Developing the WRAP Point and Area Source Emissions Projections 

for the 2018 Reasonable Progress Milestone for Regional Haze Planning 

Paula G. Fields and Martinus E. Wolf 

Eastern Research Group, Inc. 

8950 Cal Center Drive, Suite 348 

Sacramento, California 95826 

T: (916) 361-6751 

F: (916) 361-6759 

paula.fields@erg.com

Tom Moore 

Western Governors’ Association – Western Regional Air Partnership 

c/o CIRA/Colorado State University 

1375 Campus Delivery 

Fort Collins, Colorado 80523-1375 

T: (970) 491-8837 

mooret@cira.colostate.edu

Lee Gribovicz 

Western Governors’ Association – Western Regional Air Partnership 

3218 Locust Drive 

Cheyenne, Wyoming 82001 

T: (307) 778-4927 

lg@westgov.org 

ABSTRACT 

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

strategies pertaining to regional haze within its geographic domain: States of Alaska, Arizona, 

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

Utah, Washington, Wyoming, and the Native American reservations located within these states. To 

assist the WRAP with this assessment and to provide emission projection inputs into the visibility 

models used by the WRAP’s Regional Modeling Center, the WRAP and its contractors developed a base 

case emissions inventory of point and area sources for the year 2018, and have now updated that 2018 

inventory to a “Preliminary Reasonable Progress” (PRP) data set, to support haze plans due in December 

2007. (Other inventories for other source types, such as mobile sources and fire, were addressed by other 

contractor teams and are not covered in this paper.) 

This paper discusses the methods used to develop the WRAP 2018 Base Case version 1 and 

PRP18 inventories. These activities included data collection from each state, local and tribal (S/L/T) 

agency related to post-2002 “on-the-books” controls resulting from implementation or enforcement of 

consent decrees, new permit limits, new rules/regulations, and Early Action Compacts; determination of 

adjustments needed to reflect post-2002 conditions such as new facilities that had come on line, facilities 

that were retired or closed. Growth factors were developed using information from DOE/EIA and the 

U.S. EPA’s EGAS (Version 5.0) model. 

The results of the 2018 point and area source base case inventory were provided in several 

formats, including Excel pivot tables (i.e., for analysis of results at the state, county, facility, or SCC 

level), National Emissions Inventory Format (NIF) 3.0, and Sparse Matrix Operator Kernel emission 

(SMOKE)/Inventory Data Analyzer (IDA) format. The WRAP 2018 base case inventory for point and 
area source was used by the WRAP RMC to model the planning target for the first regional haze 

planning milestone year. 

As a follow-on project, the 2018 Base Case version 1 inventory was revised in early 2007 to 

correct omissions/errors in the original data set and to update some facility emissions projections, as 

well as growth and control factors. This resulted in the PRP18 inventory, revised Excel pivot tables, and 

NIF and SMOKE/IDA files for modeling. Details on the methods, data, assumptions, and results of the 

work to develop the PRP18 emissions inventory for point and area sources are also discussed in the 

paper. 

INTRODUCTION 

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

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

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

Utah, Washington, Wyoming, and the Native American Reservations located within these states). The 

WRAP’s Stationary Sources Joint Forum (SSJF) sponsored a project to provide WRAP work groups and 

forums with data, information, and assessments necessary for developing regional haze control 

strategies. This project was conducted by Eastern Research Group, Inc. (ERG) and its subcontractors, 

ENVIRON International Corporation and Alpine Geophysics, LLC, for the WRAP SSJF under 

Contracts No. 30204-101 and 30204-116 with the Western Governors’ Association (WGA). This work 

was conducted as part of a multi-task effort for the WRAP SSJF, which included the following tasks: 

• Phase 1: 

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

quality assurance; 

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

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

inventory; 

- Task 2: Control technology analysis; 

- Task 3: Tribal inventories for 2002 and 2018; 

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

- Temporal profiles for WRAP electric generating units. 

• Phase 2: Preliminary Reasonable Progress 2018 analysis (in progress) 

The objective of this project was to develop 2018 base case emissions inventory projection data 

(Phase 1) and technical basis for making preliminary evaluations of reasonable progress toward 

individual Class I area visibility goals by the WRAP (Phase 2). This was done by updating the WRAP 

region 2018 point and area sources emission inventory projections from the 2018 Base Case version 1 

project, completed by Eastern Research Group, Inc. (ERG) in January 2006.1

 The resulting emissions 

inventory is the WRAP region Preliminary Reasonable Progress emissions inventory for 2018 (PRP18). 

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

draft PRP18 analyses for point and area sources. However, in order to provide a comprehensive 

assessment of methods and results, many details pertaining to the other tasks are either discussed or 

incorporated by reference. 

Inventory Characteristics 

The year of 2018 is the first milestone in a 60-year path to restoring visibility in federal Class 1 

areas to natural conditions; the goal of preventing visibility impairment, and remedying existing 

impairment is set forth in the federal Clean Air Act, as amended. This “reasonable progress” milestone 
year for visibility requires all states to submit haze control plans (SIPs), as defined in the federal 

Regional Haze Rule (RHR), and establishes the future year for the WRAP projected inventory for 

modeling purposes. 

The geographic domain covered by this 2018 emissions inventory is shown in Figure 1 and 

includes the following: 

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

and 

• Native American Reservations (NARs) within the WRAP region; the following tribes 

provided emissions inventory data for 2018 projections (i.e., the Arapahoe and Shoshone 

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

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

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

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

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

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

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

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

Reservation, Shoshone-Bannock Tribes of the Fort Hall Reservation, Tohono O’Odham 

Nation, Ute Mountain Ute Tribe of the Ute Mountain Ute Reservation). 

The sources included in the PRP18 inventory are point sources and area (nonpoint) stationary 

sources. Certain area source categories that were not included in this project, but were dealt with in other 

WRAP projects and contracts include the following: 

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

• Windblown dust (SCCs 27014xxxxx and 27301xxxxx); 

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

• Agricultural production livestock (SCCs 2805xxxxxx). 

Also, nonroad mobile sources (e.g., commercial marine, locomotives, aircraft, etc.) were not 

included in this inventory of point and area sources. 

The pollutants included in the PRP18 inventory are nitrogen oxides (NOx), sulfur dioxide (SO2), 

volatile organic compounds (VOC), carbon monoxide (CO), particulate matter (PM) with an 

aerodynamic diameter of less than 10 micrometers (μm) (PM10) and less than 2.5 μm (PM2.5), and 

ammonia (NH3). 

The actual pollutants included in the PRP18 inventory for a given point or area source category 

are dependent upon those pollutants included in the 2002 WRAP inventory for that source. For example, 

if only PM10-Filterable and PM2.5-Filterable (and not PM10-Primary and PM2.5-Primary) are included in 

the 2002 inventory for a given source, then only those pollutants are included in the PRP18 inventory 

(i.e., no 2002 emissions or pollutants were augmented or gap filled). 

