### Developing the WRAP Point and A rea Source Emissions Projections for the 2018 Reasonable Progress Milest one 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 Partne rship (WRAP) is assessing im pacts and evaluating control strategies pertaining to regional haze within its geographic domain : States of Alaska, Arizona, California, Colorado, Idaho, Montan a, 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 prov ide emission projection i nputs 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 de velop the WRAP 2018 Base Case version 1 and PRP18 inventories. These activities included data coll ection 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/regulati ons, 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. Grow th 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 ba se 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 andarea source was used by the WRAP RMC to model th e planning target for th e first regional haze planning milestone year.

As a follow-on project, the 2018 Base Case vers ion 1 inventory was revised in early 2007 to correct omissions/errors in the original data set a nd to update some facility emissions projections, as well as growth and control factors. This resulted in the PRP18 inventory, revise d 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 Partne rship (WRAP) is assessing im pacts and evaluating control strategies pertaining to regional haze within its geographic doma in (States of Alaska, Arizona, California, Colorado, Idaho, Montan a, Nevada, New Mexico, North Dakota, Oregon, South Dakota, Utah, Washington, Wyoming, and the Native American Re servations located with in 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 conduc ted by Eastern Research Group, Inc. (ERG) and its subcontractors, ENVIRON International Corpor ation and Alpine Geophysics, LLC, for the WRAP SSJF under Contracts No. 30204-101 and 30204-116 with the Western Governors’ Asso ciation (WGA). This work was conducted as part of a multi-task effort for th e WRAP SSJF, which included the following tasks:

• Phase 1:

- 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.

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

The objective of this project was to develop 2018 base case emissions i nventory projection data (Phase 1) and technical basis for making prelimin ary evaluations of reasonable progress toward individual Class I area visibil ity goals by the WRAP (Phase 2). This was done by updating the WRAP region 2018 point and area sources em ission inventory projections from the 2018 Base Case version 1 project, completed by Eastern Resear ch Group, Inc. (ERG) in January 2006. 1 The resulting emissions inventory is the WRAP region Pr eliminary Reasonable Progress emi ssions inventory for 2018 (PRP18).

This paper contains details pertai ning to the data and methods us ed, 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 pert aining 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 visib ility in federal Class 1 areas to natural conditions; the goal of preven ting visibility impairment, and remedying existing impairment is set forth in the federal Clean Air Ac t, as amended. This “reasonable progress” milestoneyear for visibility requires all states to submit haze control plans (SIPs), as defined in the federal Regional Haze Rule (RHR), and establishes the futu re year for the WRAP projected inventory for modeling purposes.

The geographic domain covered by this 2018 emi ssions inventory is sh own 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) with in the WRAP region; the following tribes provided emissions inventory data for 2018 pr ojections (i.e., the Ar apahoe and Shoshone Tribes of the Wind River Reservation, the Assi niboine 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 th e Coeur d’Alene Reservation, Confederated Tribes and Bands of the Yakama Nation, Confed erated 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 In dian Reservation, La Posta Band of Diegueno Mission Indians of the La Posta Indian Re servation, Navajo Nation, Pueblo of Laguna, Pueblo of Santa Ana, Salt River Pima-Mar icopa 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 PRP 18 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 contract s include the following:

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

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

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

• Agricultural production livestock (SCCs 2805xxxxxx).

Also, nonroad mobile sources (e .g., commercial marine, locomotiv es, aircraft, etc.) were not included in this inventory of point and area sources.

The pollutants included in the PRP18 inventory are nitrogen oxides (NO x ), sulfur dioxide (SO 2 ), volatile organic compounds (VOC), carbon monoxi de (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 PRP18 inve ntory for a given point or area source category are dependent upon those pollu tants included in the 2002 WRAP invent ory 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 inventory for a given source, then only thos e 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 th e WRAP 2002 emissions i nventory to the year 2018. The data and calculations for each of the laye rs 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 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 Point Source Information: * BART and Presumptive BART Limits * Permit Limits * SO2 Adjustments to §309 Sources Adjustments

Control Factors

Growth Factors New and Retired Faciliti es, PM Adjustments, CAMD EGU Fixes ( IDs , Missin g Records )

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 Adjustments• 2002 Emissions Inventory. This information wa s 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 Invent ory [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 (E GU) emissions taken from the U.S. EPA’s Clean Air Markets Division (C AMD) database for 2002, and replacement of deleted records for non-CAMD units loca ted 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 othe r 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 scenar ios that have yet to be determined.

