U.S. Environmental Protection Agency 

Region 9 

Clean Air Act Permit 

Fact Sheet

Four Corners Power Plant

PSD Permit: NN 14-01

Tribal Minor NSR: T-002-NN

July 2014
i 

Fact Sheet

Proposed Prevention of

Significant Deterioration Permit

And

Minor New Source Review Permit in Indian Country

Four Corners Power Plant

Navajo Nation

PSD Permit No. NN 14-01

Tribal NSR Permit: T-002-NN

_________________________________________________Table of Contents____________________________________________ 

Section 1: Executive Summary 1 

Section 2: Purpose 1 

Section 3: Project Description 1 

Section 4: Public Comment Period, Procedures for Final Decision, and EPA Contact 6 

Section 5: Applicability of Prevention of Significant Deterioration Regulations 8 

Section 6: Determination of Best Available Control Technology 20 

Section 7: Ambient Air Quality Impact Report 33 

Section 8: Additional Impact Analysis 35 

Section 9: Minor New Source Review for Indian Country 35 

Section 10: Endangered Species Act 37 

Section 11: National Historic Preservation Act 38 

Acronyms & Abbreviations 39 

 

 
FCPP SCR Project Page 1 of 41 

Fact Sheet 

July 2014

Fact Sheet

Proposed Prevention of Significant Deterioration Permit and Minor New Source Review

Permit in Indian Country

Four Corners Power Plant

Section 1.0: Executive Summary

The Arizona Public Service Company (APS or Applicant) applied to the U.S. Environmental Protection Agency 

(EPA) Region 9 for authorization under the Clean Air Act (CAA) Prevention of Significant Deterioration (PSD) 

program to install selective catalytic reduction (SCR) systems for two electric power generating units at the Four 

Corners Power Plant (FCPP) located on the Navajo Nation near Farmington, New Mexico (the Project or FCPP SCR 

Project). EPA is noticing for public review a proposed PSD permit to allow construction of the Project because it 

satisfies the requirements of the PSD program for the following reasons: 

ß The proposed PSD permit requires the best available control technology (BACT) to limit emissions of 

sulfuric acid mist (H2SO4 or SAM). 

ß The FCPP SCR Project will not adversely impact soils, vegetation, air quality, or visibility, in parks or 

wilderness areas that are given special protection under the Clean Air Act (referred to as Class I areas). 

 

· The only pollutant for which the FCPP SCR Project causes a significant net emission increase is SAM. 

Because there is no National Ambient Air Quality Standard (NAAQS) for SAM emissions, there is no 

requirement to conduct a NAAQS analysis for this proposed PSD permit. 

Section 2.0: Purpose

This document describes the legal and factual basis for the proposed PSD permit, including requirements under 

section 165 of the CAA and the PSD regulations at Title 40 of the Code of Federal Regulations (CFR) section 52.21 

(40 CFR 52.21) and section 110 of the CAA and the Minor New Source Review (NSR) Program in Indian Country 

regulations at 40 CFR 49.151 through 161. This document serves as a Fact Sheet for the proposed PSD permit per 40 

CFR 124.8. 

Section 3.0: Source Description and Project Summary

EPA received an application from APS for the FCPP SCR Project on April 28, 2014 (hereinafter referred to as “the 

Application”).1 EPA received supplemental information from APS during the application review process. The 

application materials for the proposed PSD permit for the Project are included in EPA’s administrative record for the 

proposed PSD permit. EPA determined the application to be complete on July 8, 2014. 

 

1 EPA received the application by email on April 28, 2014, although the cover letter is dated April 29, 2014. A hard copy of the 

application was date stamped received on May 2, 2014. EPA previously received an application for this Project in October 2013, 

and supplementary information in March 2014. In the October 2013 application, APS did not apply the netting analysis available 

for contemporaneous emissions increases and decreases in 40 CFR 52.21(b)(3) in the October 2013 application. Thereafter, APS 

withdrew the October 2013 application and replaced it with the application we received on April 28, 2014, containing a netting 

analysis for contemporaneous decreases of PM10 and PM2.5 emissions. FCPP App. at Table 3-3. The withdrawn application from 

October 2013 and supplementary materials are not a part of our administrative record for this action. 
FCPP SCR Project Page 2 of 41 

Fact Sheet 

July 2014

Section 3.1: Source Location and Address

Location 

End of San Juan County Road 6675 

Fruitland, New Mexico 

Address 

Arizona Public Service Company Four Corners Electric Power Station 

P.O. Box 35 

Fruitland, NM 87416-0355 

Section 3.2: Source Description

APS co-owns and operates the FCPP. The FCPP is a coal-fired power plant, utilizing pulverized coal-boilers, located 

on the Navajo Nation about 25 miles west of Farmington, New Mexico (see Figure 1). The FCPP currently consists 

of two 750 megawatt (MW) coal-fired electric steam-generating units (EGUs), with a total capacity of approximately 

1,500 MW, and other ancillary equipment such as coal storage, lime handling operations and dry ash handling 

operations. Previously, the FCPP consisted of five coal-fired EGUs. On August 24, 2012, EPA promulgated a sourcespecific Federal Implementation Plan (FIP) requiring the FCPP to achieve emission reductions required by the CAA’s 

best available retrofit technology (BART) requirements.2 In a letter dated December 30, 2013, APS notified EPA that 

as part of the compliance strategy for the BART FIP it would permanently shut down three existing EGUs – Units 1, 

2, and 3 by January 1, 2014. As of January 2014, the FCPP now consists of the two remaining 750 MW EGUs – Units 

4 and 5 – and the existing ancillary equipment. APS will further comply with the requirements of EPA’s BART FIP by 

installing SCR on Units 4 and 5 to reduce emissions of nitrogen oxides (NOX) by approximately 80% from current 

levels. The installation of SCR to comply with EPA’s BART FIP, as explained in more detail below, is causing a 

significant net emissions increase of SAM, which is the reason this Project must obtain a PSD permit from EPA 

Region 9. Because the Project causes a significant net emissions increase only for SAM emissions, SAM is the only 

pollutant subject to PSD review for the SCR Project. 

Section 3.2.1: Existing Pollution Control Equipment for Units 4 and 5

Currently, Units 4 and 5 are each controlled by a wet flue gas desulfurization (FGD) system and a baghouse. The wet 

FGD system is operated primarily to reduce sulfur dioxide (SO2) emissions and is located at the end of the control 

train just prior to the flue gas exiting the stack. Each unit’s baghouse is located prior to the wet FGD and used 

primarily for reducing PM, PM10, and PM2.5 emissions. Figure 2 provides a flow diagram depicting how each unit is 

configured and includes the proposed SCR system and the dry sorbent injection (DSI) system using hydrated lime that 

we are proposing to require as BACT for SAM. 

Section 3.3: Description of SCR Project

The FCPP SCR Project involves the installation of SCR to reduce approximately 80% of the NOX emissions from 

Units 4 and 5 to comply with EPA’s BART FIP. EPA’s BART FIP requires installation of the SCR systems on Units 

4 and 5 to improve visibility at 16 nearby Class I areas, such as Mesa Verde National Park. The new and affected 

emission units associated with the FCPP SCR Project are: 

· Units 4 and 5 will be modified by adding new SCR emissions controls. SCR will be added to substantially 

reduce NOX emissions. The SCR systems will be located after each EGU’s economizer and before the air 

preheater. 

 

2 For more information on EPA’s BART FIP, please see 77 Fed. Reg. 51620 (Aug. 24, 2012) 
FCPP SCR Project Page 3 of 41 

Fact Sheet 

July 2014

· Because the SCR emissions controls will cause a significant net emissions increase in SAM emissions, EPA is 

proposing to require FCPP to install and operate dry sorbent injection (DSI) systems on each Unit as BACT 

to minimize SAM emissions. The DSI systems will be located after the air preheaters and just before the 

baghouses and wet FGDs on each Unit. See Figure 2. 

· Truck traffic will increase due to the delivery of reagent for the DSI systems resulting in increased fugitive 

emissions from paved plant roads. 

· Truck traffic will also increase due to the delivery of urea pellets, 29% aqueous ammonia, or anhydrous 

ammonia for the SCR systems resulting in increased fugitive emissions from paved plant roads. 

· A new pneumatic dry sorbent truck unloading system and silo will be installed; and 

· A new pneumatic urea pellet truck unloading system and silo may be installed if this reagent option is selected 

for the SCR systems or a new ammonia truck unloading station and storage tank will be installed if either the 

aqueous or anhydrous ammonia option is selected for the SCR systems. 

Section 3.4: Construction and Operating Schedule

In order to comply with EPA’s BART FIP, APS must install the SCR systems on Units 4 and 5 by July 2018. To meet 

this requirement, APS intends to begin construction of the FCPP SCR Project by the middle of 2015. Application at 

2-8. Units 4 and 5 currently do not have limits on hours of operation and can operate up to 8,760 hours per year. APS 

is not requesting any changes to the FCPP’s operating schedule as a part of the FCPP SCR Project. Application at 2-8. 