METHODOLOGY 

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

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

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

in each step are described as follows: 
Figure 1. WRAP 2018 inventory domain.
Figure 2. 2018 WRAP inventory projection methodology

CA 

Emissions 

CENRAP 

Emissions 

Area 

Source Oil 

WRAP PRP18 Emission Inventory 

EGUs Point Oil and All Others 

Gas 

Fuel All Others 

Combustion 

Agricultural 

Sources 

EGUs Point Oil and All Others 

Gas 

CAMD EGAS DOE USDA EGAS

2002 

Emissions

2018 

Emissions

Other Point Source Information:

* BART and Presumptive BART Limits 

* Permit Limits 

* SO2 Adjustments to §309 Sources 

Adjustments

Control 

Factors

Growth 

Factors

New and Retired Facilities, PM Adjustments, 

CAMD EGU Fixes (IDs, Missing Records)

Oil and Gas 

Growth Factors 

Fuel All Others 

Combustion 

Agricultural 

Sources 

Area Source Oil and 

Gas Emissions 

Revised WRAP 2002 Point and CA Emissions

Area Source Inventory 

(excluding fire and windblown dust) 

2002 Point 

Sources 

2002 Area 

Sources 

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

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

and area source inventory updated in Phase 1 (which was based on the draft U.S. EPA 

National Emissions Inventory [NEI]), and included the following fields: 

- State and county FIPS 

- State facility identifier 

- Emission unit ID 

- Process ID 

- Pollutant code 

- Emission release point ID 

- Emission numeric value 

- Emission unit numerator 

- Tribal code 

- Primary SIC and NAICS 

- Facility name 

- City 

- SCC 

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

• Adjustments: 

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

- Corrections for facilities that retired since 2002 and will not return to operation in the 

future 

- Corrections to facility IDs for electric generating unit (EGU) emissions taken from the 

U.S. EPA’s Clean Air Markets Division (CAMD) database for 2002, and replacement of 

deleted records for non-CAMD units located at facilities with CAMD EGUs 

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

combustion of natural gas) 

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

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

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

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

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

special analysis of EGU growth relative to unit capacity threshold. 

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

rates based on expected equipment lifetimes. Retired equipment replaced by lower-emitting 

new equipment. Unit lifetimes examined for natural gas-fired EGUs; no retirements for coalfired 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). 

• Updates to SO2 emissions for 2002 and/or 2018 as a result of a separate analysis conducted 

for §309 states to address significant (>100 tons) non-EGU sources. 

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

adjustments, control factors, growth factors, retirement and replacement rates, and permit limits, etc. 

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

adjustments made, factors calculated, and results are described in detail in the remaining sections of this 

paper. 

Part of this WRAP 2018 projection process included numerous telephone conferences with the 

WRAP SSJF Projections Workgroup, who provided input and feedback on proposed methods for 
various source sectors, especially electric generating units. Both the draft 2018 base case inventory 

(Phase 1) and the draft PRP18 inventory (Phase 2) were generated and distributed to all affected states 

and tribal entities for review and comment. During the PRP18 process, calls were held with each agency 

to allow discussion of the inventory development to that point, and answer questions. Written comments 

then followed, and were compiled and responded to. All of this information was used to develop the 

draft PRP18 inventory. In some cases, comments received on the 2002 emissions were also addressed, 

and the 2002 inventory database was modified (although these changes were minimized and focused 

only on very significant comments). 

Next, the results of PRP18 inventory were formatted using NIF 3.0 for input in to the WRAP 

Emissions Data Management System (EDMS), and SMOKE/IDA format to be used by the WRAP 

Regional Modeling Center (RMC) for modeling reasonable progress. 

The remainder of this section explains the steps performed to develop the draft PRP18 emissions 

inventory. In some cases, the work was performed under Phase 1 and incorporated into Phase 2. 

Post-2002 Adjustments 

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

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

since the 2002 baseline inventory. These adjustments were associated with 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. 

New, Retired, or Omitted Facilities

Based on information received from the S/L/T agencies, facilities that had either come on-line or 

have been retired since 2002 were added or removed from the inventory. Also, changes were made for 

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

from their 2002 levels (e.g., emissions reported to the U.S. EPA CAMD database but not included in the 

2002 WRAP inventory, uncharacteristically high or low emissions in 2002, duplicate facility record or 

SCC). 

PM Combustion Emission Corrections

U.S. EPA has recently developed and distributed ratios to correct certain natural gas and 

liquefied petroleum gas combustion emission factors.2

 As currently understood, U.S. EPA will apply 

these ratios when finalizing the 2002 National Emissions Inventory (NEI), thus it was felt that the 

WRAP inventory should reflect this change as well, and that the most appropriate place to make this 

change was in the 2018 base case inventory (and not in the 2002 inventory, since this would create an 

inconsistency with most 2002 state emission inventories.) These ratios were applied at the SCC level to 

adjust the WRAP 2002 emissions prior to applying other factors in subsequent steps. Most of the ratios 

affect point sources (8-digit SCCs), although some area sources (10-digit SCCs) are affected as well. 

Most of the impacts are significant, ranging from a 92.3 to 95.4 percent decrease in PM10-Primary and a 

94.2 to 97.2 percent decrease in PM2.5-Primary. 

Corrected CAMD EGU Facility IDs and Added Missing Records

The basis of the WRAP 2002 emissions inventory, and thus the WRAP 2018 version 1 and 

PRP18 inventories, were the data submitted by S/L/T agencies for the U.S. EPA National Emissions 

Inventory (NEI). During the development of the NEI, NOx and SO2 emissions data for EGUs reporting 

to the CAMD database were used instead of the emissions submitted by the agencies. When these NOx
and SO2 emissions data were placed into the NEI, they were assigned a unique facility ID beginning 

with “EGU” in order to distinguish that record from the record submitted by the state. Generally, the 

NOx and SO2 emissions values from CAMD varied only slightly from those submitted by the S/L 

agency (i.e., ERG observed results showing about a 1-2% difference in emissions between CAMD and 

S/L agency emissions). However, the use of the CAMD “EGU” numbering scheme resulted in two 

different facility IDs for the same EGU in the resulting dataset. This eventually became recognized as a 

problem when these data were used in the WRAP 2002 and 2018 pivot tables and in the WRAP 

Emissions Data Management System (EDMS). 

Also, another problem had occurred during the data replacement activities, that resulted in some 

NOx and SO2 emission records for non-CAMD units operating at facilities with CAMD units being 

deleted, causing non-CAMD EGU emissions to be underreported in the resulting dataset. For these 

reasons, ERG performed a task to (1) replace the CAMD “EGU” facility IDs with the S/L agency 

facility IDs as originally submitted to the NEI, and (2) to replace the dropped NOx and SO2 emission 

records in the 2002 inventory database and project these to 2018. These corrections are now reflected in 

the draft WRAP 2018 PRP emissions inventory. 

Post-2002 Control Factors 

Post-2002 control factors were calculated to reflect impacts from on-the-books controls (i.e., 

with implementation dates from 2003 to the end of 2018). These control factors are based on expected or 

actual post-2002 emission reductions from these general areas: 

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

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

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

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

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

Ozone Plan, and implementation of Agricultural Best Management Practices (BMPs) in 

Maricopa County and Salt River SIP in Arizona; and 

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

Emissions Reduction Project. 

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

emission limit, equipment shutdown, or some other condition. 

In addition to the control impacts that could be quantified, there was a significant amount of 

information gathered for other types of control impacts that could not be quantified due to various 

reasons (e.g., dust control requirements in SIPs with no specific emission reductions quantified, 

potential post-2002 control through voluntary reductions not enforceable through permit limits). Details 

on the two most significant initiatives and types of controls considered are described next. 

National Wood Products Initiative

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

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

a suspected nationwide pattern of noncompliance with the PSD regulations under the NSR provisions of 

the Clean Air Act and state rules.3 Within the WRAP region, settlements were reached with Willamette 

Industries (2000) and Boise Cascade Corporation (2002). 

The Willamette facilities affected within the WRAP states were located in Oregon. However, 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. 
The Boise Cascade facilities affected with the WRAP states were located in Idaho, Washington, 

and Oregon. In general, the settlements with both companies required significant VOC reductions (i.e., 

90 to 95 percent), while minimizing NOx and CO emissions. For the most part, VOC reductions were to 

be achieved through regenerative catalytic oxidation (RCO) or regenerative thermal oxidation (RTO) 

installed on the wood/veneer dryers. 