• Growth factors: SCC-specific growth factors developed from EGAS projection factor model; special analysis of EGU growth re lative 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 na tural 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 SO 2 emissions for 2002 and/or 2018 as a resu lt of a separate analysis conducted for §309 states to address significant (>100 tons) non-EGU sources.

An extensive data collection effort was conduc ted to identify the info rmation needs for the adjustments, control factors, grow th factors, retirement and replacem ent rates, and permit limits, etc. needed to develop the various factors and data ne eded for the projections. The actual data collected, adjustments made, factors cal culated, and results are described in de tail in the remaining sections of this
paper.
Part of this WRAP 2018 proj ection process included numerous telephone conferences with the WRAP SSJF Projections Workgr oup, who provided input and feedback on proposed methods forvarious source sectors, especially electric genera ting units. Both the draft 2018 base case inventory (Phase 1) and the draft PRP18 inventory (Phase 2) we re generated and distributed to all affected states and tribal entities for review and comment. During th e 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. A ll of this information was used to develop the draft PRP18 inventory. In some cases, comments r eceived 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 form atted using NIF 3.0 for input in to the WRAP Emissions Data Management System (EDMS), a nd SMOKE/IDA format to be used by the WRAP Regional Modeling Center (RMC) for modeling reasonable progress.

The remainder of this section explains the step s performed to develop th e draft PRP18 emissions inventory. In some cases, the work was performe d 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 change s in sources and emissions that have occurred since the 2002 baseline inventory. These adjustments we re 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 agen cies, facilities that had either come on-line or have been retired since 2002 were added or removed from the invent ory. Also, changes were made for emissions at facilities (or specific un its at facilities) that, for various reasons, needed to be corrected from their 2002 levels (e.g., emissions reported to th e U.S. EPA CAMD database but not included in the 2002 WRAP inventory, uncharacteristi cally high or low emissions in 2002, duplicate facility record or SCC).

PM Combustion Emission Corrections

U.S. EPA has recently develope d and distributed ratios to co rrect certain natural gas and liquefied petroleum gas co mbustion emission factors. 2 As currently understood, U.S. EPA will apply these ratios when finalizing the 2002 National Emissi ons 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 inve ntory (and not in the 2002 invent ory, since this would create an inconsistency with most 2002 state emission inventories. ) These ratios were app lied at the SCC level to adjust the WRAP 2002 emissions prior to applying other factors in subsequent step s. Most of the ratios affect point sources (8-digit SCCs ), although some area sources (10-di git SCCs) are affected as well. Most of the impacts are significant, ranging from a 92.3 to 95.4 per cent decrease in PM 10 -Primary and a 94.2 to 97.2 percent decrease in PM 2.5 -Primary.

Corrected CAMD EGU Facility IDs and Added Missing Records

The basis of the WRAP 2002 emissions invent ory, 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, NO x and SO 2 emissions data for EGUs reporting to the CAMD database were used instead of th e emissions submitted by the agencies. When these NO xand SO 2 emissions data were placed in to 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 NO x and SO 2 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 NO x and SO 2 emission records for non-CAMD units operati ng at facilities with CAMD units being deleted, causing non-CAMD EGU emissions to be underr eported in the resulti ng 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 NO x and SO 2 emission records in the 2002 inventor y database and project these to 2018. Th ese corrections are now reflected in the draft WRAP 2018 PRP emissions inventory.

Post-2002 Control Factors

Post-2002 control factors were calculated to re flect 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) 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 Agricultur al Best Management Practices (BMPs) in Maricopa County and Salt River SIP in Arizona; and

• Public/private stakeholder agreements for im proving 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 shutdow n, 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 imp acts that could not be quantified due to various reasons (e.g., dust contro l 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 incl udes manufacturers of plywood, panelboard, medium density fiberboard (MDF), and oriented strand board. In 1988, the U.S. EPA be gan 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, settleme nts were reached with Willamette Industries (2000) and Boise Ca scade Corporation (2002).