APS will be required to operate the SCR systems at all times when Units 4 and 5 are operating, except at certain times 

during startup when the units are outside the operating temperature range for the SCR systems. Application at 2-8. 

The DSI systems proposed as BACT for this Project will be required to operate at all times Units 4 and 5 are 

operating to comply with BACT. 
FCPP SCR Project Page 4 of 41 

Fact Sheet 

July 2014

Figure 1 Location of Four Corners Power Plant
FCPP SCR Project Page 5 of 41 

Fact Sheet 

July 2014

Figure 2 Flow Diagram for Units 4 and 5 at FCPP 

Atmosphere

(hydrated lime)

Wet Flue Gas 

Desulfurization

Stack Fabric Filter

Dry Sorbent Injection

Bypass

NH3 Injection

Coal Conveyor

Boiler Economizer

Air Preheater

(urea, 29% 

aqueous NH3 or 

anhydrous NH3)

Selective Catalytic 

Reduction
FCPP SCR Project Page 6 of 41 

Fact Sheet 

July 2014

Section 4.0: Public Comment Period, Procedures for Final Decision, and EPA Contact

Any interested person may submit written comments on EPA’s proposed PSD permit for the FCPP SCR Project. All 

written comments must be received or postmarked by September 24, 2014. Comments must be sent or delivered in 

writing to Lisa Beckham at one of the following addresses: 

E-mail: R9airpermits@epa.gov

U.S. Mail: Lisa Beckham (AIR-3) 

U.S. EPA Region 9 

75 Hawthorne Street 

San Francisco, CA 94105-3901 

Comments should address the proposed permit and facility, including such matters as: 

1. The best available control technology (BACT) determination for sulfuric acid mist; 

2. The effects, if any, on Class I areas; and 

3. The effect of the proposed modification, if any, on ambient air quality. 

Before the Public Hearings described below, EPA will hold two Public Information Meetings for the purpose of 

providing interested parties with additional information and an opportunity for informal discussion of the proposed 

Project. The date, time and location of the Public Information Meetings are as follows: 

Date: August 27, 2014 

Time: 6:00 p.m. - 7:00 p.m. 

Location: Nenahnezad Chapter House 

West Hwy 64, South on 

County Road 6675 

North on Navajo Route 365 

Fruitland, NM 87416 

Date: August 28, 2014 

Time: 6:00 p.m. - 7:00 p.m. 

Location: San Juan College 

Henderson Fine Arts Building 

Rooms 9008 and 9010 

4601 College Blvd. 

Farmington, NM 87402 

 

Following the Public Information Meetings, EPA will hold two Public Hearings, pursuant to 40 CFR 124.12, to 

provide the public with further opportunity to comment on the proposed permit for the FCPP SCR Project. At these 

Public Hearings, any interested person may provide written comments or oral comments, in English or Diné, and 

relevant data pertaining to the proposed permit. 

The date, time, and location of the Public Hearings are as follows: 

Date: August 27, 2014 

Time: 7:00 p.m. – 9:00 p.m. 

Location: Nenahnezad Chapter House 

West Hwy 64, South on 

County Road 6675 

North on Navajo Route 365 

Fruitland, New Mexico 87416 

Date: August 28, 2014 

Time: 7:00 p.m. – 9:00 p.m. 

Location: San Juan College 

Henderson Fine Arts Building 

Rooms 9008 and 9010 

4601 College Blvd. 

Farmington, NM 87402 
FCPP SCR Project Page 7 of 41 

Fact Sheet 

July 2014

English-Diné translation services will be provided at each Public Information Meeting and Public Hearing. If you 

require a reasonable accommodation, please contact Philip Kum, EPA Region 9 Reasonable Accommodations 

Coordinator, by August 20, 2014 at (415) 947-3566, or kum.philip@epa.gov. 

Information submitted by the Applicant as part of the Application is available as part of the administrative record for 

this proposed permit. The proposed permit, Fact Sheet, Application and other supporting information are available 

through the EPA Region 9 website at http://www.epa.gov/region09/air/permit/r9-permitsissued.html#pubcomment. The administrative record may also be viewed in person, Monday through Friday 

(excluding Federal holidays) from 9:00 AM to 4:00 PM, at the EPA Region 9 address above. Due to building security 

procedures, please call Lisa Beckham at (415) 972-3811 at least 48 hours in advance to arrange a visit. Lisa Beckham 

can also be reached through EPA Region 9’s toll-free general information line at (866) 372-9378. 

EPA’s proposed permit for the FCPP SCR Project and the accompanying Fact Sheet are also available for review in 

hardcopy at the following locations: San Juan College, Receptionist Desk, 4601 College Blvd, Farmington, NM 

87402, (505) 326-3311; Diné College Shiprock Branch, Receptionist Desk, 1228 Yucca St, Shiprock, NM 87402, (505) 

368-3500; and Shiprock Branch Library, Receptionist Desk, 2102 Farmington Ave, Farmington, NM 87401, (505) 

368-3500. 

All comments that are received will be included in the public docket without change and will be available to the 

public, including any personal information provided, unless the comment includes Confidential Business Information 

(CBI) or other information whose disclosure is restricted by statute. Information that is considered to be CBI or 

otherwise protected should be clearly identified as such and should not be submitted through e-mail. If a commenter 

sends e-mail directly to the EPA, the e-mail address will be automatically captured and included as part of the public 

comment. Please note that an e-mail or postal address must be provided with comments if the commenter wishes to 

receive direct notification of EPA’s final decision regarding the Application and proposed permit. 

Before taking final action on the Application, EPA will consider all written comments submitted during the public 

comment period, including at the Public Hearings described above. EPA will only respond to those oral comments 

that were presented during the scheduled Public Hearings. 

EPA will send notice of our final permit decision to each person who submitted comments and contact information 

during the public comment period or requested notice of the final permit decision. EPA will summarize the contents 

of all substantive comments and provide written responses in a document accompanying EPA’s final permit decision. 

EPA will also make a transcript of the Public Hearing proceedings available to the public. 

EPA’s final permit decision will become effective 30 days after the service of notice of the decision unless: 

1. A later effective date is specified in the decision; or 

2. The decision is appealed to EPA’s Environmental Appeals Board pursuant to 40 CFR 124.19; or 

3. There are no comments requesting a change to the proposed permit decision, in which case the final decision 

shall become effective immediately upon issuance. 

If you have questions, or if you wish to obtain further information, please contact Lisa Beckham at (415) 972-3811, 

via email at R9airpermits@epa.gov, or at the mailing address above. If you would like to be added to our mailing list 

to receive future information about this proposed permit decision or other permit decisions issued by EPA Region 9, 

please contact Lisa Beckham at (415) 972-3811 or send an email to R9airpermits@epa.gov, or visit EPA Region 9's 

website at http://www.epa.gov/region09/air/permit/psd-public-guidelines.html. Lisa Beckham can also be reached 

through EPA Region 9’s toll-free general information line at (866) 372-9378. 
FCPP SCR Project Page 8 of 39 

Fact Sheet 

July 2014 

Section 5.0: Applicability of the Prevention of Significant Deterioration Regulations

This section describes the general requirements of the PSD regulations, our analysis to determine applicability of the 

requirements of the PSD program, and our justification for determining that the FCCP SCR Project’s emissions of

SAM trigger the requirement for a PSD permit. 

Section 5.1: Overview

The PSD program is a preconstruction review and permitting program applicable to certain new major stationary 

sources and major modifications at existing major stationary sources. The specific requirements under the PSD 

program applicable to stationary sources located in Indian country are in EPA’s Federal Implementation Plan for the 

PSD program at 40 CFR 52.21. The PSD program applies to any regulated NSR pollutant (as defined in 40 CFR 

52.21(b)(23)(i)), except for pollutants designated nonattainment for a NAAQS. The FCPP is an existing major source 

that is located in an area designated as attainment or unclassifiable for all NAAQS. Therefore, the PSD program 

applies if the FCPP SCR Project is a major modification for any regulated NSR pollutant. 

The applicability of PSD to a particular source must be determined in advance of construction or modification and is 

pollutant-specific. The primary criterion is whether the proposed project is sufficiently large (in terms of its emissions) 

to be a major stationary source or major modification. 

If the emissions from a project are greater than the levels that are considered a major stationary source or major 

modification, a PSD permit must be issued before construction of the project. The requirements that must be satisfied 

to issue a PSD permit by the reviewing authority include: 

· Conduct a control technology review (40 CFR 52.21(j)); 

· Conduct a source impact analysis (40 CFR 52.21(k)); 

· Conduct an additional impacts analysis (40 CFR 52.21(o)); 

· For sources impacting Class I areas, notify the Federal land managers of the PSD application and evaluation 

of the impacts on air quality related values (including visibility) in Class I areas (40 CFR 52.21(p)); and 

· Follow the applicable public participation requirements (40 CFR 52.21(q)). 