National Petroleum Refinery Initiative

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

address air emissions from the nation’s petroleum refineries.4

 Since 2000, U.S. EPA has entered into 17 

settlements with U.S. companies that refine over 75 percent of the nation’s petroleum. The settlements 

focus on four main areas of the Clean Air Act (CAA): 

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

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

gas combustion devices); 

• Leak detection and repair requirements; and 

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

Table 1 lists the refineries within the WRAP region with CDs that have been negotiated as part 

of the national petroleum refinery initiative. As part of the development of the 2018 base case inventory, 

each CD was reviewed to determine the types of controls, emission limits, applicable equipment, and 

deadline for achieving reductions. However, most of the CD requirements call for preliminary studies to 

determine the most feasible and effective types of controls, installation of equipment that meets NSPS 

requirements, and other types of programmatic approaches. As a result, the specific mass reductions 

expected (e.g., mainly NOx, SO2, and PM) are not provided in the CD, or have yet to be fully negotiated. 

Of the 14 refineries listed in Table 2, specific emission reductions estimates were only available for two: 

BP Amoco Mandan Refinery and (Navajo Refining) Artesia Refinery. 

Table 1. Refineries in WRAP states subject to the national petroleum refinery initiative. 

State EPA Region Refinery 

CO 8 Conoco (Suncor Energy) Refinery (Denver) 

CO 8 Valero (Colorado Refining) Refinery (Denver) 

MT 8 Exxon Mobile (Billings) 

MT 8 Montana Refining (Great Falls) 

MT 8 Conoco Refinery (Billings) 

MT 8 Centex Harvest States (Laurel) 

ND 8 BP Amoco Mandan Refinery 

NM 6 Artesia Refinery 

NM 6 Lea Refinery 

UT 8 Chevron Salt Lake Refinery 

UT 8 BP Amoco Salt Lake City Refinery 

WA 10 Equilon-Puget Sound Refining (Anacortes) 

WA 10 ConocoPhillips (Ferndale) 

WA 10 BP Cherry Point Refinery (Blaine) 

EGU 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. A specialized methodology was developed for coal-fired EGUs in 

order to incorporate detailed information regarding EGU operation, while a generalized approach was 
used for the majority of the other sources. The growth factor and rate analysis methodologies are 

described in detail below. 

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

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

on an EGU-by-EGU basis, rather than for the sector as a whole. The starting point of this effort was the 

revised 2002 WRAP point sources inventory; all EGU sources were then extracted from the overall 

inventory. Under Task 1A of this project, NOx and SO2 emissions data had already been incorporated 

into the inventory for all EGUs that had continuous emissions monitors (CEMs) and reported to the 

Clean Air Markets Division (CAMD) database. The specialized methodology was applied only to 

CAMD EGUs; EGUs not contained in the CAMD database were treated like other non-EGU point 

sources. The methodology details specific to coal-fired CAMD EGUs are presented first, followed by 

the methodology details for all other CAMD EGUs. 

Coal-Fired EGUs

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

commenced operation after 2002 were added to the inventory. Likewise, coal-fired EGUs that retired 

since 2002 were removed from the list of coal-fired EGU sources (i.e., Arapahoe Units #1 and #2). After 

the list of CAMD coal-fired EGUs was compiled, then the following data were downloaded from the 

CAMD website for each of the units: 

• Nameplate unit capacity (megawatts [MW]); 

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

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

• 2002 NOx emissions (tpy); 

• 2002 SO2 emissions (tpy); 

• 2004 NOx emissions (tpy); and 

• 2004 SO2 emissions (tpy). 

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

Equation (1) CF = (gross generated electricity [MWh])/(nameplate unit capacity [MW] × 8760 

hours) 

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

appropriate growth factor (GF) for each coal-fired EGU. The GF value represents how much growth is 

needed to project from the current level of operation up to the CT value. The equation used is as follows: 

Equation (2) GF = CT/CF 

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

need to begin construction of a new EGU to meet additional demand requirements. For coal-fired EGUs, 

a CT value of 0.85 was assumed based on input from the Projections Work Group. The use of this CT 

value was based upon historical precedent; the value was previously used many years ago in the WRAP 

Integrated Assessment System (IAS) and has been carried forward to the present time. 

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

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

Equation (3) Emissions2018 = Emissions2002 × GF 
An expanded methodology was utilized for NOx and SO2. The calculated GF was multiplied by 

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

Equation (4) HI2018 = HI2002 × GF 

The 2004 NOx and SO2 emission rates (ER) in pounds (lbs) per MMBtu were generated by 

dividing 2004 emissions by 2004 HI as follows: 

Equation (5) ERNOx = EmissionsNOx,2004/HI2004

Equation (6) ERSO2 = EmissionsSO2,2004/HI2004

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

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

operation in 2018. Emissions were calculated as follows: 

Equation (7) EmissionsNOx,2018 = HI2018 × ERNOx

Equation (8) EmissionsSO2,2018 = HI2018 × ERSO2 

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

Other EGUs

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

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

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

compiled, then the following data were downloaded from the CAMD website for each of the units: 

● Nameplate unit capacity (MW); 

● 2002 gross electricity generation (MWh); 

● 2002 NOx emissions (tpy); and 

● 2002 SO2 emissions (tpy). 

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

Equation (9) CF = (gross generated electricity [MWh])/(nameplate unit capacity [MW] × 8760 

hours) 

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

appropriate growth factor (GF) for each other EGU. The GF value represents how much growth is 

needed to project from the current level of operation up to the CT value. The equation used is as follows: 

Equation (10) GF = CT/CF 

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

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

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

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

determine the 2018 emissions using the following equation: 

Equation (11) Emissions2018 = Emissions2002 × GF 

Future EGUs

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

identification of future EGUs that will need to be built in order to meet projected electricity demand in 

2018. The basis of the projected electricity demand is the Energy Information Administration’s (EIA) 
annual energy projections. The original analysis for the 2018b inventory relied on EIA projections 

released in 2005 with estimates out to 2025; the most current projections were released in February 2007 

and provide estimates out to 2030.5,6 Historical statistics for 2002 and projections for 2018 were 

obtained from the EIA documentation for 4 of the 13 electricity market module regions: 

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

California, Montana, Nevada, and South Dakota); 

● Rocky Mountain Power Area, Arizona, New Mexico, and Southern Nevada (Arizona and 

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

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

Dakota, Minnesota, Iowa, and Wisconsin); and 

● California (parts of California). 

A comparison of the original and revised generation projections are shown in Tables 2 and 3. 

Table 2. EIA electricity projections (billion kWh)

Electricity Market Module Region 

2018 Required Coal-Fired 

Generation (2005 EIA) 

2018 Required Coal-Fired 

Generation (2007 EIA) 

Californiaa 77.76 83.17 

Northwest Power Poolb 88.37 106.05 

Rocky Mountain Power Areac 162.18 167.05 

Mid-Continent Area Power Pool (ND and SD portions only) 45.61 45.05 

Total 373.92 401.32 

a

 Portions of CA. 

b

 ID, OR, UT, WA, and WY; portions of CA, MT, NV, and SD. 

c

 AZ and CO; portions of NV and NM. 

Table 3. Future electricity generation analysis (billion kWh) 

Growth Parameter 

Original 2018b Analysis 

(2005 EIA) 

Revised PRP18 Analysis 

(2007 EIA) 

2002 Electricity Generation 258.70 258.70 

2018 Electricity Generation 373.92 401.32 

Needed Generation 115.22 142.62 

Unused Capacity at Existing 2002 Facilities 16.60 16.60 

New Capacity at 2003-2004 Facilities 0.66 0.66 

Capacity Currently Under Construction 9.61 9.83 

Capacity Currently Being Permitted 21.82 74.33 

Remaining Capacity to be Allocated 66.53 41.20 

Future EGUs – Coal. The revised analysis of future electricity generation for coal is summarized 

in Table 3, which shows that the required 2018 generation in the revised analysis increased by 7.3% 

(i.e., 27.40 billion kWh) relative to the original analysis. This growth is offset by increased generation 

capacity (i.e., 52.51 billion kWh) that is currently being permitted. A list of facilities that are currently 

under construction or currently being permitted is provided in Table 4. 
Table 4. Coal-fired EGUs under construction or being permitted (MW). 