The Willamette facilities affected within the WR AP states were located in Oregon. However, all of the operating Willamette facilities have achieved co mpliance with their respective settlement CDs as of 2002; thus, it is not necessary to reflect on-the-books controls.The Boise Cascade facilities aff ected 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 NO x and CO emissions. For the most part, VOC reductions were to be achieved through regenerative catalytic oxidation (RCO) or rege nerative 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 cr acking units and heaters and boilers);

• New Source Performance Standards (NSPS) (affecti ng 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 with in the WRAP region with CDs that have been negotiated as part of the national petroleum refinery initiative. As pa rt of the development of the 2018 base case inventory, each CD was reviewed to determine the types of c ontrols, emission limits, applicable equipment, and deadline for achieving reductions. However, most of th e CD requirements call for preliminary studies to determine the most feasible and effective types of controls, installation of e quipment that meets NSPS requirements, and other types of programmatic a pproaches. As a result, the specific mass reductions expected (e.g., mainly NO x , SO 2 , 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 estimat es were only available for two: BP Amoco Mandan Refinery and (Nav ajo Refining) Arte sia 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 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)

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 me thodology was developed for coal-fired EGUs in order to incorporate detailed information regard ing EGU operation, while a ge neralized approach wasused for the majority of the other sources. The gr owth factor and rate an alysis methodologies are described in detail below.

Because EGUs are the largest source of NO x and SO 2 in the WRAP inventory domain, considerable effort was spent to de velop projections for them. In part icular, 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, NO x and SO 2 emissions data had already been incorporated into the inventory for all EGUs th at had continuous emissions monitors (CEMs) and reported to the Clean Air Markets Division (CAMD) database. Th e specialized methodology was applied only to CAMD EGUs; EGUs not contained in the CAMD da tabase were treated lik e other non-EGU point sources. The methodology details spec ific 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 inve ntory. 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 e ach 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 valu e 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 ne w EGU to meet additional demand re quirements. 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 prec edent; the value was previously us ed many years ago in the WRAP Integrated Assessment System (IAS) and has be en 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:

Equation (3) Emissions 2018 = Emissions 2002 × GFAn 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:

Equation (4) HI 2018 = HI 2002 × GF

The 2004 NO x and SO 2 emission rates (ER) in pounds (l bs) per MMBtu were generated by dividing 2004 emissions by 2004 HI as follows:

Equation (5) ER NOx = Emissions NOx,2004 /HI 2004 Equation (6) 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 rates for coal-fir ed EGUs, were used to represent coal-fired EGU operation in 2018. Emissions were calculated as follows:

Equation (7) Emissions NOx,2018 = HI 2018 × ER NOx Equation (8) Emissions SO2,2018 = HI 2018 × ER SO2 As a final step, projected emissions were redu ced by any relevant emission caps or permit limits.

Other EGUs

The methodology used to project other EGUs was si milar to that used for the coal-fired EGUs. As with the coal-fired EGUs, the other EGUs we re extracted from the overall inventory with adjustments made for post-2002 new EGUs and reti red 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 NO x emissions (tpy); and

● 2002 SO 2 emissions (tpy).

The 2002 capacity factor (CF) was calc ulated 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 othe r 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 na tural gas-fired combined cycle EGUs.

For all pollutants, the 2002 emissions were then mu ltiplied by the calculated GF value in order to determine the 2018 emissions using the following equation:

Equation (11) Emissions 2018 = Emissions 2002 × 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 mark et module regions:

● Northwest Power Pool (Idaho, Oregon, Uta h, Washington, Wyoming; and parts of California, Montana, Nevada, and South Dakota);

● 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).

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

Table 2. EIA electricity proj ections (billion kWh)

Electricity Market Module Region 2018 Required Coal-Fired Generation (2005 EIA) 2018 Required Coal-Fired Generation (2007 EIA)
California a 77.76 83.17

Northwest Power Pool b 88.37 106.05 Rocky Mountain Power Area c 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 genera tion 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 futu re electricity generation for coal is summarized in Table 3, which shows that the required 2018 genera tion in the revised analysis increased by 7.3% (i.e., 27.40 billion kWh) relativ e to the original analysis. This growth is o ffset by increased generation capacity (i.e., 52.51 billion kWh) that is currently bei ng permitted. A list of facilities that are currently under construction or currently bei ng 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 fa cilities listed in Tabl e 4, 41.20 billion kWh of coal-fired electricity generation still remained. Assuming that a typical future coal-fi red 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 E GUs 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 wa s based upon current state-le vel 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 we re assigned to ND; the ND and SD generation analysis was conducted separately from the other We stern states because ND a nd SD are in a different electricity market module region and lignite coal is preferentially us ed, 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 id entified permitted facilities locat ed in ND (i.e., Gascoyne #1 and #2, South Heart, and Great River Energy) have a to tal 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 moratori um 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 th e 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 thehighest 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 Ta ble 5 (both original a nd 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 ex isting coal-fired EGUs and associated infrastructure) should be maintained in the PRP18 analysis.