Section 5.2: PSD Applicability – FCPP SCR Project Emissions

The FCPP SCR Project is a modification at an existing major stationary source. The regulations provide that the PSD 

program is only triggered for the FCPP SCR Project if it causes two types of emissions increases: (1) a significant 

emissions increase (as defined in 40 CFR 52.21(b)(40)) and (2) a significant net emissions increase (as defined in 40 

CFR 52.21 (b)(3) and (b)(23)). This two-step test means that the FCPP SCR Project is only a major modification for 

any pollutant if it causes a significant emissions increase of that pollutant and significant net emissions increase for that 

pollutant. See 40 CFR 52.21(a)(2)(iv)(a). These two steps are discussed separately below. 

 Section 5.2.1: Step 1 – Significant Emissions Increase

To determine whether the Project causes a significant emissions increase we must first establish the pre-project 

baseline emissions. After establishing the pre-project baseline emissions, we calculate the projected actual emissions 

increases associated with the FCPP SCR Project for each regulated pollutant. This Project - installation of SCR - will 

involve emission increases for all regulated pollutants except NOX

3

, as described below. 

 

3 There is a 0.3% increase in fuel use associated with the FCPP SCR Project. However, as seen in Table 3, an increase in emissions of lead is not 

expected. While the increase in fuel use has the potential to increase lead emissions, the increase is so small, less than 0.001 tons per year that the 

actual change in emissions is negligible for the purposes of determining PSD applicability. 
FCPP SCR Project Page 9 of 39 

Fact Sheet 

July 2014 

 Section 5.2.1.1 Description of SCR and the Project

The Project involves the installation of SCR systems on Units 4 and 5 to reduce emissions of NOX. SCR technology is 

a widely used post-combustion control technology for achieving significant reductions in NOX emissions. The SCR 

system is used to inject vaporized ammonia into the flue gas of the boiler to act as a reducing agent and convert NOX

to N2 (nitrogen) and water. The reaction takes place using a catalyst (the “catalytic” of selective catalytic reduction) to 

lower the activation energy needed for the NOX to reduce to nitrogen and water. However, the catalysts used in SCR 

systems – e.g. vanadium pentoxide (V2O5) – also cause a side reaction. The side reaction is the oxidation of some 

sulfur dioxide (SO2) to sulfur trioxide (SO3). Sulfur dioxide is originally present in the flue gas of each boiler from the 

sulfur in coal that oxidizes during combustion. Once formed SO3 will condense to form SAM (sulfuric acid mist or 

H2SO4). At some stationary sources the SAM emissions have been seen as a visible blue plume exiting the stack. In 

addition to air quality impacts, SO3 can cause operational impacts through ammonium bisulfate formation, corrosion 

and plugging. Minimizing the conversion of SO2 to SO3 can mitigate these impacts, which, to the extent practicable, 

the Applicant is proposing to do through the use of a catalyst with a low SO2 to SO3 conversion rate and by utilizing 

DSI systems. The increased emissions of SAM will also cause a significant increase in PM10 and PM2.5 emissions, as 

SAM is also condensable particulate matter and therefore included in PM10 and PM2.5. 

The Project will include less than significant emissions increases for other regulated NSR pollutants resulting from: 

· Increased fuel use to operate the SCR systems, caused by partial bypassing of the economizer for each boiler 

to raise the flue gas temperature in certain conditions for proper control of NOX emissions. 

· Increased truck traffic for deliveries 

· Addition of storage tanks and silos. 

The emissions increase for each regulated pollutant is shown in Table 3-3 of the Application and Table 3 below on 

page 14.

 Section 5.2.1.2 Applicability Procedures

40 CFR 52.21(a)(2) – Applicability procedures – contains the applicability tests used to determine whether a modification 

at an existing major source is a major modification for each regulated pollutant. In this case the applicability test in 40 

CFR 52.21(a)(2)(iv)(f) – Hybrid test for projects that involve multiple types of emission units – applies because the Project 

includes the modification of existing emissions units (Units 4 and 5) and the construction of new emissions units 

(truck traffic and storage silos). For existing emissions units, emission increases are determined by the sum of the 

difference between the baseline actual emissions and the projected actual emissions for each modified emissions unit 

(referred to as the actual-to-projected-actual test). For new emissions units, emission increases are determined by the 

potential to emit of the new unit (referred to as the actual-to-potential test). 

 Section 5.2.1.3 Actual-to-Projected-Actual Test (for Existing Emission Units)

 

Actual-to-projected actual emissions are determined by calculating the baseline actual emissions from the existing units 

and the projected actual emissions caused by the Project. The difference between these two numerical values is the 

emissions increases associated with this Project. 

Baseline Actual Emissions 

Table 1 on page 14 below contains the baseline actual emissions for the existing emission units (Units 4 and 5) being 

modified as part of this Project. The baseline actual emissions are determined according to the procedures in 40 CFR 

52.21(b)(48), as described below. 

Selection of Baseline period for Units 4 and 5 

Baseline actual emissions for an existing electric utility steam generating unit is the average rate, in tons per year, that 

the unit actually emitted during any consecutive 24-month period selected by the owner or operator within the 5-year 

period immediately preceding when the owner or operator begins actual construction of the project. 40 CFR 

52.21(b)(48)(i). APS anticipates beginning actual construction in July 2015 to comply with the requirement in EPA’s 
FCPP SCR Project Page 10 of 39 

Fact Sheet 

July 2014 

BART FIP. FCPP Application, Section 2.3. The 5-year period preceding the Project, therefore, is July 2010 through 

July 2015. EPA’s BART FIP contains a compliance date of July 2018 for operation of SCR and APS anticipates a 3-

year schedule for construction and operation in time to meets the requirements of the BART FIP. Based on our 

experience with implementing BART requirements at other facilities, EPA is finding that it is reasonable for APS to 

anticipate a 3-year construction schedule, beginning in July 2015. 

Because APS reasonably anticipates beginning construction in July 2015, APS may choose any 24-month period 

during the 5-year period beginning in July 2010 to determine baseline actual emissions. In this case, APS chose 

January 2011 through December 2012. The detailed data for the baseline actual emissions is in Table A-1.1 of 

Appendix A to the FCPP Application. 

Provisions Applicable to Baseline Actual Emissions 

The definition for baseline actual emissions applicable to electric steam generating utility units provides that: 

1. The average rate shall include fugitive emissions to the extent quantifiable, and emissions associated with 

startups, shutdowns, and malfunctions. 40 CFR 52.21(b)(48)(i)(a). 

Analysis – Requirement met. Emissions from Units 4 and 5 in Table 1 are not fugitive (that is, there are 

no quantifiable fugitive emissions from these units) and the emissions data used included all emissions 

during the 24-month period, including any emissions that may have been associated with startup, 

shutdown, or malfunction. See Addendum to Application for PSD Permit dated July 2, 2014 

(Addendum) at 1 and Attachment E. 

2. The average rate shall be adjusted downward to exclude any non-compliant emissions that occurred while the 

source was operating above any emission limitation that was legally enforceable during the consecutive 24-

month period. 40 CFR 52.21(b)(48)(i)(b). 

Analysis – Requirement met. During the particular period, January 2011 through December 2012, the 

applicable emission limitations to Units 4 and 5, according to FCPP’s title V permit4, were: 

· SO2 – 12% of the potential combustion concentration assuming all of the sulfur in the coal is 

converted to SO2; 

· SO2 – 17,900 lb/hr; 

· PM – 0.050 lb/MMBtu; 

· NOX – 0.65 lb/MMBtu – Units 4 and 5; 

· The total plant-wide NOX emissions shall not exceed 335,000 pounds per 24-hour period when 

coal-burning equipment is operating, on a plant-wide basis; for each hour when coal-burning 

equipment is not operating, this limitation shall be reduced. If the unit which is not operating is 

Unit 1, 2, or 3, the limitation shall be reduced by 1,542 lb per hour for each unit which is not 

operating. If the unit, which is not operating, is Unit 4 or 5, the limitation shall be reduced by 

4,667 lb per hour for each unit which is not operating. 

The data used for this analysis, which is based on EPA’s Air Markets Program Data (AMPD) continuous 

emissions monitoring data (CEMS), and performance testing, does not indicate that Units 4 and 5 

operated above these limits, so the emission rates do not need to be adjusted downward. See Table A-1.1 

– Monthly Baseline Emissions in the Application. See also Addendum at 2-3 and Attachment C. 

3. For a regulated NSR pollutant, when a project involves multiple emissions units, only one consecutive 24-

month period must be used to determine the baseline actual emissions for the emissions units being changed. 

 

4

See Section II.A.2 of the FCPP Title V (No. NN-ROP-05-07) issued by the Navajo Nation Environmental Protection Agency.
FCPP SCR Project Page 11 of 39 

Fact Sheet 

July 2014 

A different consecutive 24-month period can be used for each regulated NSR pollutant. 40 CFR 

52.21(b)(48)(i)(c). 