Original 2018b Analysis Revised PRP18 Analysis 

Facility Name State 

Under 

Construction Being Permitted 

Under 

Construction 

Being 

Permitted 

Rocky Mountain Power/Hardin Gen. Station MT 160 160 

Bull Mountain Plant/Roundup Plant MT 750 780 

Wygen Station #2/Black Hills Corp WY 100 100 

Two Elk (#1)/Bechtel WY 280 280 

Springerville (#3 and #4) AZ 760 800 

Comanche (#3) CO 750 750 

Northern Nevada Energy/Newmont NV 200 200 

NEVCO Energy Company UT 270 270 

Intermountain Power Plant (#3) UT 950 950 

Ft. Morgan/LS Power CO 600 

Akron/AES Power CO 640 

Highwood/Southern Montana Electric MT 270 

White Pine Energy Association/LS Power NV 1,500 

Gascoyne #1/Montana Dakota Utility ND 175 

Gascoyne #2/Montana Dakota Utility ND 500 

South Heart/Great Northern Power ND 500 

Great River Energy ND 66 

Wygen (#3) WY 100 

Two Elk (#2) WY 740 

Dry Fork/ Basin Electric WY 422 

Desert Rock/Sithe Global Power Navajo 

(NM) 

 1,500 

Total 1,290 2,180 2,070 9,983 

 

After considering the facilities listed in Table 4, 41.20 billion kWh of coal-fired electricity 

generation still remained. Assuming that a typical future coal-fired EGU has a nameplate capacity of 

500 MW and operates at the capacity threshold of 0.85 (assumptions that were based upon input from 

the Projections Work Group), then a total of 11 future coal-fired EGUs are required under the revised 

analysis compared to the 18 EGUs estimated with the original analysis. The state-level allocation of the 

future coal-fired EGUs in the original analysis was based upon current state-level capacity (i.e., sum of 

capacity at existing, under construction, and permitted facilities). This same state-level allocation was 

maintained for the revised analysis with three exceptions. 

First, no additional future coal-fired EGUs were assigned to ND; the ND and SD generation 

analysis was conducted separately from the other Western states because ND and SD are in a different 

electricity market module region and lignite coal is preferentially used, instead of bituminous and subbituminous coal. Three future coal-fired EGUs (i.e., total of 1,500 MW) were allocated to ND and SD in 

the original analysis; the newly identified permitted facilities located in ND (i.e., Gascoyne #1 and #2, 

South Heart, and Great River Energy) have a total capacity of 1,241 MW. In addition, the ND and SD 

projected coal-fired electricity generation decreased slightly in the new EIA data. Therefore, no 

additional EGUs were assigned to ND. 

The second exception is that the one future coal-fired EGU assigned to Idaho in the original 

analysis was removed. This is based upon a moratorium on the construction of coal-fired EGUs in 

Idaho. Although this moratorium is not necessarily permanent, WRAP staff indicated that the future 

coal-fired EGU assigned to Idaho should be removed from the revised analysis. 

The third exception is the identification of the Desert Rock/Sithe Global Power EGU consisting 

of two 750 MW units that is being permitted for the Navajo Nation (San Juan County, New Mexico). 

Desert Rock will “replace” the two future coal-fired EGUs allocated to the Navajo Nation in the original 

ERG analysis, as well as one other EGU located elsewhere from the original ERG analysis. Because the 
highest number of allocated future coal-fired EGUs were located in Wyoming, in the previous analysis, 

the number of these EGUs was reduced from three to two in the PRP18 analysis. 

The state-level allocations are presented in Table 5 (both original and revised). WRAP staff 

indicated that the county-level allocations used in the original analysis (based upon announcements of 

plans to build coal-fired EGUs and locations of existing coal-fired EGUs and associated infrastructure) 

should be maintained in the PRP18 analysis. 

Table 5. State-level allocation of future placeholder coal-fired EGUs required to match total electricity 

demand forecasts (number of 500 MW Units) 

State Original 2018b Analysis Revised PRP18 Analysis 

Arizona 2 2 

Colorado 2 2 

Idaho 1 0 

Montana 1 1 

Nevada 1 1 

New Mexico 1 1 

North Dakota 3 0 

Oregon 0 0 

South Dakota 0 0 

Utah 2 2 

Washington 0 0 

Wyoming 3 2 

Tribes (Navajo) 2 0 

Total 18 11 

In addition to new generation projections and future plant allocations, the revised analysis for 

coal-fired EGUs included a review of permitted emission rates for new EGUs. The previous analysis 

used emission rates derived from a range of values from 12 Western facilities that were reported to U.S. 

EPA; the revised analysis uses permitted emission rates collected by WRAP staff. These emission rates 

are shown in Table 6; blank cells in the table indicated no reported permit limit. The permitted emission 

rates were used at each respective permitted EGU. Average emission rates were calculated from these 

collected emission rates and then applied to each of the future allocated EGUs. Three permitted emission 

rates (i.e., PM10 at Springerville #3 and #4 and SO2 at Neil Simpson #2) were excluded from the 

calculation of the average emission rates because they were significant outliers. In addition, the VOC 

rate (0.0022 lb/MMBtu) used in the previous analysis was used instead of the average calculated VOC 

rate (0.0056 lb/MMBtu; based upon only about half of the permitted EGUs). 

The emission rates applied to each of the future allocated EGUs are identified in the bottom row 

of Table 6. 

The emission profile of the future allocated EGUs is presented in Table 7. This emission profile 

is based upon a 500 MW EGU operating year-round at 0.85 capacity with a conversion factor of 10 

MMBtu/MWh. 

Future EGUs – Natural Gas. A similar natural gas-fired electricity demand analysis was also 

developed. The original analysis indicated that a total of 148.77 billion kWh of natural gas-fired 

electricity generation is projected to be required by 2018. A total of 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 came on-line in 2003 or 2004, are currently under construction, or 

are currently being permitted. All of these facilities were added to the 2018 inventory. Because the 

identified generation exceeded the projected 2018 needed generation, no additional future natural gasfired EGUs were expected to be needed in the WRAP Region. An examination of the revised natural 

gas-fired electricity generation projections did not indicate any significant differences. Therefore, no 
new future natural gas-fired EGUs were added to the 2018 inventory beyond those that are currently 

under construction or are currently being permitted. 

Other Point Source Growth Analysis 

In general, for all other non-EGU point sources, growth factors were obtained from U.S. EPA’s 

Economic Growth and Analysis System growth factor model (EGAS), Version 5.0. The EGAS model 

generates SCC-specific growth factors for a specified geographic area, base year (i.e., 2002), and future 

year (i.e., 2018) using various socio-economic data.7,8 EGAS model runs were made for every state 

within the inventory with the exception of California (California growth factors are discussed below). 

Growth factors from the EGAS model runs were matched using SCCs to each inventory record. In the 

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

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

the inventory record. 