Table 5. State-level allocation of future placeholder coal-fired EGUs requi red 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 proj ections 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 fr om 12 Western facilities that were reported to U.S. EPA; the revised analysis uses pe rmitted emission rates collected by WR AP 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., PM 10 at Springerville #3 and #4 and SO 2 at Neil Simpson #2) were excluded from the calculation of the average emission rates because th ey were significant outliers. In addition, the VOC rate (0.0022 lb/MMBtu) used in the previous analysis was used in stead 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 c onversion factor of 10 MMBtu/MWh. Future EGUs – Natural Gas. A similar natural ga s-fired electricity demand analysis was also developed. The original analysis indicated that a total of 148.77 b illion 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 additiona l 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 faciliti es were added to the 2018 inventory. Because the identified generation exceeded the projected 2018 needed generation, no additi onal future natural gasfired EGUs were expected to be needed in the WRAP Region. An examination of the revised natural gas-fired electricity generation proj ections did not indicate any signi ficant differences. Therefore, nonew future natural gas-fired EGUs were added to the 2018 inventory beyond t hose 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 f actor model (EGAS), Version 5.0. The EGAS model generates SCC-specific growth factor s 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 Californi a (California growth fact ors are discussed below). Growth factors from the EGAS mode l runs were matched using SCCs to each inventory record. In the event that an inventory record SCC did not match a ny 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 NO x SO 2 VOC CO PM 10 Springerville #3 AZ 0.090 0.090 0.055 a Springerville #4 AZ 0.054 0.077 0.055 a
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 0.200 a 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 fu ture allocated coal-fired EGU

Facility Name NO x SO 2 VOC CO PM 10 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 produc tion area sources were de veloped under Task 1B of this project. These growth factor s 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 growthfactor 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 fr om one of three sources : the EGAS growth factor model, energy projections from EIA, or agricu ltural crop projections from the U.S. Department of Agriculture (USDA). The EGAS area source projecti on factors were obtained in the same manner as described above for the EGAS poi nt source projection factors.

As discussed above, the EIA has issued annua l 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 co mbustion sources. These EIA- based projection factors were used for the following source categorie s: 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 majo r field crops (i.e., wheat, barley, corn, rice, oats, soybeans, sorghum, and upland cotton). Extrapolation wa s used to extend the time series back to 2002 and forward to 2018. The 2002 harvested acreage was es timated 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 deve loped using an entirely different methodology than has been described in this report for the othe r WRAP states. The California Air Resources Board (ARB) used the California Emission Forecasting Syst em (CEFS) to develop California’s 2018 base case inventory and provided it directly to the WRAP. The California 2018 ba se case inventory was provided by ARB in CEFS output format. CEFS uses two sepa rate 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 th e WRAP. The CEFS 2018 database files for point sources (i.e., 128,425 record s; 20,914 facilities) and area sources (i.e., 16,340 records; 618 SCCs across all countie s) were provided 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 pl ace 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 c ould not be matched to 2002 records.• Area Sources:

- Certain EICs were removed (i.e., sources not in cluded in this inventory effort – wildfires, prescribed burning, forest fires, rangela nd burning, agricultura l 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 Calif ornia files were convert ed 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 project ed inventory also include s 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 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 with specific modi fications that were made for the special case of EGUs.