Analysis – Requirement met. The same consecutive 24-month period was used for each unit and each 

pollutant. See Tables A-1.2 and A-1.4 of the Application. 

4. The average rate shall not be based on any consecutive 24-month period for which there is inadequate 

information for determining annual emissions, in tons per year, and for adjusting this amount if required by 

paragraph (b)(48)(i)(b) of this section. 40 CFR 52.21(b)(48)(i)(d). 

Analysis – Requirement met. Sufficient information to determine baseline actual emissions is available by 

using heat input data provided by EPA’s AMPD; CEMS information reported to AMPD for SO2, NOX

and CO2; stack test data for SAM and filterable PM; and emission factor information for all other 

pollutants (including condensable PM and estimates of PM10 and PM2.5 fractions) available through EPA 

AP-42 – Compilation of Air Pollutant Emission Factors or the EPRI Emission Factor Handbook. See 

Table A-1.2 of the Application. 

Additional Considerations for Baseline Actual Emissions 

1. For a new emissions unit, the baseline actual emissions for purposes of determining the emissions increase 

that will result from the initial construction and operation of such unit shall equal zero; and thereafter, for all 

other purposes, shall equal the unit's potential to emit. 40 CFR 52.21(b)(48)(iii). 

Analysis – Not applicable, Units 4 and 5 are not new emissions units. 

2. For a PAL for a stationary source, the baseline actual emissions shall be calculated for existing electric utility 

steam generating units in accordance with the procedures contained in 40 CFR 52.21(b)(48)(i), for other 

existing emissions units in accordance with the procedures contained in 40 CFR 52.21(b)(48)(ii), and for a 

new emissions unit in accordance with the procedures contained in 40 CFR 52.21(b)(48)(iii). 40 CFR 

52.21(b)(48)(iv). 

Analysis – Not applicable, APS is not applying for a PAL permit. 

Projected Actual Emissions 

Table 2 on page 14 below contains the projected actual emissions for the existing emission units being modified as 

part of this Project. Projected actual emissions are determined according to the procedures in 40 CFR 52.21(b)(41). 

Projected actual emissions must be calculated based on the maximum annual rate, in tons per year, at which an 

existing emissions unit is projected to emit a regulated NSR pollutant in any one of the 5 years (12-month period) 

following the date the unit resumes regular operation after the project, or in any one of the 10 years following that 

date, if the project involves increasing the emissions unit's design capacity or its potential to emit that regulated NSR 

pollutant and full utilization of the unit would result in a significant emissions increase or a significant net emissions 

increase at the major stationary source. 

Analysis: Requirement met. The Project is expected to become operational in mid-2018, so the Applicant considered 

the years 2018 through 2027 to determine projected actual emissions.5 

In addition, per 40 CFR 52.21(b)(41)(ii), in determining the projected actual emissions under 40 CFR 52.21(b)(41)(i) 

(before beginning actual construction), the owner or operator of the major stationary source: 

 

5 See Addendum at 3. 
FCPP SCR Project Page 12 of 39 

Fact Sheet 

July 2014 

1. Shall consider all relevant information, including but not limited to, historical operational data, the company's 

own representations, the company's expected business activity and the company's highest projections of 

business activity, and the company's filings with the State or Federal regulatory authorities; and 

2. Shall include fugitive emissions to the extent quantifiable, and emissions associated with startups, shutdowns, 

and malfunctions; and 

3. Shall exclude, in calculating any increase in emissions that results from the particular project, that portion of 

the unit's emissions following the project that an existing unit could have accommodated during the 

consecutive 24-month period used to establish the baseline actual emissions under paragraph (b)(48) of this 

section and that are also unrelated to the particular project, including any increased utilization due to product 

demand growth; or 

4. In lieu of using the method set out in paragraphs (b)(41)(ii)(a) through (c) of 40 CFR 52.21, may elect to use 

the emissions unit's potential to emit, in tons per year, as defined under paragraph (b)(4) of this section. 

Analysis: Requirement met. APS did not choose to use the modified emissions units’ potential to emit to determine 

projected actual emissions. Projected actual emissions for Units 4 and 5 are based on: 

· APS’s projections that the FCPP maximum annual capacity factor between 2014 and 2027 will be 89.35% 

due to demand growth and non-project related factors.6 The baseline actual emissions calculations were 

equivalent to an annual capacity factor of 74.9%. 

· Emission increases of SAM, PM10, and PM2.5 caused by the operation of the SCR systems.7

· Project-related emissions increases due to an increase in fuel use necessitated by the increased utilization of 

Units 4 and 5. The operation of SCR increases the parasitic power requirements8 of the FCPP because 

additional power must be generated to power the SCR systems and to account for occasional bypassing of 

the economizer. Due to these parasitic power requirements, the SCR systems are expected to increase fuel 

use by 0.3%9 above the projected 89.35% utilization. 

· Except for NOX, SAM, PM10, and PM2.5, the Project is not expected to affect the emission rates for Units 4 

and 5 for any pollutants on a lb/MMBtu basis. That is, the emissions increase of all other pollutants is only 

associated with the increased utilization of Units 4 and 5 due to demand growth. In order to calculate 

projected actual emissions, APS used the lb/MMBtu emission rates associated with baseline actual emissions, 

as shown in Table 4. 

· The projected actual NOX emission rate and annual emissions will be significantly lower after the Project 

based on the NOX limit that FCPP will be required to meet by the BART FIP. 

· There are no quantifiable fugitive emissions associated with Units 4 and 5. 

· Emissions anticipated to be associated with startup, shutdown, or malfunction were not excluded. See 

Addendum at 1-2 and Attachment E. 

· APS appropriately excluded emissions associated with demand growth and non-project related emission 

increase. Application at Table 5-1. 

 Section 5.2.1.4 Actual-to-Potential Test (for New Emission Units)

Table 2 contains the potential to emit of the proposed new emission units. Emissions from truck traffic and storage 

silos is expected to increase emissions of PM, PM10 and PM2.5. Emissions calculations are available in Tables A-4, A5.1, and A-5.2 of the Application. 

 

6 See Table A-8 – FCPP Projected Capacity Factors including Demand Growth and Non-Project Related Factors – in the Application. See also, 

Addendum at 3-4 and Attachment B. 

7 The increase in emissions caused by the catalysts of the SCR systems will be in the form of SAM. SAM is also condensable particulate matter, 

so this also causes emission increases of condensable PM10 and PM2.5. Separately, there will also be increases of filterable particulate matter – 

PM, PM10, and PM2.5 – from the SCR and DSI systems’ auxiliary operations due to truck traffic, storage tanks, and storage silos. 

8 By parasitic power requirements we mean the portion of the gross power generated by the FCPP that is needed to operate the systems at the 

plant and that will not be available for supplying power to the grid. 

9 See Table A-9 – Estimated Increased Fuel Use due to SCR Parasitic Load and Economizer Bypass. 
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 Section 5.2.2: Summary of Project Emissions Increases

Table 3 contains the summary of emissions increases associated with this Project. Based on this information, the 

Project only results in a significant emissions increase, as defined in 40 CFR 52.21(b)(3) and (b)(23), for PM10, PM2.5

and SAM emissions. As such, we will only further consider whether PM10, PM2.5, and SAM emissions from the FCPP 

SCR Project are subject to the PSD program. The emissions information provided in this Fact Sheet is based on the 

calculations provided by APS in the application. Application at Table 5-1. In our review of the application there were 

certain instances where emissions could have be calculated slightly differently, but did not affect the overall 

conclusion regarding whether the Project caused a significant emissions increase for a pollutant. Our supplemental 

calculations are provided separately in Supplemental Emissions Analysis – FCPP SCR Project, which is a part of the 

administrative record for this action.
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July 2014

Table 1 Baseline Actual Emissions for FCPP SCR Project 

Emission Unit NOX SO2 PM PM10 PM2.5 CO VOC H2SO4 Lead GHGs

(CO2e)

Units 4 and 5 24,029 8,373 644 801 550 1,444 5.79 14.1 0.115 10,058,133 

Truck Traffic, Delivery Dry Sorbent 0 0 0 0 0 0 0 0 0 0 

Truck Traffic, Delivery of SCR reagent 0 0 0 0 0 0 0 0 0 0 

Silo for Dry Sorbent Storage 0 0 0 0 0 0 0 0 0 0 

Silo for SCR Reagent Storage 0 0 0 0 0 0 0 0 0 0 

Total Baseline Actual Emissions 24,029 8,373 644 801 550 1,444 5.79 14.1 0.115 10,058,133 

Table 2 Projected Actual Emissions for FCPP SCR Project 

Emission Unit NOX SO2 PM PM10 PM2.5 CO VOC H2SO4 Lead GHGs

(CO2e)

Units 4 and 5 4,783 8,403 647 1,134 843 1,449 5.81 250.6 0.115 10,094,124 

Truck Traffic, Delivery Dry Sorbent 0.0 0.0 0.095 0.019 0.005 0.0 0.0 0.0 0.0 0.0 

