www.epa.gov/ttn/ecas/egas5.htm. U.S. Environmental Protection Agency, I nnovative 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 Agen cy, Clean Air Markets Division.

U.S. EPA, 2005b. National Coal-Fired U tility Projects. Internet address: http://www.epa.gov/ ttu/cat/dir1/natcoal.xls. U.S. E nvironmental Protection Agency. May

WRAP, 2005. 2003 Regional SO 2 

### 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 IN VENTORY (VERSION 1) SUMMARIES

### A-1Table A-1. Itemization of Changes Projected to Point Source Emissions Between 2002 and 2018 (NOxin tons),Version 1State2002EmissionsActual Post2002AdjustmentsActual Post2002ControlsGrowthRetirements/ReplacementsGrowth(New/future)PermitLimits2018EmissionsWRAP Point Sources Total NOx1,058,743 1,489 -182 92,310 -87,950 53,585 -15,368 1,107,705Coal-fired EGUs Total 574,643 -1,897 -7 9,504 -737 44,297 -10,755 615,081AKAZ 45,401 0 0 2,850 0 5,897 -4,657 49,491CA 397 431CO 72,513 -2,508 0 -1,617 -203 5,864 -2,643 71,406ID 0 0 0 0 0 1,675 0 1,675MT 35,644 0 0 3,835 -99 4,724 0 44,105NV 38,872 0 0 2,060 0 2,345 -3,455 39,823NM 33,997 0 -7 -10,243 -30 1,675 0 25,392ND 75,950 0 0 1,762 0 5,026 0 82,738OR 8,401 0 0 1,043 0 0 0 9,443SD 14,954 0 0 369 0 0 0 15,323UT 71,388 0 0 -4,094 0 7,439 0 74,732WA 15,463 0 0 -964 0 0 0 14,499WY 84,518 611 0 11,826 -406 6,299 0 102,849Tribes 77,146 0 0 2,678 0 3,351 0 83,174Other EGUs Total 66,689 4,237 019,643 -5,366 9,289 -434 97,977AK 11,077 0 0 3,165 -748 0 -434 13,061AZ 5,819 2,297 0 4,071 -1,406 1,845 0 12,627CA 16,369 20,288CO 4,327 392 0 2,333 -784 0 0 6,268ID 19 91 0 209 -7 0 0 312MT 395 4 0 198 -6 0 0 591NV 13,070 728 0 2,081 -339 2,513 0 18,053NM 3,075 102 0 2,725 -207 443 0 6,139NDOR 497 172 0 337 -34 3,920 0 4,893SD 967 72 0 1,483 -193 0 0 2,329UT 1,891 7 0 540 -445 340 0 2,332WA 5,721 126 0 2,042 -727 227 0 7,389

### A-2Table A-1. Cont.State2002EmissionsActual Post2002AdjustmentsActual Post2002ControlsGrowthRetirements/ReplacementsGrowth(New/future)PermitLimits2018EmissionsWY 3,243 45 0 347 -472 0 0 3,164Tribes 218 200 0 114 0 0 0 532All Other Point SourcesTotal 417,411 -851 -174 63,163 -81,846 0 -4,179 394,647AK 63,394 0 0 11,185 -15,503 0 -4,179 54,898AZ 12,864 -10 0 4,043 -1,276 0 0 15,619CA 87,668 88,796CO 41,029 0 0 6,697 -13,250 0 0 34,476ID 11,468 0 0 2,648 -2,155 0 0 11,959MT 17,376 10 0 3,268 -2,766 0 0 17,888NV 7,833 66 0 3,302 -60 0 0 11,141NM 63,280 -414 -174 6,321 -25,670 0 0 43,343ND 11,475 -661 0 1,395 -3,051 0 0 9,157OR 16,061 -63 0 3,866 -2,439 0 0 17,425SD 4,777 0 0 2,477 -179 0 0 7,074UT 17,765 0 0 4,811 -2,666 0 0 19,910WA 22,448 72 0 6,483 -1,494 0 0 27,509WY 30,122 148 0 4,649 -8,340 0 0 26,579Tribes 9,851 0 0 2,019 -2,996 0 0 8,874