Retirement and replacement was applied to a subs et 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 projecti on retirement rate. The annua l retirement rate is the percentage of sources under a part icular SCC that are expected to retire in a given year; the annual retirement rate is defined as (1/lifetime). For exampl e, an SCC with an expected lifetime of 50 years has an annual retirement rate of 0.02 (i.e., 1/50 years). The projection re tirement rate is th e percentage of sources under a particular SCC that are expected to retire over the pe riod of the projection (i.e., from 2002 to 2018, or 16 years). In the case of the SCC exam ple 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 NO x , SO 2 , and PM 10 . These factors were based on the expected reduc tion as an uncontrolled source is retired and replaced by a new controlled source. Reduction fact ors were calculated usi ng 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 ne w 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 Emi ssions = Unretired 2002 Emissions + Retired/Replaced 2002 Emissions + Grown 2018 Emissions

Equations (14) Total 2018 Emissions = (2002 Emissi ons × [1 – R]) + (2002 Emissions × R × [1 – C])+ (2002 Emissions × [G – 1] × [1 – C]) The retirement/replacement methodology described above was applied to al l point sources that matched the SCCs in Table 8. The one key excep tion was for EGUs. Instead of applying annual retirement rates to EGUs, the age of the E GU based upon known start-up dates was compared to expected lifetimes as shown in Table 8. If the ag e of any EGU exceeded its expected lifetime in 2018, then that EGU was assumed to be replaced by a si milarly-sized EGU grown up to capacity with the appropriate reduced emission rates. Further inpu t from the WRAP SSJF Projections Work Group and other stakeholders indicated that the retiremen t/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 retireme nt/replacement effects were applie d 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 contro ls 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 retrof it 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 usedin place of the 2018 projections in the WRAP 2018 PRP inventory. Th e 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 SO 2 /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 elig ible for BART, according to the WRAP’s latest WRAP BART Clearinghouse. 10 The methodology used to estimate the annual SO 2 emissions based on the presumptive BART rate was to multiply the ra te 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 NO x (tpy) SO 2 (tpy) NO x (tpy) SO 2 (tpy) NO x (tpy) SO 2 (tpy) Colorado Colorado Springs Utilities – Nixon Un it 1 2,416 4,774 2, 331 4,073 -85 -701 Colorado Springs Utilities – Drak e 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 BART a -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 c apacity factor of 85%. Email from Mark Fisher, ODEQ to Paula Fields, ERG, April 13, 2007.Table 10. Summary of presumptive SO 2 BART limits for subject and eligible coal-fired electric generating units in the WRAP region.

Facility Name and Unit 2018b Base Case (tons SO 2 ) a Presumptive BART - Rate (lb/MMBtu) 2018 Heat Input (MMBtu) Presumptive BART- Annual (tons SO 2 )

Alaska – GVEA Healy Power Plant – Unit 1 366 0.15 140 Change in AK Due to Presumptive BART -226 tons SO 2 Arizona AZ Electric Power Cooperative, In c. – Apache 2 1,439 0.15 15,248,939 1,144 AZ Electric Power Cooperative, In c. – 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 SO 2 Montana Colstrip Steam Electric Station – Unit 1 b 5,517 0.15 29,843,850 2,238 Colstrip Steam Electric Station – Unit 2 b 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 SO 2 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 SO 2 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 SO 2 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 0.22 c 19,819,756 2,180 Pacificorp – Dave Johnston – Unit 2 4,250 0.15 c 30,030,412 2,252 Pacificorp – Jim Bridger – Unit 1 7,069 0.15 c 45,621,694 3,422 Pacificorp – Jim Bridger – Unit 2 6,906 0.15 c 43,634,528 3,273 Pacificorp – Jim Bridger – Unit 3 6,537 0.15 c 46,238,491 3,468 Pacificorp – Jim Bridger – Unit 4 4,107 0.15 c 45,075,468 3,381 Pacificorp – Naughton Power Plant – Unit 1 6,518 0.41 c 12,813,313 2,627 Pacificorp – Naughton Power Plant – Unit 2 8,694 0.41 c 16,715,747 3,427 Pacificorp – Naughton Power Plant – Unit 3 5,980 0.21 c 28,425,577 2,985 Pacificorp – Wyodak – Unit 1 8,281 0.32 c 35,685,720 5,710 Change in WY Due to Presumptive BART -35,522 tons SO 2 EPA Sources on Navajo Tribal Land located in New Mexico Four Corners Power Plant – Unit 1 1,385 0.21 d 14,846,431 1,559 Four Corners Power Plant – Unit 2 1,687 0.21 d 16,632,804 1,746 Four Corners Power Plant – Unit 3 2,122 0.21 d 19,873,582 2,087 Four Corners Power Plant – Unit 4 8,509 0.21 d 57,929,739 6,083 Four Corners Power Plant – Unit 5 9,729 0.21 d 56,778,871 5,962 Change on Navajo Tribal Land Due to SO 2 Control Levels Proposed by EPA -5,995 tons SO 2 Overall Total Change Due to Presumptive BART -77,560 tons SO 2 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 percenta ge 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 F our Corners. http://www.epa.gov/fe drgstr/EPA-AIR/2006/September/Da y-12/a15097.pdf

e Totals may not equal sum of columns due to rounding.Several EGUs either have permit limits below the presumptive SO 2 BART limit, or they operated below the presumptive BART leve l in 2006. Therefore, no presumptive SO 2 BART reductions were applied for the 2018 PRP inventory for th ese 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 SO 2 Changes in §309 states