Truck Traffic, Delivery of SCR reagent 0.0 0.0 0.087 0.017 0.004 0.0 0.0 0.0 0.0 0.0 

Silo for Dry Sorbent Storage 0.0 0.0 0.086 0.086 0.086 0.0 0.0 0.0 0.0 0.0 

Silo for SCR Reagent Storage 0.0 0.0 0.214 0.214 0.214 0.0 0.0 0.0 0.0 0.0 

Total Projected Actual Emissions 4,783 8,403 647 1,134 843 1,449 5.81 251 0.115 10,094,124 

Table 3 Summary of Emissions Increases from the FCPP SCR Project 

Emission Increases from the

Project NOX SO2 PM PM10 PM2.5 CO VOC H2SO4 Lead GHGs

(CO2e)

Total Baseline Actual Emissions 24,029 8,373 644 801 550 1,444 5.79 14.1 0.115 10,058,126 

Total Projected Actual Emissions 4,783 8,403 647 1,134 843 1,449 5.81 251 0.115 10,092,496 

Emission Increases -19,246 30 3 333 293 5 0.02 237 0 35,992 

Significant Emission Rate10 40 40 25 15 10 100 40 7 0.6 75,00011

Significant Emission Increase No No No Yes Yes No No Yes No No 

 

10 See 40 CFR 52.21(b)(23) 

11 For an existing major stationary source undergoing a modification such as this, PSD permitting for GHGs will occur only when the project would also cause a net increase in GHG emissions of 

75,000 tpy or more on a CO2e basis and greater than 0 tpy on a mass basis. See 40 CFR 52.21(b)(23) and (49)(iv); PSD and Title V Permitting Guidance for Greenhouse Gases (March 2011) at 13-15. 
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Table 4 Emission Factors for Determining Projected Actual Emissions, Units 4 and 5 

Pollutant Emission Factor Basis

NOX 0.098 lb/MMBtu 40 CFR 49.5512(i)(3) BART FIP, 30-day rolling average 

SO2 0.1722 lb/MMBtu Combined average emission rate from baseline actual emissions 

PM 0.0132 lb/MMBtu Combined average emission rate from baseline actual emissions 

PM10 0.0222 lb/MMBtu 

92% of filterable PM BART limit (0.015 lb/MMBtu), 0.0040 lb/MMBtu for 

condensable PM12, 0.00435 lb/MMBtu proposed H2SO4 BACT limit 

PM2.5 0.0163 lb/MMBtu 

53% of filterable PM BART limit (0.015 lb/MMBtu), plus 0.0040 

lb/MMBtu for condensable PM13, plus 0.00435 lb/MMBtu proposed 

H2SO4 BACT limit 

CO 0.02969 lb/MMBtu Combined average emission rate from baseline actual emissions 

VOC 0.000119 lb/MMBtu Combined average emission rate from baseline actual emissions14

H2SO4 0.00435 lb/MMBtu Proposed BACT limit 

Lead 2.36E-06 lb/MMBtu Combined average emission rate from baseline actual emissions15

CO2e 206.8 lb/MMBtu Combined average emission rate from baseline actual emissions 

Table 5 Determining Projected Actual Emissions, Future Annual Heat Input, Units 4 and 5 Combined 

Projected Heat Input, Excluding Demand Growth

Hourly maximum heat input16 (MMBtu/hr) 14,822 

Annual maximum heat input (MMBtu/yr) 129,840,720 

Baseline heat input17 (MMBtu/yr) 97,258,307 

Future expected maximum annual capacity factor, without Project-related 

increases 89.35% 

Future expected maximum annual heat input, w/o Project-related 

increases (MMBtu/yr) 116,012,683 

Project related increases in fuel use from SCR18, percentage of annual heat 

input 0.3% 

Increase in annual heat input caused by Project-related increase in fuel 

(MMBtu/yr) 348,038 

Heat input for determining projected actual emissions, MMBtu/yr 

(baseline heat input + Project-related increases) 97,606,345 

 

12 See Table A-1.1 – Monthly Baseline Emissions – in the Application. PM10 organics assumed to be 20% of 0.02 lb/MMBtu, AP-42 Table 1.1-

5. 

13 See Table A-1.1 – Monthly Baseline Emissions – in the Application. PM2.5 organics assumed to be 20% of 0.02 lb/MMBtu, AP-42 Table 1.1-

5. 

14 The Applicant used an emission factor from the EPRI Emission Factor Handbook. This is not a readily available document and was not 

included in the Application. Nevertheless, we re-calculated the PSD applicability analysis using higher emission from AP-42 – 0.06 lb/ton and 

this did not change the overall conclusion. This is expected, as the Project does not affect VOC emissions other than the 0.3% increase in fuel 

use. 

15 The Applicant used an emission factor from the EPRI Emission Factor Handbook. We re-calculated the PSD applicability analysis using a 

higher emission in AP-42 – 0.000507 lb/ton – and this did not change the overall conclusion. This is expected, as the Project does not affect 

VOC emissions other than the 0.3% increase in fuel use. 

16 Both units combined, expected maximum 24-hour average, see footnote 1, Page 4-1, of the Application. 

17 Determined from the baseline actual emissions calculations using AMPD data for the January 2011 through December 2012 period. 

18 See Table A-9 – Estimated Increased Fuel Use due to SCR Parasitic Load and Economize Bypass, Application. 
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 5.2.3: Step 2 – Significant Net Emissions Increase

A net emissions increase is the sum of the increase in emissions from a project (i.e. projected actual emissions) and 

any other increases and decreases in actual emissions at the major stationary source that are contemporaneous with 

the particular change. The PSD regulations provide specific criteria to determine whether other emissions increases or 

decreases are contemporaneous and otherwise creditable as discussed in more detail below. 

An increase or decrease in actual emissions is considered contemporaneous if it occurs between (1) the date five years 

before construction on the Project commences; and (2) the date that the increase from the Project occurs. 40 CFR 

52.21(b)(3)(ii). There is one emissions increase and one emissions decrease within the contemporaneous period 

associated with the FCPP SCR Project. The increase occurred from the addition of an auxiliary boiler in 2012.19 The 

contemporaneous emissions decreases occurred from shutdown of Units 1-3 in January 2014. Our basis for 

determining these two changes are creditable contemporaneous emissions increases and decreases is provided below. 

Pursuant to 40 CFR 52.21(b)(3)(iii) an increase or decrease in actual emissions is creditable only if: 

1. The Administrator or other reviewing authority has not relied on it in issuing a permit for the source under 40 

CFR 52.21, which permit is in effect when the increase or decrease in actual emissions from the particular 

change occurs. 40 CFR 52.21(b)(3)(iii)(a). 

Analysis: Requirement met. FCPP has never been issued a PSD permit. As such, these changes, and 

specifically the emissions reductions in actual emissions from shutting down Units 1 – 3, have not been relied 

on in issuing a permit under 40 CFR 52.21 for this source. 

2. The increase or decrease in emissions did not occur at a Clean Unit except as provided in paragraphs (x)(8) 

and (y)(10) of 40 CFR 52.21. 40 CFR 52.21(b)(3)(iii)(b). 

Analysis: Not applicable. This criterion appears in the PSD regulations but is not applicable as the definition 

for Clean Unit was vacated in 2005. 

3. As it pertains to an increase or decrease in fugitive emissions (to the extent quantifiable), it occurs at an 

emissions unit that is part of one of the source categories listed in paragraph (b)(1)(iii) of this section or it 

occurs at an emissions unit that is located at a major stationary source that belongs to one of the listed source 

categories. 40 CFR 52.21(b)(3)(iii)(c). 

Analysis: Not applicable. The contemporaneous emission changes from shutting down Units 1 – 3 and 

installing the auxiliary boiler do not include fugitive emissions. 

4. An increase or decrease in actual emissions of sulfur dioxide, particulate matter, or nitrogen oxides that 

occurs before the applicable minor source baseline date is creditable only if it is required to be considered in 

calculating the amount of maximum allowable increases remaining available. 40 CFR 52.21(b)(3)(iv). 

Analysis: Requirement met. These emissions changes are occurring at a major stationary source and must be 

included in calculations of the amount of maximum allowable increase remaining available (also referred to as 

“increment”) because the changes occurred after the major source baseline dates in 40 CFR 52.21(b)(13)(ii) 

and (14)(i).20 That is, the FCPP was not an increment-consuming source because it was in operation before 

 

19 See Addendum at 4, construction commenced on November 4, 2012 and the boiler became operational on March 25, 2013. 

20 See also, EPA’s 1990 New Source Review Workshop Manual – Chapter C, pages C10-11, for additional information on increment 

consumption and expansion. 
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July 2014 

the minor source baseline date and is a part of the background concentration in its baseline area. However, 

any changes to a major source in actual emissions after the minor source baseline date have the potential to 

expand or consume increment and must be included in determining the allowable increase remaining available 

in the baseline area. See 40 CFR 42.21(b)(13)(ii)(b). 