Table 6. Permitted emissions rates for coal-fired EGUs (lb/MMBtu) 

Facility Name State NOx SO2 VOC CO PM10

Springerville #3 AZ 0.090 0.090 0.055a

Springerville #4 AZ 0.054 0.077 0.055a

AES Power/Akron CO 0.070 0.100 0.012 

Comanche #3 CO 0.080 0.100 0.0035 0.130 0.013 

LS Power/Ft. Morgan CO 0.070 0.078 0.012 

Roundup Power/Bull Mountain #1 MT 0.070 0.100 0.0030 0.15 0.012 

Roundup Power/Bull Mountain #2 MT 0.070 0.100 0.0030 0.15 0.012 

Southern Montana Electric/Highwood MT 0.070 0.038 0.0030 0.10 0.012 

Nevada Energy/Newmont NV 0.067 0.090 0.150 0.012 

LS Power/ White Pine Energy NV 0.070 0.078 0.012 

Great River Energy ND 0.090 0.060 0.013 

Montana Dakota Utility/Gascoyne #1 ND 0.090 0.038 0.0050 0.150 0.013 

Montana Dakota Utility/Gascoyne #2 ND 0.090 0.060 0.012 

Great Northern Power/South Heart ND 0.090 0.039 0.0025 0.150 0.010 

Otter Tail Power Company SD 0.0036 0.150 0.030 

Intermountain Power #3 UT 0.070 0.090 0.0027 0.15 0.012 

Nevco/Sevier Power UT 0.100 0.022 0.115 0.0154 

Basin Electric/ Dry Fork WY 0.050 0.080 0.0039 0.15 0.012 

Black Hills Power/ Neil Simpson #2 WY 0.023 0.200a 0.0150 0.15 0.02 

Two Elk #1 WY 0.090 0.132 0.0135 0.135 0.018 

Two Elk #2 WY 0.070 0.084 0.0035 0.15 0.015 

Black Hills Power/ Wygen #2 WY 0.070 0.100 0.0100 0.15 0.012 

Black Hills Power/ Wygen #3 WY 0.050 0.090 0.15 0.012 

Average New Unit Rates 0.072 0.078 0.0056 0.143 0.014 

Previous Analysis New Unit Rates 0.090 0.090 0.0022 0.150 0.018 

Current Analysis New Unit Rates 0.072 0.078 0.0022 0.143 0.014 

Table 7. Emissions profile for 500 MW future allocated coal-fired EGU 

Facility Name NOx SO2 VOC CO PM10

Emission Factors from Table 5 (lb/MMBtu) 0.072 0.078 0.0022 0.143 0.014 

Annual Emissions (tpy) 1,340.3 1,452.0 41.3 2,661.9 260.6 

An exception to the use of EGAS growth factors was for the oil and gas point source emissions. 

County-specific growth factors for oil and gas production area sources were developed under Task 1B of 

this project. These growth factors were then applied to the point source inventory by mapping the oil and 

gas area source categories to the corresponding point source SCCs. If an SCC/county-specific growth 
factor did not exist for a particular oil and gas inventory record, then regional growth factors obtained 

from EIA forecasts were applied. 

Area Source Growth Analysis 

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

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

Agriculture (USDA). The EGAS area source projection factors were obtained in the same manner as 

described above for the EGAS point source projection factors. 

As discussed above, the EIA has issued annual energy projections out to the year 2030. 

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), and residential fuel combustion (SCC 

2104xxxxxx). 

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

projections developed by USDA.9

 The USDA projections covered a 12-year period from 2003 to 2014 

and included harvested acreage estimates for eight major field crops (i.e., wheat, barley, corn, rice, oats, 

soybeans, sorghum, and upland cotton). Extrapolation was used to extend the time series back to 2002 

and forward to 2018. The 2002 harvested acreage was estimated to be 226.9 millions acres; while the 

2018 harvested acreage was estimated to be 235.1 millions acres. This corresponds to a growth factor of 

1.0361. 

California Point and Area Sources 

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

than has been described in this report for the other WRAP states. The California Air Resources Board 

(ARB) used the California Emission Forecasting System (CEFS) to develop California’s 2018 base case 

inventory and provided it directly to the WRAP. The California 2018 base case inventory was provided 

by ARB in CEFS output format. CEFS uses two separate forecast algorithms: TREND forecast module 

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

forecasts at the facility/device/process level for use in gridded inventory inputs for modeling. The 

TREND module was used to develop the 2018 base case inventory for the WRAP. The 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 units of tons per day. The pollutants were NOx, 

SO2, reactive organic gases (ROG), CO, PM10, and PM2.5. ROG was taken to be equivalent to VOC; no 

NH3 emissions were provided. 

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

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

IDA fields: 

• Point Sources: 

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

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

- PM10 and PM2.5 records were adjusted according to the U.S. EPA correction factors for 

natural gas combustion. 

- Latitude/longitude coordinates were assigned to the 2018 records using information from 

California’s 2002 inventory (compiled under Task 1A of this project). County centroids 

were assigned to 2018 sources that could not be matched to 2002 records. 
• Area Sources: 

- Certain EICs were removed (i.e., sources not included in this inventory effort – wildfires, 

prescribed burning, forest fires, rangeland burning, agricultural burning, and windblown 

dust). 

- Remaining EICs were mapped to SCCs. 

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

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

formats for use in subsequent steps of the 2018 base case inventory process. 

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

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

retirement and replacement were handled as follows: 

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

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

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

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

from the retired point source; and 

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

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

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

methodology is outlined below, along with specific modifications that were made for the special case of 

EGUs. 

Retirement and replacement was applied to a subset of the point sources contained in the 2002 

WRAP inventory. A list of the point sources and SCCs is provided in Table 8 along with expected 

facility lifetime, annual retirement rate, and projection retirement rate. The annual retirement rate is the 

percentage of sources under a particular SCC that are expected to retire in a given year; the annual 

retirement rate is defined as (1/lifetime). For example, an SCC with an expected lifetime of 50 years has 

an annual retirement rate of 0.02 (i.e., 1/50 years). The projection retirement rate is the percentage of 

sources under a particular SCC that are expected to retire over the period of the projection (i.e., from 

2002 to 2018, or 16 years). In the case of the SCC example above, the projection retirement rate is 0.32 

(i.e., 0.02 × 16 years). 

For each of the SCCs listed in Table 8, reduction factors were developed for NOx, SO2, and 

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

replaced by a new controlled source. Reduction factors were calculated using the following equation: 

Equation (12) Reduction Factor = (Retired Rate – Replacement Rate)/(Retired Rate) 

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

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

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

equations where R is equal to the retirement rate, G is the growth rate, and C is the reduction rate for a 

particular pollutant: 

Equations (13) Total 2018 Emissions = Unretired 2002 Emissions + Retired/Replaced 2002 Emissions 

+ Grown 2018 Emissions 

Equations (14) Total 2018 Emissions = (2002 Emissions × [1 – R]) + (2002 Emissions × R × [1 – C]) 
+ (2002 Emissions × [G – 1] × [1 – C]) 

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

matched the SCCs in Table 8. The one key exception was for EGUs. Instead of applying annual 

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

expected lifetimes as shown in Table 8. 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 with the 

appropriate reduced emission rates. Further input from the WRAP SSJF Projections Work Group and 

other stakeholders indicated that the retirement/replacement methodology used for other point sources 

was not appropriate for coal-fired EGUs (i.e., no coal-fired EGUs in the WRAP region are expected to 

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

inventory. 

Table 8. Retirement and replacement SCCs, lifetimes, and retirement rates 

Category Applicable SCCs 

Lifetime 

(years) 

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 

Other Point Source Projection Information Used to Develop the 2018b and PRP18 Emission 

Inventories 

In addition to the application of post-2002 controls and growth factors in the steps described 

above, several other types of information were incorporated into WRAP’s 2018 inventory. This 

information is described next. 

BART and Presumptive BART Limits

One of the key elements of the work conducted in Phase 2 was to modify the 2018b inventory to 

reflect the impacts from implementation of best available retrofit technology (BART). 

With assistance from WRAP staff, ERG collected information on specific BART limits for all 

sources subject to BART in CO, ND, and UT, as well as the Boardman facility in OR. These were used 
in place of the 2018 projections in the WRAP 2018 PRP inventory. The information related to BART 

limits is summarized in Table 9. 