### A-3Table A-2. Itemization of Changes Projected to Point Source Emissions Between 2002 and 2018 (SO2in tons),Version 1StateSection 309 Flag2002EmissionsActual Post2002AdjustmentsActual Post2002 ControlsGrowthRetirements/ReplacementsGrowth(New/future)PermitLimits2018EmissionsWRAP Point Sources Total SO2824,262 3,225 -16,082 51,208 -18,950 44,356 -62,835 832,698Coal-fired EGUs Total 545,350 532 -29 -6,163 -1,477 44,297 -62,088 520,475AKAZ Section 309 Sources 66,642 0 0 -1,838 0 0 -10,688 54,116AZNon-Section 309Sources0 0 0 0 0 5,897 0 5,897CA Section 309 Sources 342 395CANon-Section 309SourcesCO Section 309 Sources 53,891 0 0 -9,041 -328 0 -11,917 32,605CONon-Section 309Sources0 0 0 0 0 5,864 0 5,864ID Section 309 SourcesIDNon-Section 309Sources0 0 0 0 0 1,675 0 1,675MT 21,066 0 0 27 -110 4,724 0 25,707NV Section 309 Sources 49,198 0 0 9,851 0 0 -39,482 19,567NVNon-Section 309Sources0 0 0 0 0 2,345 0 2,345NM Section 309 Sources 18,233 0 -29 -2,664 -45 0 0 15,495NMNon-Section 309Sources0 0 0 0 0 1,675 0 1,675ND 140,534 0 0 7,266 0 5,026 0 152,827OR Section 309 Sources 12,262 0 0 2,672 0 0 0 14,935ORNon-Section 309SourcesSD 11,756 0 0 1,103 0 0 0 12,859UT Section 309 Sources 32,130 0 0 1,801 0 0 0 33,930UTNon-Section 309Sources0 0 0 0 0 7,439 0 7,439WA 19,032 0 0 -12,654 0 0 0 6,378

### A-4Table A-2. Cont.StateSection 309 Flag2002EmissionsActual Post2002AdjustmentsActual Post2002 ControlsGrowthRetirements/ReplacementsGrowth(New/future)PermitLimits2018EmissionsWY Section 309 Sources 83,411 0 0 6,752 -875 0 0 89,288WYNon-Section 309Sources0 532 0 50 -119 6,299 0 6,763Tribes Section 309 Sources 36,854 0 0 -9,489 0 0 0 27,365TribesNon-Section 309Sources0 0 0 0 0 3,351 0 3,351Other EGUs Total 55,858 -1,659 0 -6,067 -2,980 59 -442 45,068AK 3,339 0 0 2,164 -181 0 -24 5,298AZ Section 309 Sources 1,634 0 0 15 -522 0 0 1,128AZNon-Section 309Sources46 66 0 37 0 12 0 160CA Section 309 SourcesCANon-Section 309Sources1,029 1,327CO Section 309 Sources 35,266 -1,819 0 -11,579 0 0 -418 21,451CONon-Section 309Sources96 13 0 52 0 0 0 161ID Section 309 SourcesIDNon-Section 309Sources0 3 0 5 0 0 0 7MT 2,331 0 0 999 0 0 0 3,330NV Section 309 SourcesNVNon-Section 309Sources108 44 0 45 -1 16 0 212NM Section 309 Sources 0 0 0 9 0 0 0 9NMNon-Section 309Sources46 3 0 13 -8 3 0 57OR Section 309 SourcesORNon-Section 309Sources23 6 0 11 0 25 0 65SD 786 4 0 48 -176 0 0 663UT Section 309 Sources 1,121 0 0 16 -359 0 0 778

### A-5Table A-2. Cont.StateSection 309 Flag2002EmissionsActual Post2002AdjustmentsActual Post2002 ControlsGrowthRetirements/ReplacementsGrowth(New/future)PermitLimits2018EmissionsUTNon-Section 309Sources17 0 0 10 0 2 0 29WA 2,791 8 0 914 -145 1 0 3,569WY Section 309 Sources 7,171 0 0 1,149 -1,589 0 0 6,731WYNon-Section 309Sources0 2 0 0 0 0 0 2Tribes Section 309 SourcesTribesNon-Section 309Sources56 11 0 24 0 0 0 91All Other Point Sources Total SO2223,053 4,351 -16,053 63,439 -14,492 0 -306 267,155AK 3,472 0 -766 558 -475 0 -306 2,484AZ Section 309 Sources 25,082 0 0 18,995 0 0 0 44,076AZNon-Section 309Sources 349 126 0 261 -2 0 0 736CA Section 309 Sources 37,565 44,809CANon-Section 309Sources 3,184 3,101CO Section 309 Sources 6,329 0 0 1,396 -1,292 0 0 6,433CONon-Section 309Sources 1,428 0 0 587 -53 0 0 1,963ID Section 309 Sources 17,302 0 -10,228 2,587 -891 0 0 8,771IDNon-Section 309Sources 295 0 0 83 -18 0 0 359MT 13,483 0 0 2,833 -2,297 0 0 14,018NV Section 309 Sources 1,009 0 0 371 0 0 0 1,380NVNon-Section 309Sources 407 71 0 76 -17 0 0 536NM Section 309 Sources 18,152 0 -669 5,369 -624 0 0 22,228NMNon-Section 309Sources 1,005 -16 0 375 -3 0 0 1,361ND 16,134 -362 -4,390 1,621 -3,126 0 0 9,878