A study was conducted for the WRAP SSJF in 2006 by Pechan to update the 2018 SO 2 emission projections (originally estimat ed by ERG and ENVIRON) for purposes of establishing SO 2 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 estim ates for non-utility sources emitting more than 100 tons of SO 2 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 SO 2 emissions from these industries: copper smelters, lime manufacturing, pulp and paper, oil and gas, chem ical manufacturing, petrol eum refining, and cement production.

For the WRAP PRP18 inventory, ERG summarized th e changes from the Pechan report by state, distributed these to the applicable S/L/T agencies as part of the collect ion of comments process described above, and requested that each agency c onfirm these changes. Also, ERG obtained SCC level changes from Pechan, in order to make the detail ed changes at the SCC le vel for this WRAP PRP18 inventory project.

RESULTS

The summary results of the PRP18 emissions invent ory 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 Ph ase 2 of this project. The resulting changes between the 2018 base case emission s inventory and the PRP18 emissions inventory are also graphically shown for NO x , SO 2 , and PM 10 in Figures 3 and 4. From Figure 3, it is clear that the most significant point source changes are for SO 2 emissions. Likewise, from Figure 4, it is shown that the most significant area source changes are for NO x emissions.Table 11.Summary of draft 2018b base case emissionsinventory, net changes made by state and resulting WRAP PRP18 emissions inventory –point sources (tons per year)StateNOxSO2VOCCOPM10PM2.5NH3WRAP 2018b Base Case Emissions Inventory (TPY):AK 67,959.43 7,781.59 6,637.31 25,881.08 2,884.91 357.32 1,103.95AZ 77,738.22 94,407.68 9,466.23 33,242.90 9,893.22 1,644.24 729.29CA 109,514.89 49,631.75 54,631.70 123,795.15 33,191.68 19,496.84CO 112,239.70 69,213.14 98,629.89 58,211.27 28,697.25 306.79 623.03ID 14,048.16 25,467.31 3,060.02 38,019.05 1,741.19 643.01 1,649.87MT 62,583.10 45,321.07 10,445.96 62,353.62 11,266.02 691.74 421.68ND 92,097.99 162,704.76 2,493.21 22,589.46 4,369.38 3,051.53 522.95NM 74,874.05 41,392.29 26,187.38 57,506.25 3,391.82 1,749.33 123.26NV 69,016.45 24,040.65 4,112.87 20,745.67 6,200.35 1,534.57 1,172.78OR 31,760.79 21,686.48 41,168.92 53,654.91 13,517.81 16,659.86 1,016.13SD 24,725.86 15,268.20 3,522.79 6,858.87 1,044.86 256.93 101.60UT 96,974.44 52,952.88 13,599.53 98,373.32 18,381.76 5,812.25 2,081.94WA 49,396.97 51,355.44 28,013.12 187,705.34 12,096.19 4,676.22 5,495.06WY 132,115.76 145,099.58 27,541.60 60,503.77 42,819.39 19,495.90 810.87Tribal 92,580.06 32,894.77 2,864.32 12,987.96 7,748.84 3,206.27 125.44Net Changes to 2018b Base Case Emissions Inventory (TPY):AK -226.34 -1,118.54AZ -4,666.91 -24,070.72 211.84 796.24 984.32 44.41 23.80CACO 1,120.93 -12,234.64 -21,100.97 5,782.57 -401.45 -211.29 -85.85ID -1,675.35 -15,522.06 -41.37 -2,792.25 -335.07 -87.42 -31.09MT -217.91 -8,840.88 55.17 1,000.74 -131.79 -246.52ND -21,041.97 -95,626.23 1.79 -1,593.89 1,020.96 -262.26 -61.07NM -273.61 -9,011.88 -0.04 -130.31 -74.46 -87.43 -4.94NV -1,391.45 4,126.30 -247.12 6,968.94 -164.13 1,058.37 -308.31OR -6,813.49 -13,734.49 -530.41 -3,502.51 -433.54 -15,377.31 -184.31SD 1.00 -9,433.88 0.00UT -17,213.16 -15,014.36 -406.18 -1,920.34 -2,903.88 -1,311.37 -31.44WA 59.34 -13,911.46 -1,801.03 -80,108.37 -2,370.47 -289.69 -29.27WY 1,099.95 -49,955.64 728.59 4,278.61 19.80 -328.70 0.00Tribal 7,922.92 -4,495.17 317.51 572.15 1,293.29 536.03 31.44WRAP PRP18 Emissions Inventory (TPY):AK 67,959.43 7,555.25 6,637.31 25,881.08 1,766.37 357.32 1,103.95AZ 73,071.31 70,336.96 9,678.07 34,039.14 10,877.54 1,688.65 753.09CA 109,514.89 49,631.75 54,631.70 123,795.15 33,191.68 19,496.84Table 11.ContinuedStateNOxSO2VOCCOPM10PM2.5NH3CO 