5. An increase in actual emissions is creditable only to the extent that the new level of actual emissions exceeds 

the old level. 40 CFR 52.21(b)(3)(v). 

Analysis: Requirement met. The contemporaneous increase in actual emissions (installation of auxiliary boiler) 

is based on the potential to emit of the unit, as it is a new unit and the old level of emissions is zero. 

6. Decrease in actual emissions is creditable only to the extent that: 

a. The old level of actual emissions or the old level of allowable emissions, whichever is lower, exceeds 

the new level of actual emissions (40 CFR 52.21(b)(3)(vi)(a)); 

Analysis: Requirement met. The contemporaneous decrease of actual emissions from shutting down 

Units 1-3 meets this requirement because the new level of actual emissions associated with Units 1 – 

3 is zero and the old level of actual emissions is 551.5 tpy of PM10, 421.8 tpy of PM2.5 and 3.1 tpy of 

SAM emissions. As such, the old level of actual emissions (551.5/421.8 tpy) exceeds the new level of 

actual emissions (0 tpy). See Section 5.2.4 below. 

b. It is enforceable as a practical matter at and after the time that actual construction on the particular 

change begins (40 CFR 52.21(b)(3)(vi)(b); 

Analysis: Requirement met. The shutdown of Units 1-3 is enforceable as a practical matter because 

shutting down those units is required by EPA’s BART FIP, as APS’s chosen compliance method, as 

identified in APS’s December 30, 2013 letter.21

c. It has approximately the same qualitative significance for public health and welfare as that attributed 

to the increase from the particular change (40 CFR 52.21(b)(3)(vi)(c). 

Analysis: Requirement met. The emission decreases resulting from the shutdown of Units 1-3 have 

the same qualitative significance for public health and welfare as that attributed to the increases from 

the FCPP SCR Project. Units 1-3 are the same type of equipment, coal-fired EGU’s, as those 

modified by the Project. As such, the decreases in emissions of PM10, PM2.5 and SAM emissions 

from Units 1-3 have the same qualitative impact on public health and welfare as the PM10, PM2.5 and 

SAM emissions from Units 4 and 5. Although the SAM emissions increase from the FCPP SCR 

Project is greater than the decrease from shutting down Units 1 – 3, the proposed permit requires 

FCPP to install and operate BACT for SAM emissions. 

7. An increase that results from a physical change at a source occurs when the emissions unit on which 

construction occurred becomes operational and begins to emit a particular pollutant. Any replacement unit 

that requires shakedown becomes operational only after a reasonable shakedown period, not to exceed 180 

days. 40 CFR 52.21(b)(3)(viii). 

Analysis: Requirement met. The auxiliary boiler became operational on March 25, 2013, and is within 

the contemporaneous period. See Addendum at 4. 

 

21 See also letter dated March 21, 2014 from D. Bloomfield to Navajo Nation Air Quality Control Program and U.S. EPA Re: Four Corners 

Units 1, 2, and 3 Retired Unit Exemption. 
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July 2014 

8. 40 CFR 52.21(b)(21)(ii) shall not apply for determining creditable increases and decreases. 40 CFR 

52.21(b)(3)(ix). 

Analysis: Requirement met. As required by 40 CFR 52.21(b)(3)(i)(b) the definition for baseline actual 

emissions in 40 CFR 52.21(b)(48) is used to determine creditable increases and decreases, except for 

paragraphs (b)(48)(i)(c) and (b)(48)(ii)(d). These paragraphs relate to the particular 24-month period that can 

be chosen for determining baseline actual emissions. By excluding these paragraphs, a different 24-month 

period can be used for each contemporaneous increase or decrease. The definition of actual emissions in 40 

CFR 52.21(b)(21) is not used for determining creditable increases and decreases, including paragraph (ii). 

Based on this information we have determined the emissions increases resulting from installation of the auxiliary 

boiler and the emissions decreases from the shutdown of Units 1-3 are creditable emission increases and decreases. 

Section 5.2.4 Calculation of Contemporaneous Emissions Increases and Decreases 

Below we provide our basis for determining the specific amount of creditable emissions increases and decreases. This 

amount is based on the definition of baseline actual emission in 40 CFR 52.21(b)(48). 

New Limited-Use Auxiliary Boiler 

For a new emissions unit, the baseline actual emissions shall equal zero and, thereafter, shall equal the unit’s potential 

to emit. 40 CFR 52.21(b)(48)(iii). 

Analysis: Requirement met. Baseline actual emissions for the limited use auxiliary boiler was considered to be zero, and 

thereafter the unit’s potential to emit. 

Units 1-3 

For the purposes of determining contemporaneous emission decreases, baseline actual emissions for an existing 

electric utility steam generating unit is the average rate, in tons per year, at which the unit actually emitted the pollutant 

during any consecutive 24-month period selected by the owner or operator within the 5-year period immediately 

preceding when the owner or operation begins actual construction of the project – in July 2015. 40 CFR 

52.21(b)(48)(i). In this case, APS chose the same January 2011 through December 2012 period, for all pollutants, used 

for Units 4 and 5. 

Further, the definition for baseline actual emissions22 applicable to utility units identifies that: 

1. The average rate shall include fugitive emissions to the extent quantifiable, and emissions associated with 

startups, shutdowns, and malfunctions. 40 CFR 52.21(b)(48)(i)(a). 

Analysis: Requirement met. Emissions from Units 1-3 are not fugitive and the emissions data used 

included all emissions during the 24-month period, including any emissions that may have been 

associated with startup, shutdown, or malfunction. Application at Table A-1.4 (Annual Average 

Emissions Based on Rolling 24-Month Average – Units 1, 2, and 3) and Addendum at 1-2 and 

Attachment E. 

2. The average rate shall be adjusted downward to exclude any non-compliant emissions that occurred while the 

source was operating above any emission limitation that was legally enforceable during the consecutive 24-

month period. 40 CFR 52.21(b)(48)(i)(b). 

 

22 As previously stated, per 40 CFR 52.21(b)(3)(i)(b), paragraph (b)(48)(i)(c) of the definition for baseline actual emissions does not apply to this 

analysis and was not included in this portion of the analysis. 
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July 2014 

Analysis: Requirement met. During the particular period, January 2011 through December 2012, the only 

applicable emission limitations to Units 1-3, according to FCPP’s title V permit23, were: 

· SO2 – 12% of the potential combustion concentration assuming all of the sulfur in the coal is 

converted to SO2; 

· SO2 – 17,900 lb/hr; 

· PM – 0.050 lb/MMBtu; 

· NOX – 0.85 lb/MMBtu – Units 1 and 2; 

· NOX – 0.65 lb/MMBtu – Unit 3; 

· The total plant-wide NOX emissions shall not exceed 335,000 pounds per 24-hour period when 

coal burning equipment is operating, on a plant-wide basis; for each hour when coal burning 

equipment is not operating, this limitation shall be reduced. If the unit which is not operating is 

Unit 1, 2, or 3, the limitation shall be reduced by 1,542 lb per hour for each unit which is not 

operating. If the unit which is not operating is Unit 4 or 5, the limitation shall be reduced by 

4,667 lb per hour for each unit which is not operating 

The data used for this analysis, which is based on EPA’s AMPD data, does not indicate that Units 1-3 

operated above these limits at any time during the 24-month period, so the emission rates do not need to be 

adjusted downward. Application at Table A-1.1 (Monthly Baseline Emissions) and Addendum at 1. 

3. The average rate shall not be based on any consecutive 24-month period for which there is inadequate 

information for determining annual emissions, in tons per year, and for adjusting this amount if required by 

paragraph (b)(48)(i)(b) of this section. 40 CFR 52.21(b)(48)(i)(d). 

Analysis: Requirement met. Sufficient information to determine baseline emissions for PM10, PM2.5 and 

SAM is available by using heat input data provided by EPA’s AMPD, stack test data for filterable PM and 

SAM and emission factor information for condensable PM and estimates of PM10 and PM2.5 fractions 

available through EPA AP-42 – Compilation of Air Pollutant Emission Factors or the EPRI Emission 

Factor Handbook. Application at page 69 (erroneously labeled Table A-1.1, which already exists). 

4. For a new emissions unit, the baseline actual emissions for purposes of determining the emissions increase 

that will result from the initial construction and operation of such unit shall equal zero; and thereafter, for all 

other purposes, shall equal the unit's potential to emit. 40 CFR 52.21(b)(48)(iii). 

Analysis: Not applicable. Units 1-3 are not new emissions units. 

5. For a PAL for a stationary source, the baseline actual emissions shall be calculated for existing electric utility 

steam generating units in accordance with the procedures contained in 40 CFR 52.21(b)(48)(i), for other 

existing emissions units in accordance with the procedures contained in 40 CFR 52.21(b)(48)(ii), and for a 

new emissions unit in accordance with the procedures contained in 40 CFR 52.21(b)(48)(iii). 40 CFR 

52.21(b)(48)(iv). 

Analysis: Not applicable. The FCPP SCR Project is not applying for a PAL permit. 