In addition to these specific BART limits, the presumptive limit of 0.15 lb of SO2/MMBtu was 

applied to all coal-fired EGUs that have been determined to be either subject to BART (but for which a 

specific limit had not yet been determined) or eligible for BART, according to the WRAP’s latest 

WRAP BART Clearinghouse.10 The methodology used to estimate the annual SO2 emissions based on 

the presumptive BART rate was to multiply the rate times the 2018 heat input (MMBtu) from U.S. 

EPA’s CAMD database.11 A summary of changes made as a result of applying presumptive BART 

limits is shown in Table 10. 

Table 9. Summary of known BART limits for subject electric generating units 

2018b Base Case BART Limits Changes Due to BART 

Facility Name and Unit NOx (tpy) SO2 (tpy) NOx (tpy) SO2 (tpy) NOx (tpy) SO2 (tpy) 

Colorado 

Colorado Springs Utilities – Nixon Unit 1 2,416 4,774 2,331 4,073 -85 -701 

Colorado Springs Utilities – Drake Unit 5 838 1,581 752 1,464 -86 -117 

Colorado Springs Utilities – Drake Unit 6 1,493 2,999 1,344 566 -149 -2,433 

Colorado Springs Utilities – Drake Unit 7 1,918 3,991 2,412 941 +494 -3,050 

Public Service – Valmont Unit 5 2,190 709 2,279 879 +89 +170 

Public Service – Cherokee Unit 4 3,834 1,457 4,317 1,750 +483 +293 

Public Service – Comanche Unit 1 3,090 1,858 2,317 1,856 -773 -2 

Public Service – Comanche Unit 2 3,053 1,828 2,587 1,830 -466 +2 

Public Service – Hayden Unit 1 4,083 1,234 3,819 1,265 -264 +31 

Public Service – Hayden Unit 2 4,018 1,530 3,488 1,633 -530 +103 

Public Service – Pawnee Unit 1 4,900 13,700 3,942 2,225 -958 -11,475 

Tri-State Generation – Craig Unit 1 4,685 657 5,426 1,066 +741 +409 

Tri-State Generation – Craig Unit 2 5,866 1,891 5,548 1,051 -318 -840 

Trigen – Colorado Energy Corp Unit 4 464 452 508 733 +44 +281 

Trigen Colorado Energy Corp Unit 5 776 987 677 1,891 -99 +904 

Change in CO Due to BART -1,877 -16,425 

North Dakota 

Coal Creek – Unit 143 5,186 14,706 4,285 3,781 -901 -10,925 

Coal Creek – Unit 144 5,941 12,638 4,104 3,621 -1,837 -9,017 

Leland Olds – Unit 121 2,811 17,322 2,661 3,578 -150 -13,744 

Leland Olds – Unit 122 10,550 33,531 5,904 3,205 -4,646 -30,326 

M.R. Young – Unit 152 9,071 19,997 3,857 2,571 -5,214 -17,426 

M.R. Young – Unit 152 14,332 10,160 6,392 5,661 -7,940 -4,499 

R.M. Heskett – Unit 154 945 2,754 858 1,660 -87 -1,094 

Stanton – Unit 141 2,101 6,296 1,720 1,179 -381 -5,117 

Change in ND Due to BART -21,156 -92,148 

Oregon

PGE Boardman 9,418 14,917 4,960 3,235 -4,458 -11,682 

Change in OR Due to BART -4,458 -11,682 

Utah

Hunter – Unit 1 6,564 2,610 4,851 2,239 -1,713 -371 

Hunter – Unit 2 6,430 2,477 4,734 2,185 -1,696 -292 

Hunter – Unit 3 6,255 950 5,717 1,682 -538 +732 

Huntington – Unit 1 5,757 2,693 4,445 2,052 -1,312 -641 

Huntington – Unit 2 5,294 13,519 3,776 1,743 -1,518 -11,776 

Change in UT Due to BART -6,777 -12,348 

Overall Total Change Due to BARTa -34,268 -132,603 c PGE Boardman post-presumptive BART emissions were calculated by Oregon DEQ based on firing capacity of 5,793 MMBtu/hour and a capacity 

factor of 85%. Email from Mark Fisher, ODEQ to Paula Fields, ERG, April 13, 2007. 
Table 10. Summary of presumptive SO2 BART limits for subject and eligible coal-fired electric 

generating units in the WRAP region. 

Facility Name and Unit 

2018b Base 

Case 

(tons SO2)

a

Presumptive 

BART - Rate 

(lb/MMBtu) 

2018 Heat 

Input 

(MMBtu) 

Presumptive 

BART- Annual 

(tons SO2) 

Alaska – GVEA Healy Power Plant – Unit 1 366 0.15 140 

Change in AK Due to Presumptive BART -226 tons SO2

Arizona 

AZ Electric Power Cooperative, Inc. – Apache 2 1,439 0.15 15,248,939 1,144 

AZ Electric Power Cooperative, Inc. – Apache 3 1,225 0.15 14,487,789 1,087 

Coronado Generating Station – Unit 1B 6,449 0.15 28,551,063 2,141 

Coronado Generating Station – Unit 2B 7,030 0.15 31,029,812 2,327 

Irvington Generating Station – Unit 4 5,374 0.15 13,393,547 1,005 

Change in AZ Due to Presumptive BART -13,813 tons SO2

Montana 

Colstrip Steam Electric Station – Unit 1b 5,517 0.15 29,843,850 2,238 

Colstrip Steam Electric Station – Unit 2b 5,640 0.15 29,276,157 2,196 

PPL Montana – JE Corette Plant – Unit 2 3,757 0.15 14,895,194 1,160 

Change in MT Due to Presumptive BART -9,320 tons SO2

New Mexico 

San Juan Generating Station – Unit 1 2,630 0.15 26,974,922 2,023 

San Juan Generating Station – Unit 2 2,677 0.15 27,460,582 2,060 

San Juan Generating Station – Unit 3 4,288 0.15 43,863,371 3,290 

San Juan Generating Station – Unit 4 4,444 0.15 45,582,346 3,419 

Change in NM Due to Presumptive BART -3,247 tons SO2

South Dakota -- Otter Tail Power Company 12,220 0.15 37,111,681 2,783 

Change in SD Due to Presumptive BART -9,437 tons SO2

Wyoming 

Basin Electric – Laramie River Station – Unit 1 4,043 0.15 48,061,878 3,605 

Basin Electric – Laramie River Station – Unit 2 4,096 0.15 48,607,657 3,646 

Basin Electric – Laramie River Station – Unit 3 3,789 0.15 44,354,715 3,327 

Pacificorp – Dave Johnston – Unit 4 8,555 0.22c 19,819,756 2,180 

Pacificorp – Dave Johnston – Unit 2 4,250 0.15c 30,030,412 2,252 

Pacificorp – Jim Bridger – Unit 1 7,069 0.15c 45,621,694 3,422 

Pacificorp – Jim Bridger – Unit 2 6,906 0.15c 43,634,528 3,273 

Pacificorp – Jim Bridger – Unit 3 6,537 0.15c 46,238,491 3,468 

Pacificorp – Jim Bridger – Unit 4 4,107 0.15c 45,075,468 3,381 

Pacificorp – Naughton Power Plant – Unit 1 6,518 0.41c 12,813,313 2,627 

Pacificorp – Naughton Power Plant – Unit 2 8,694 0.41c 16,715,747 3,427 

Pacificorp – Naughton Power Plant – Unit 3 5,980 0.21c 28,425,577 2,985 

Pacificorp – Wyodak – Unit 1 8,281 0.32c 35,685,720 5,710 

Change in WY Due to Presumptive BART -35,522 tons SO2

EPA Sources on Navajo Tribal Land located in New Mexico 

Four Corners Power Plant – Unit 1 1,385 0.21d 14,846,431 1,559 

Four Corners Power Plant – Unit 2 1,687 0.21d 16,632,804 1,746 

Four Corners Power Plant – Unit 3 2,122 0.21d 19,873,582 2,087 

Four Corners Power Plant – Unit 4 8,509 0.21d 57,929,739 6,083 

Four Corners Power Plant – Unit 5 9,729 0.21d 56,778,871 5,962 

Change on Navajo Tribal Land Due to SO2 Control 

Levels Proposed by EPA -5,995 tons SO2

Overall Total Change Due to Presumptive BART -77,560 tons SO2

e

a

2018-18b emissions are based on 2004 heat input data from CAMD. b

Colstrip Units 1 and 2 fire on both coal and petroleum coke. The BART limit was applied to the combined heat input for 2018 and will be applied across 

both SCCs based on a percentage of the 2018-18b emissions. c

Pacificorp unit emission rates are from BART control analysis performed by Pacificorp. 