### A-6Table A-2. Cont.StateSection 309 Flag2002EmissionsActual Post2002AdjustmentsActual Post2002 ControlsGrowthRetirements/ReplacementsGrowth(New/future)PermitLimits2018EmissionsOR Section 309 Sources 4,784 0 0 1,556 -363 0 0 5,977ORNon-Section 309Sources517 1 0 199 -9 0 0 710SD 1,480 0 0 505 -238 0 0 1,746UT Section 309 Sources 8,809 0 0 2,186 -1,242 0 0 9,754UTNon-Section 309Sources761 0 0 276 -14 0 0 1,023WA 31,146 -73 0 12,359 -2,024 0 0 41,408WY Section 309 Sources 28,101 0 0 10,208 -1,743 0 0 36,567WYNon-Section 309Sources962 4,604 0 240 -57 0 0 5,749Tribes Section 309 Sources 1,015 0 0 638 0 0 0 1,654TribesNon-Section 309Sources282 0 0 157 -4 0 0 435

### A-7 Table A-3. Itemization of Changes Projected to Area Sources Emissions Between 2002 and 2018 (NO x 

### ), 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 N evada 483 0 0 200 683 N ew Mexico 613 0 0 261 874 N orth 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 N evada 962 0 0 68 1,030 N ew 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 N evada 1,037 0 0 157 1,193 N ew Mexico 412 0 0 105 518 N orth 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 N evada 621 0 0 242 863 N ew Mexico 16,821 0 0 4,074 20,894 N orth 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 N evada 62 0 -9 19 72 N ew Mexico 60,446 0 -4,498 82,603 138,551 N orth 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 N evada 124 0 0 53 177 N ew Mexico 340 0 0 72 412 N orth 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 N evada 1,499 0 0 794 2,293 N ew Mexico 1,688 0 0 969 2,657 N orth 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 N evada 118 0 0 7 125 N ew Mexico 144 0 0 6 150 N orth 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 N evada 880 0 0 170 1,051 N ew Mexico 4,886 0 0 3,175 8,060 N orth 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 N ebraska 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 (SO 2 

### ), 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 N evada 11 0 0 0 11 N ew 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 N evada 5 0 0 2 7 N ew Mexico 4 0 0 2 5 N orth 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 N evada 4,935 0 0 348 5,283 N ew 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 N evada 7,301 0 0 1,104 8,404 N ew Mexico 878 0 0 224 1,102 N orth 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 N evada 396 0 0 -251 145 N ew Mexico 2,913 0 0 10,194 13,106 N orth 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 N evada 1 0 N ew Mexico 1,444 17 N orth 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 N evada 1 0 0 0 1 N ew Mexico 2 0 0 0 3 N orth 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 N evada 9 0 0 5 14 N ew Mexico 11 0 0 6 17 N orth 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 N evada 11 0 0 1 11 N ew Mexico 22 0 0 1 23 N orth 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 N evada 286 0 0 33 319 N ew Mexico 714 0 0 172 886 N orth 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 N ebraska 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 (PM 10 

### ), 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 N evada 559 0 0 20 579 N ew Mexico 17,158 0 0 620 17,778 N orth 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 N evada 75 -70 0 2 7 N ew Mexico 47 -43 0 1 5 N orth 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 N evada 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) N ew Mexico 76,802 0 0 28,797 105,599 N orth 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 N evada 109 0 0 27 136 N ew Mexico 619 0 0 152 771 N orth 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 N evada 12,142 0 0 2,548 14,691 N ew Mexico 8,745 0 0 3,539 12,284 N orth 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 N evada 215 0 0 148 363 N ew Mexico 1,159 0 0 336 1,496 N orth 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 N evada 367 0 0 253 620 N ew Mexico 1,936 0 0 562 2,498 N orth 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 N evada 90 -84 0 3 9 N ew Mexico 136 -127 0 5 15 N orth 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 N evada 640 0 0 38 678 N ew Mexico 1,565 0 0 68 1,633 N orth 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 N evada 1,369 -19 0 397 1,747 N ew Mexico 1,214 -125 0 1,122 2,211 N orth 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 N ebraska 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 invent ory was revised on November 18, 2005. This revision was not included in the 2018 base cas e 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 incorporat ed into the 2018 base case calculations. Thus, emissions were not proj ected 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 Reservat ion: The tribal environmental agency indicated operation of a new post-2002 f acility, 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 w ood products facilities (Boise Cascade in White City and La Grande) were not include d in the 2018 base case projections due to problems matching the SCCs in the 2002 invent ory 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 si x new post-2002 facili ties could not be included in the 2018 base case files (NIF a nd IDA) files due to missing county FIPS):

⎯ Burlington Resources, Big Ho rn Wells (WY, ID 00012)

⎯ Chevron USA Table Rock Field (WY)

⎯ Chevron USA Whitney Canyon, Carter Creek (WY)

⎯ ExxonMobil Corporation, Black Canyon (WY)

⎯ Sierra Pacific Industr ies (WA, ID 1118)



## ⎯ Olympic Panel Products (WA, ID 2100284)

### B-1 • Investigate potentially overestimated PM 10 

### from construction/wind erosion (SCC 2311000100) in Washington and Oregon.