Table 6 below provides our summary of the creditable contemporaneous emissions increases and decreases associated 

with the FCPP SCR Project. We note that the emissions information provided in this Fact Sheet is based on the 

calculations provided by APS in the Application. Application at Table A-1.1 (Monthly Baseline Emissions). In our 

review of the Application there were certain instances where emissions could have be calculated slightly differently, 

 

23 See Section II.A.2 of the FCPP Title V (No. NN-ROP-05-07) issued by the Navajo Nation Environmental Protection Agency. 
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July 2014 

but did not affect the overall conclusion. Our supplemental calculations are provided separately in EPA Region 9 – 

Supplemental Emissions Analysis – FCPP SCR Project and are a part of the administrative record for this action. 

Table 6 Contemporaneous Emission Increases and Decreases for the FCPP SCR Project 

Emission Unit PM10 PM2.5 H2SO4

Units 1-3 -551.5 -421.8 -3.1 

Limited-Use Auxiliary Boiler 0.96 0.96 <0.001 

Combined contemporaneous emission 

changes 

-550.5 -420.8 -3.1 

Section 5.3: Summary of PSD Applicability Determination 

As demonstrated in Tables 1-7, because the FCPP SCR Project will cause both a significant emissions increase and 

significant net emissions increase of SAM emissions, this Project is subject to the PSD program for SAM emissions as 

a major modification to an existing major source. For emissions of PM10 and PM2.5, the emissions decreases from the 

contemporaneous shutdown of Units 1 – 3 exceed the amount of the increases from the FCPP SCR Project. 

Therefore, the FCPP SCR Project does not result in a significant net emissions increase for either PM10 or PM2.5. 

Sections 6-8 of this Fact Sheet provides our basis for proposing to issue a PSD permit allowing installation of the SCR 

systems on Units 4 and 5 as provided in the FCPP SCR Project. Consistent with the requirements of the PSD 

program we conducted a BACT determination for SAM, an ambient air quality impact report, and an additional 

impacts analysis. 

Table 7 Summary of PSD Applicability Determination for the FCPP SCR Project 

PSD Applicability PM10 PM2.5 H2SO4

Emissions increases from the Project (see Table 3) 333 293 237 

Combined contemporaneous emission changes (see Table 6) -550.5 -420.8 -3.1 

Significant net emissions (sum of Project increases and 

contemporaneous changes) -217.5 -127.8 233.9 

Significant emission rate 15 10 7 

PSD Applicable? No No Yes

Section 6.0: Determination of Best Available Control Technology

Section 6.1: Overview of Top-Down BACT Analysis

This section describes EPA’s BACT analysis for the control of SAM emissions from this facility. Section 169(3) of the 

Clean Air Act defines BACT as follows: 

"The term 'best available control technology' means an emission limitation based on the maximum degree of 

reduction of each pollutant subject to regulation under the Clean Air Act emitted from or which results from 

any major emitting facility, which the permitting authority, on a case-by-case basis, taking into account energy, 

environmental, and economic impacts and other costs, determines is achievable through application of 

production processes and available methods, systems, and techniques, including fuel cleaning or treatment or 

innovative fuel combustion techniques for control of each such pollutant. In no event shall application of 

‘best available control technology’ result in emissions of any pollutants which will exceed the emissions 
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July 2014 

allowed by any applicable standard established pursuant to section 111 [New Source Performance Standards 

or NSPS] or 112 [or NESHAPS] of the Clean Air Act." 

See also 40 CFR 52.21(b)(12). In accordance with 40 CFR 52.21(j), the regulations require an analysis of best available 

control technology for each regulated NSR pollutant for any modification at an existing major stationary source that 

causes a significant net emissions increase at the source. This requirement applies to each proposed emissions unit at 

which a significant net emissions increase in the pollutant would occur as a result of a physical change or change in 

the method of operation in the unit. 

EPA’s process for the case-by-case BACT analysis (referred to as a “top-down” BACT analysis) is a well-established 

procedure that EPA’s Environmental Appeals Board (EAB) has consistently followed in adjudicating PSD permit 

appeals. See, e.g., In re Desert Rock Energy Center, 14 E.A.D. ___, slip op. at 52-53 (Sept. 24, 2009); In re Knauf, 8 

E.A.D. 121, 129-31 (EAB 1999); In re Maui Electric, 8 E.A.D. 1, 5-6 (EAB 1998). 

In brief, under the top-down process, all available control technologies are ranked in descending order of control 

effectiveness. The Applicant and reviewing agency first examine the most stringent (i.e. most effective) emission 

control technology. That technology with the emissions limit that it can consistently achieve is established as BACT 

unless it is demonstrated that technical considerations, or energy, environmental, or economic impacts, justify a 

conclusion that the most stringent technology is not achievable for the particular project under review. If the most 

stringent technology is eliminated, then the next most stringent option is evaluated until BACT is determined. The 

top-down BACT analysis is a case-by-case exercise for the particular source under evaluation. In summary, the five 

steps involved in a top-down BACT evaluation are: 

1. Identify all available control options with practical potential for application to the specific emission unit for the 

regulated pollutant under evaluation; 

2. Eliminate technically infeasible technology options; 

3. Rank remaining control technologies by control effectiveness; 

4. Evaluate the most effective control alternative and document results, considering energy, environmental, and 

economic impacts as appropriate; if top option is not selected as BACT, evaluate next most effective control 

option; and 

5. Select BACT, which will be the most stringent technology not rejected based on technical, energy, 

environmental, and economic considerations and establish the emissions limit that can be consistently achieved 

with that technology. 

Section 6.2: BACT for SAM

The FCPP SCR Project is triggering BACT due to the significant net emissions increase of SAM emissions from Units 

4 and 5 following installation of SCR emissions controls. The PSD Application included a top-down BACT analysis 

for SAM emissions. EPA has independently evaluated the top-down BACT analysis in the Application, as discussed 

below. 

Step 1 – Identify All Control Options

The inherently lower-emitting control options include: 

· Fuel switching 

· Fuel washing 

· Fuel processing 

· SCR catalyst SO2 to SO3 conversion rate 

The available add-on control technologies include: 

· Ammonia injection 
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July 2014 

· Spray dryer absorber 

· Dry sorbent injection 

· Wet electrostatic precipitation 

Step 2 – Eliminate Technically Infeasible Options

Fuel switching

The coal that is used by the FCPP is supplied entirely by the nearby Navajo Mine (owned by the Navajo Nation 

Transitional Energy Company, LLC) and the lease allowing the FCPP to operate on the Navajo Nation requires the 

FCPP to use coal as its primary source of fuel. Application at 4-4. The sulfur content of the Navajo Mine coal is 

approximately 0.78%, with a heating value of 8,776 Btu/lb, and is considered low sulfur coal although there are lower 

sulfur coals available in other states, such as Wyoming. Application at 4-4, Coal Market Module at Table 12-524. The 

FCPP may have somewhat lower SAM emissions if we could have required it to burn a lower sulfur coal because it 

would reduce the amount of sulfur available to oxidize to SO3 and condense to SAM emissions. However, as a minemouth facility (i.e. combusts only coal from an adjacent mine), requiring FCPP to switch to a different type of coal is 

not technically feasible or available as a method for reducing SAM emissions. The use of mine-mouth coal is a 

fundamental component of the FCPP. We note that EPA’s Environmental Appeals Board has considered whether a 

power plant that operates as a mine-mouth facility is required to consider coal from a different source in the BACT 

analysis. The Environmental Appeals Board generally has held that requiring a power plant to burn coal from an 

entirely different source is not technically feasible or available and is not, therefore, required as part of the BACT 

analysis. In re: Prairie State Generating Company, 13 E.A.D. 1 (EAB 2006), ), affirmed in Sierra Club v. EPA, 499 F.3d 

653 (7th Cir. 2007). . Therefore, it is not necessary for us to further evaluate requiring FCPP to use a different source 

of coal as BACT for SAM emissions for this Project. 

Switching to a fuel other than coal, such as natural gas, may also lower the SAM emissions caused by installation of 

SCR Units 4 and 5. Similarly as stated above, because FCPP is a mine-mouth power plant built to combust coal from 

the Navajo Mine located on the Navajo Nation, switching to a fuel other than coal would fundamentally redefine the 

source, is technically infeasible, and is eliminated from further consideration in this BACT analysis. The 

Environmental Appeals Board has also considered this question and has held that switching to a different fuel type is 

not technically feasible for a mine-mouth plant and that was designed and developed specifically to burn one type of 

coal. Therefore, it is not necessary for us to further evaluate requiring FCPP to use a fuel other than coal as BACT for 

SAM emissions for this Project. 