d

Emission rate is based on current U.S. EPA proposal for APS Four Corners. http://www.epa.gov/fedrgstr/EPA-AIR/2006/September/Day-12/a15097.pdf e

Totals may not equal sum of columns due to rounding.
Several EGUs either have permit limits below the presumptive SO2 BART limit, or they 

operated below the presumptive BART level in 2006. Therefore, no presumptive SO2 BART reductions 

were applied for the 2018 PRP inventory for these BART subject or eligible sources: 

• Cholla Power Plant (AZ) Units 1-4 

• Navajo Generating Station (U.S. EPA source on Navajo Tribal land, located in northern AZ) 

Units 1-3 

• Reid Gardner (NV) Units 1-3 

• Mohave Power Plant (NV) Units 1-2 

• TransAlta Centralia Units (WA) BW21 and BW22 

Non-EGU SO2 Changes in §309 states

A study was conducted for the WRAP SSJF in 2006 by Pechan to update the 2018 SO2 emission 

projections (originally estimated by ERG and ENVIRON) for purposes of establishing SO2 milestones 

for the 309 State Regional Haze State Implementation Plans.11 The focus of that project was to update 

some of the projected 2018 version 1 emissions estimates for non-utility sources emitting more than 100 

tons of SO2 in the five milestone states (AZ, NM, UT, and WY). (Note that changes by Pechan to 

sources in OR were made as part of this project, although OR is no longer a §309 state.) The Pechan 

project resulted in revised 2018 SO2 emissions from these industries: copper smelters, lime 

manufacturing, pulp and paper, oil and gas, chemical manufacturing, petroleum refining, and cement 

production. 

For the WRAP PRP18 inventory, ERG summarized the changes from the Pechan report by state, 

distributed these to the applicable S/L/T agencies as part of the collection of comments process 

described above, and requested that each agency confirm these changes. Also, ERG obtained SCC level 

changes from Pechan, in order to make the detailed changes at the SCC level for this WRAP PRP18 

inventory project. 

RESULTS 

The summary results of the PRP18 emissions inventory are presented in Table 11 (point sources) 

and Table 12 (area sources). The summary results of the 2018b base case emissions inventory are also 

shown in Table 11 and 12, along with changes from Phase 2 of this project. The resulting changes 

between the 2018 base case emissions inventory and the PRP18 emissions inventory are also graphically 

shown for NOx, SO2, and PM10 in Figures 3 and 4. From Figure 3, it is clear that the most significant 

point source changes are for SO2 emissions. Likewise, from Figure 4, it is shown that the most 

significant area source changes are for NOx emissions. 
Table 11. Summary of draft 2018b base case emissions inventory, net changes made by state and resulting WRAP PRP

point sources (tons per year) 

State NOx SO2 VOC CO PM10 

WRAP 2018b Base Case Emissions Inventory (TPY): 

AK 67,959.43 7,781.59 6,637.31 25,881.08 2,884.91 

AZ 77,738.22 94,407.68 9,466.23 33,242.90 9,893.22 

CA 109,514.89 49,631.75 54,631.70 123,795.15 33,191.68 CO 112,239.70 69,213.14 98,629.89 58,211.27 28,697.25 

ID 14,048.16 25,467.31 3,060.02 38,019.05 1,741.19 

MT 62,583.10 45,321.07 10,445.96 62,353.62 11,266.02 

ND 92,097.99 162,704.76 2,493.21 22,589.46 4,369.38 

NM 74,874.05 41,392.29 26,187.38 57,506.25 3,391.82 

NV 69,016.45 24,040.65 4,112.87 20,745.67 6,200.35 

OR 31,760.79 21,686.48 41,168.92 53,654.91 13,517.81 

SD 24,725.86 15,268.20 3,522.79 6,858.87 1,044.86 

UT 96,974.44 52,952.88 13,599.53 98,373.32 18,381.76 

WA 49,396.97 51,355.44 28,013.12 187,705.34 12,096.19 WY 132,115.76 145,099.58 27,541.60 60,503.77 42,819.39 

Tribal 92,580.06 32,894.77 2,864.32 12,987.96 7,748.84 

Net Changes to 2018b Base Case Emissions Inventory (TPY): 

AK -226.34 -1,118.54 

AZ -4,666.91 -24,070.72 211.84 796.24 984.32 

CA CO 1,120.93 -12,234.64 -21,100.97 5,782.57 -401.45 

ID -1,675.35 -15,522.06 -41.37 -2,792.25 -335.07 

MT -217.91 -8,840.88 55.17 1,000.74 -131.79 

ND -21,041.97 -95,626.23 1.79 -1,593.89 1,020.96 

NM -273.61 -9,011.88 -0.04 -130.31 -74.46 

NV -1,391.45 4,126.30 -247.12 6,968.94 -164.13 

OR -6,813.49 -13,734.49 -530.41 -3,502.51 -433.54 

SD 1.00 -9,433.88 0.00 

UT -17,213.16 -15,014.36 -406.18 -1,920.34 -2,903.88 

WA 59.34 -13,911.46 -1,801.03 -80,108.37 -2,370.47 WY 1,099.95 -49,955.64 728.59 4,278.61 19.80 

Tribal 7,922.92 -4,495.17 317.51 572.15 1,293.29 

WRAP PRP18 Emissions Inventory (TPY): 

AK 67,959.43 7,555.25 6,637.31 25,881.08 1,766.37 

AZ 73,071.31 70,336.96 9,678.07 34,039.14 10,877.54 

CA 109,514.89 49,631.75 54,631.70 123,795.15 33,191.68 
Table 11. Continued 

State NOx SO2 VOC CO PM10 

CO 113,360.63 56,978.50 77,528.92 63,993.84 28,295.80 

ID 12,372.81 9,945.25 3,018.65 35,226.80 1,406.12 

MT 62,365.19 36,480.19 10,501.13 63,354.36 11,134.23 

ND 71,056.02 67,078.53 2,495.01 20,995.57 5,390.34 

NM 74,600.43 32,380.40 26,187.34 57,375.95 3,317.36 

NV 67,625.00 28,166.95 3,865.76 27,714.61 6,036.22 

OR 24,947.30 7,951.99 40,638.51 50,152.40 13,084.26 

SD 24,726.86 5,834.32 3,522.79 6,858.87 1,044.86 

UT 79,761.28 37,938.52 13,193.35 96,452.98 15,477.88 

WA 49,456.32 37,443.99 26,212.09 107,596.98 9,725.72 WY 133,215.71 95,143.95 28,270.19 64,782.38 42,839.19 

Tribal 100,502.99 28,399.61 3,181.83 13,560.10 9,042.14 
Table 12. Summary of draft 2018b base case emissions inventory, net changes made by state and resulting WRAP PRP

sources (tons per year) 