113,360.63 56,978.50 77,528.92 63,993.84 28,295.80 95.50 537.19ID 12,372.81 9,945.25 3,018.65 35,226.80 1,406.12 555.59 1,618.78MT 62,365.19 36,480.19 10,501.13 63,354.36 11,134.23 445.22 421.68ND 71,056.02 67,078.53 2,495.01 20,995.57 5,390.34 2,789.28 461.88NM 74,600.43 32,380.40 26,187.34 57,375.95 3,317.36 1,661.90 118.32NV 67,625.00 28,166.95 3,865.76 27,714.61 6,036.22 2,592.94 864.46OR 24,947.30 7,951.99 40,638.51 50,152.40 13,084.26 1,282.55 831.82SD 24,726.86 5,834.32 3,522.79 6,858.87 1,044.86 256.93 101.60UT 79,761.28 37,938.52 13,193.35 96,452.98 15,477.88 4,500.88 2,050.49WA 49,456.32 37,443.99 26,212.09 107,596.98 9,725.72 4,386.52 5,465.79WY 133,215.71 95,143.95 28,270.19 64,782.38 42,839.19 19,167.21 810.86Tribal 100,502.99 28,399.61 3,181.83 13,560.10 9,042.14 3,742.30 156.88Table 12.Summary of draft 2018b base case emissionsinventory, net changes made by state and resulting WRAP PRP18 emissions inventory –areasources (tons per year)StateNOxSO2VOCCOPM10PM2.5NH3WRAP 2018b Base Case Emissions InventoryAK 9,293.35 6,043.71 16,539.14 29,055.82 21,531.05 6,877.71 639.23AZ 12,558.62 3,410.26 171,414.85 70,097.25 137,883.20 39,332.92 9,457.14CA 117,716.62 9,772.22 357,745.55 384,966.70 190,987.09 84,801.21CO 44,040.52 7,498.70 173,092.43 94,594.76 185,238.34 48,422.51 96.76ID 42,067.89 2,720.52 194,210.06 40,971.48 62,880.57 7,702.74 2,288.40MT 36,052.99 3,432.14 67,476.71 41,415.20 173,892.25 40,015.47 607.92ND 21,128.65 5,856.27 82,650.71 21,606.83 311,272.53 64,978.37 462.99NM 172,318.92 15,753.24 399,205.01 47,997.02 144,289.23 34,664.44 909.55NV 7,487.60 14,194.42 47,609.85 17,479.33 97,755.67 23,312.88 1,645.65OR 17,027.19 8,421.88 334,872.12 380,523.74 225,924.68 81,744.55 249.80SD 7,206.93 11,667.18 50,072.09 25,112.44 226,750.11 48,648.35 502.02UT 21,635.69 3,586.90 173,344.04 45,962.17 34,279.28 5,760.83 1,679.83WA 22,745.95 8,667.27 253,709.83 252,446.63 348,329.35 113,984.70 7,021.73WY 79,196.38 23,109.16 436,884.86 34,463.27 45,027.21 12,435.80 514.06Tribal 6,639.04 2.08 18,240.28 563.99 2,062.46 412.22 0.07Net Changes to 2018b Base Case Emissions InventoryAK -566.98 -1.30 -91.90 -0.47AZ 224.89 -2.05 -505.80 7,865.47 -1,122.85 291.70CACO -27,617.20 -8.48 -36,938.50 -4,961.40ID 332.78MT -30,491.27 -8.03 -7,517.34 -1,636.50ND -8,620.46 -2.75 -13,003.22 -132.08NM -138,346.67 -16.49 -327,913.29 -5,934.23 -2,689.07 -926.96NV -72.09 -0.04 5,407.50 -1.44OR -48.18 -19.37 -1.39SD -2,759.18 -7,582.81 -394.53 -1,041.42 -2,673.97 -491.15 -6.23UT -13,153.59 -4.65 -95,061.48 -1,349.88WAWY -59,439.61 -15.61 -403,798.30 -3,962.23TribalWRAP PRP18 Emissions InventoryAK 8,726.37 6,042.41 16,447.24 29,055.35 21,531.05 6,877.71 639.23AZ 12,783.50 3,408.20 170,909.05 77,962.72 136,760.35 39,624.62 9,457.14CA 117,716.62 9,772.22 357,745.55 384,966.70 190,987.09 84,801.21CO 16,423.32 7,490.22 136,153.94 89,633.36 185,238.34 48,422.51 96.76Table 12.ContinuedStateNOxSO2VOCCOPM10PM2.5NH3ID 42,067.89 3,053.31 194,210.06 40,971.48 62,880.57 7,702.74 2,288.40MT 5,561.72 3,424.11 59,959.38 39,778.71 173,892.25 40,015.47 607.92ND 12,508.19 5,853.53 69,647.48 21,474.75 311,272.53 64,978.37 462.99NM 33,972.25 15,736.76 71,291.71 42,062.80 141,600.16 33,737.48 909.55NV 7,415.51 14,194.38 53,017.35 17,477.89 97,755.67 23,312.88 1,645.65OR 16,979.01 8,421.88 334,852.75 380,522.35 225,924.68 81,744.55 249.80SD 4,447.75 4,084.37 49,677.55 24,071.02 224,076.14 48,157.20 495.80UT 8,482.11 3,582.25 78,282.56 44,612.29 34,279.28 5,760.83 1,679.83WA 22,745.95 8,667.27 253,709.83 252,446.63 348,329.35 113,984.70 7,021.73WY 19,756.77 23,093.55 33,086.56 30,501.05 45,027.21 12,435.80 514.06Tribal 6,639.04 2.08 18,240.28 563.99 2,062.46 412.22 0.07Figure 3. Emissions projection changes between 2018b inve ntory and PRP18 inventory - point sources