State NOx SO2 VOC CO PM10 

WRAP 2018b Base Case Emissions Inventory 

AK 9,293.35 6,043.71 16,539.14 29,055.82 21,531.05 

AZ 12,558.62 3,410.26 171,414.85 70,097.25 137,883.20 

CA 117,716.62 9,772.22 357,745.55 384,966.70 190,987.09 CO 44,040.52 7,498.70 173,092.43 94,594.76 185,238.34 

ID 42,067.89 2,720.52 194,210.06 40,971.48 62,880.57 

MT 36,052.99 3,432.14 67,476.71 41,415.20 173,892.25 

ND 21,128.65 5,856.27 82,650.71 21,606.83 311,272.53 

NM 172,318.92 15,753.24 399,205.01 47,997.02 144,289.23 

NV 7,487.60 14,194.42 47,609.85 17,479.33 97,755.67 

OR 17,027.19 8,421.88 334,872.12 380,523.74 225,924.68 

SD 7,206.93 11,667.18 50,072.09 25,112.44 226,750.11 

UT 21,635.69 3,586.90 173,344.04 45,962.17 34,279.28 

WA 22,745.95 8,667.27 253,709.83 252,446.63 348,329.35 WY 79,196.38 23,109.16 436,884.86 34,463.27 45,027.21 

Tribal 6,639.04 2.08 18,240.28 563.99 2,062.46 

Net Changes to 2018b Base Case Emissions Inventory 

AK -566.98 -1.30 -91.90 -0.47 

AZ 224.89 -2.05 -505.80 7,865.47 -1,122.85 

CA CO -27,617.20 -8.48 -36,938.50 -4,961.40 

ID 332.78 

MT -30,491.27 -8.03 -7,517.34 -1,636.50 

ND -8,620.46 -2.75 -13,003.22 -132.08 

NM -138,346.67 -16.49 -327,913.29 -5,934.23 -2,689.07 

NV -72.09 -0.04 5,407.50 -1.44 

OR -48.18 -19.37 -1.39 

SD -2,759.18 -7,582.81 -394.53 -1,041.42 -2,673.97 

UT -13,153.59 -4.65 -95,061.48 -1,349.88 

WA WY -59,439.61 -15.61 -403,798.30 -3,962.23 

Tribal 

WRAP PRP18 Emissions Inventory 

AK 8,726.37 6,042.41 16,447.24 29,055.35 21,531.05 

AZ 12,783.50 3,408.20 170,909.05 77,962.72 136,760.35 

CA 117,716.62 9,772.22 357,745.55 384,966.70 190,987.09 CO 16,423.32 7,490.22 136,153.94 89,633.36 185,238.34 
Table 12. Continued 

State NOx SO2 VOC CO PM10 

ID 42,067.89 3,053.31 194,210.06 40,971.48 62,880.57 

MT 5,561.72 3,424.11 59,959.38 39,778.71 173,892.25 

ND 12,508.19 5,853.53 69,647.48 21,474.75 311,272.53 

NM 33,972.25 15,736.76 71,291.71 42,062.80 141,600.16 

NV 7,415.51 14,194.38 53,017.35 17,477.89 97,755.67 

OR 16,979.01 8,421.88 334,852.75 380,522.35 225,924.68 

SD 4,447.75 4,084.37 49,677.55 24,071.02 224,076.14 

UT 8,482.11 3,582.25 78,282.56 44,612.29 34,279.28 

WA 22,745.95 8,667.27 253,709.83 252,446.63 348,329.35 WY 19,756.77 23,093.55 33,086.56 30,501.05 45,027.21 

Tribal 6,639.04 2.08 18,240.28 563.99 2,062.46 
Figure 3. Emissions projection changes between 2018b inventory and PRP18 inventory - point sources 

4 

Figure 4. Emissions projection changes between 2018b inventory and PRP inventory - area sources 

1,107,625

839,218

197,245

1,064,536

571,266

192,630

-4,615

-267,951

-43,090

-400,000

-200,000

0

200,000

400,000

600,000

800,000

1,000,000

1,200,000

NOx (tpy) SO2 (tpy) PM10 (tpy)

2018b

Change

PRP18

617,116

124,136

2,208,103

116,827

2,201,617

-7,309 -6,486

-280,890

336,226

-500,000

0

500,000

1,000,000

1,500,000

2,000,000

2,500,000

NOx (tpy) SO2 (tpy) PM10 (tpy)

2018b

Change

PRP18
NEXT STEPS 

The next steps in finalizing the PRP18 inventory include incorporating comments received from 

the S/L/T agencies on the draft PRP18, which is currently in process. Then, the final SMOKE/IDA files 

will be developed and submitted to the WRAP RMC. Next, new pivot tables in Microsoft Excel will be 

developed and posted on the WRAP Web site for access by the S/L/T agencies during their visibility SIP 

development process in the coming year. 

Finally, NIF files will be developed for the PRP18 and for a revised 2002 inventory. The NIF 

files will be uploaded to the WRAP EDMS for easy on-line access. 

The WRAP plans to complete two additional regional emissions and modeling analyses to 

support Western haze planning in late 2007 or early 2008. A final baseline period (2000-04) emissions 

and modeling analysis will be conducted in conjunction with a final Reasonable Progress (2018) 

emissions and modeling analysis. The final baseline period analyses will have a limited focus, on 

correcting inventory errors that affect the Reasonable Progress demonstration, as the inventory from that 

time period will have been supplanted by more recent and complete data. The associated final 2018 

Reasonable Progress analysis will be completed when the 13 contiguous WRAP states and U.S. EPA are 

able to provide their permitted emission limits for sources subject to BART requirements. Other 

remaining 2018 inventory projection corrections will also be applied in those analyses. These final 

analyses for regional haze planning in the West will conducted simultaneously. 

REFERENCES 

1. “WRAP Point and Area Source Emissions Projections for the 2018 Base Case Inventory, 

Version 1.” Prepared for the Western Governors’ Association and the Western Regional Air 

Partnership, Stationary Sources Joint Forum. Prepared by Eastern Research Group, Inc. January 

25, 2006. Available on the Internet at: http://wrapair.org/forums/ssjf/documents/eictts/ 

projections.html. 

2. Huntley, R. Electronic file sent via electronic mail from Roy Huntley, U.S. Environmental 

Protection Agency, Research Triangle Park, NC. August 30, 2005. 

3. National Wood Products Initiative. Information available on the Internet at: http://www.epa.gov/ 

compliance/resources/cases/civil/caa/wood/index.html 

4. National Petroleum Refinery Initiative. Information available on the Internet at: 

http://www.epa.gov/compliance/resources/cases/civil/caa/oil/index.html 

5. Annual Energy Outlook 2005 With Projections to 2025. Energy Information Administration, 

Washington, DC. February 2005; DOE/EIA-0383(2005). 

6. Annual Energy Outlook 2007 With Projections to 2030. Energy Information Administration, 

Washington, DC. February 2007; DOE/EIA-0383(2007). 

7. EGAS Website. U.S. Environmental Protection Agency, Innovative Strategies and Economics 

Group. Internet address: http://www.epa.gov/ttn/ecas/egas5.htm. 

8. “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 2004. 

9. USDA Agricultural Baseline Projections to 2014. U.S. Department of Agriculture, Office of the 

Chief Economist. February 2005; Baseline Report OCE-2005-1. 

10. WRAP BART Clearinghouse. Information available on the Internet at: http://www.wrapair.org

11. Cummins, P. Listing of 2006 CAMD heat input rates provided by Pat Cummins, Western 

Regional Air Partnership. April 25, 2007. 
12. “2018 SO2 Emissions Evaluation for Non-Utility Point Sources, Final Report.” Prepared for the 

Western Regional Air Partnership, Stationary Sources Joint Forum. Prepared by Pechan and 

Associates. October, 2006. Available on the Internet at: http://www.wrapair.org/forums/ssjf/ 

documents/eictts/projections.html 

KEY WORDS 

Projections 

WRAP 

Modeling inventory 

Point sources 

Area sources