4

Figure 4. Emissions projection changes between 2018b i nventory 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
PRP18NEXT STEPS

The next steps in finalizing the PRP18 inventor y include incorporating comments received from the S/L/T agencies on the draft PRP18, which is currently in pro cess. 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 acce ss 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. Th e final baseline period analyses will have a limited focus, on correcting inventory e rrors that affect the Reasonable Progress de monstration, as the inventory from that time period will have been supplanted by more recen t 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 fo r sources subject to BART requirements. Other remaining 2018 inventory projection corrections will al so 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 Proj ections for the 2018 Base Case Inventory, Version 1.” Prepared for the Western Governor s’ Association and the Western Regional Air Partnership, Stationary Sources Joint Forum. Pr epared 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 electroni c mail from Roy Huntley, U.S. Environmental Protection Agency, Research Triangle Park, NC. August 30, 2005. 3. National Wood Products Initiative. Information avai lable on the Internet a t: http://www.epa.gov/ compliance/resources/cases/ civil/caa/wood/index.html 4. National Petroleum Refinery Initiative. In formation available on the Internet at: http://www.epa.gov/compliance/resour ces/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: Getti ng 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. Informati on available on the Internet at: http://www.wrapair.org 11. Cummins, P. Listing of 2006 CAMD heat i nput rates provided by Pat Cummins, Western Regional Air Partnership. April 25, 2007.12. “2018 SO 2 Emissions Evaluation for Non-Utility Poin t Sources, Final Report.” Prepared for the Western Regional Air Partnership, Stationary So urces Joint Forum. Prepared by Pechan and Associates. October, 2006. Availa ble on the Internet at: http://www.wrapair.org/forums/ssjf/ documents/eictts/projections.html

KEY WORDS

Projections WRAP Modeling inventory Point sources Area sources