Fuel Washing

Coal washing was introduced as a method for reducing the ash, sulfur, and other impurities of coal prior to 

combustion. Coal washing generally involves breaking coal down into smaller pieces and mixing it with a liquid to 

allow the unwanted portions to be separated. The coal must then be dried prior to use. However, coal washing has 

never been commercially available for use on lower sulfur subbituminous coals, those less than 1% sulfur, such as the 

coal from the Navajo Mine. Lignite and subbituminous coal are relatively free of impurities and generally are not 

cleaned.25 FCPP burns subbituminous coal. Because subbituminous coal is usually not cleaned, we could not find any 

information on the expected emission reductions achievable with coal washing for low sulfur subbituminous coals. 

Presumably the less sulfur in the coal the harder it will be to remove significant amounts successfully. This technology 

appears to only have been applied to higher sulfur coals. Given this information we do not consider this technology 

feasible because it is not applicable to the FCPP SCR Project and is eliminated from further consideration in this 

BACT analysis.26

 

24 See coal sulfur contents by region in Table 12.5 of the Coal Market Module, Assumptions to the Annual Energy Outlook 2014, U.S. Energy 

Information Administration. http://www.eia.gov/forecasts/aeo/assumptions/pdf/coal.pdf. Sulfur content is provided in lb sulfur per MMBtu. 

FCPP burns coal containing approximately 0.89 lb sulfur per MMBtu. 

25 See Section 2.2 of Coal Cleaning, Final Report, and Emission Factor Documentation for AP-42, Section 11.10, and available here: 

http://www.epa.gov/ttn/chief/ap42/ch11/bgdocs/b11s10.pdf. 

26 EPA’s NSR Workshop Manual, page B.17. An available technology is “applicable” if it can reasonably be installed and operated on the source 
FCPP SCR Project Page 23 of 39 

Fact Sheet 

July 2014 

Fuel Processing (or Refined Coal) 

Research on pre-combustion coal processing techniques, such as Evergreen Energy’s K-Fuel® process, has been 

conducted over the last 30 years. In general, the goal is to develop a process to upgrade low grade subbituminous coal 

and lignite into low moisture products. For example, the K-Fuel® process uses heat and pressure to remove 

approximately 30% of the moisture from lower-rank subbituminous and lignite coals containing 20-30% moisture. 

This moisture removal improves the heating value, reduces transportation costs, increases boiler efficiency and may 

reduce emissions on a lb per MMBtu basis. The coal from the Navajo Mine has a relatively low moisture content of 

11-13%. Application at 4-6. To date, the production of process fuels has been limited to a demonstration plant that 

began operation in Gillette, Wyoming in 2005. Although designed to be a commercial plant, the plant experienced 

design and operation problems and was idled in March 2008. Fuel processing, therefore, does not appear to be 

technically feasible or commercially available at this time, including K-Fuel®, and EPA is proposing to eliminate it 

from further consideration in this BACT analysis. 

SCR Catalyst SO2 to SO3 Conversion Rate 

As previously discussed, the use of SCR systems results is a substantial decrease in NOX emissions, and for the FCPP 

will result in improved visibility in 16 nearby National Parks and Wilderness Areas, but causes a side reaction that 

increases SO3 emissions through the oxidation of SO2, which then condenses to result in increased SAM emissions. 

The catalyst that FCPP is proposing to use is a low oxidation catalyst. To reduce the conversion rate of SO2 to SO3

even further there are “ultra low” conversion catalysts for SCR systems that contain even less vanadium pentoxide 

(V2O5), the main culprit for conversion to SO3, and therefore can achieve lower conversion to SO3 oxidation. 

However, using a lower vanadium pentoxide SCR catalyst will also result in less NOX emissions reductions and the 

need for more catalyst to achieve the same rate of NOX reduction. The addition of more catalyst would cause even 

more SAM emissions. Suppliers have improved the low oxidation catalyst by using materials such as molybdenum and 

tungsten that reduce NOX while minimizing SO3 conversion, but they are not as effective as vanadium pentoxide for 

NOX control and SO3 oxidation is not completely mitigated. Application at 4-8. However, the SO2 to SO3 conversion 

rate for “ultra low” conversion catalyst could be as low as 0.167% per catalyst layer.27

Typical SCR catalyst configurations use a 2+1 (two initial layers plus one future layer) configuration on a coal-fired 

power plant. Due to the type of high ash coal that is combusted at FCPP (typically 23% ash and 8,776 Btu/lb), a 3+1 

design is needed to manage pluggage due to ash. Application at 4-8; EPA BART FIP, 77 FR at 51635-36. Increased 

pluggage increases the needed catalyst surface area to maintain the desired NOX emission reduction rate, which then 

increases SO3 emissions further. 

The FCPP SCR Project is designed for 4 catalyst layers (3+1) with a 3-year catalyst replacement schedule. FCPP 

BART FIP, 77 FR at 51,635-36. By balancing the type of catalyst used (e.g. less or more vanadium pentoxide) and 

catalyst replacement rate, the desired SO2 to SO3 conversion rate can be achieved. 

In addition, EPA found one instance of a vendor, CoaLogix®, claiming catalyst conversion rates of 0.1%. However, 

this conversion rate is based on empirical data conducted from a single optimization study. Their website states28: 

Results from this study demonstrate that the use of regenerated catalyst can significantly lower SO2 oxidation 

rates in some applications. Unused plate and honeycomb catalyst modules were regenerated to compare the 

oxidation rate and catalytic activity before and after regeneration. In the case of regenerated honeycomb 

catalyst, for example, SO2 oxidation rates were measured as low as 0.1 percent29, which is comparable to the 

 

type under consideration. http://www.epa.gov/ttn/nsr/gen/wkshpman.pdf. 

27 EPA Region 9 – August 2012 – Four Corners Power Plant Final Rulemaking – Response to Comments, pages 95-96. 

28 http://coalogix.com/catalyst-regeneration/catalyst-cleaning-rejuvenation/. Additional information is available at: 

http://www.netl.doe.gov/publications/proceedings/06/ecc/pdfs/Harrison_Summary.pdf and http://static.coalogix.com/wpcontent/uploads/P-010-OptimizationofSCR-NETL2006.pdf - An Experimental Program to Optimize Catalyst Regeneration for Lower 

Oxidation of SO2 to SO3.

29 Although not specified, EPA assumes this is a reference to the conversion rate per catalyst layer. 
FCPP SCR Project Page 24 of 39 

Fact Sheet 

July 2014 

conversion rates achieved only through the use of more costly, ultra-low conversion catalyst... Details and 

results of this study were published in a an article entitled New Life for Old Catalyst which appeared in the 

March 2006 edition of Power Engineering magazine. 

 

EPA does not consider this information, based solely on one particular optimization study, to be sufficient to further 

consider CoaLogix®’s technology as technically feasible. 

The use of lower conversion catalysts (other than CoaLogix®), and lower conversion rates than the conversion rate of 

1.0% proposed by the Applicant, is therefore considered a technically feasible technology. Because this option is 

technically feasible and commercially available, we will consider it further below in this BACT analysis. 

Ammonia Injection 

Ammonia-based systems designed for controlling SAM emissions typically involve ammonia injection into the flue gas 

upstream of a cold-side electrostatic precipitator.30 Ammonia will react with SO3 in the flue gas to form ammonia 

salts, mainly ammonium sulfate [(NH4)2SO4] and ammonium bisulfate [NH4HSO4]. Ammonia salt formation is 

dependent upon flue gas temperature and reagent stoichiometric ratios. Flue gas temperatures at the inlet to a coldside electrostatic precipitator are typically in the range of 300°F to 350°F, which will promote the formation of 

ammonium bisulfate. Ammonium bisulfate tends to make fly ash more cohesive, which can promote fly ash capture in 

a cold-side electrostatic precipitator. 

Ammonia injection for SAM differs significantly from the use of ammonia for SCR. When used for SCR, ammonia is 

injected after the economizer where the flue gas temperature is approximately 650 °F. After reacting with NOX, 

ammonia slip from the SCR is limited to approximately 10 ppmv. 

Ammonia is injected at high concentrations (up to 5,000 ppm) prior to the final control device, which is typically a 

cold-side ESP, as described above. Although ammonia injection has been successfully used for SAM control on coalfired units equipped with cold- side electrostatic precipitators, an ammonia injection system would not have a practical 

application on a unit equipped with a fabric filter, such as the FCPP, due to plugging and blockage issues associated 

with the sticky properties of ammonium bisulfate, nor does it appear to be identified as an applicable control option 

for sources other than those with ESPs.31 As such, we are eliminating ammonia injection from further consideration 

in this BACT analysis. 

Spray Dryer Absorber 

Spray dryer absorbers (SDAs) are a type of FGD designed and used to remove SO2 from combustion gases using a 

semi-dry scrubbing process. These devices also promote the removal of SAM emissions. Semi-dry scrubbing using an 

SDA involves the introduction of hydrated lime slurry into a reaction tower where it reacts with SO2 in the flue gas to 

form calcium sulfite solids. Unlike wet FGD systems (like the one in place at FCPP) that produce a slurry by-product 

that is collected separately from the fly ash, SDA systems produce a dry by-product that must be removed with the fly 

ash in the particulate control equipment. Therefore, an SDA system must be located upstream of the unit’s particulate 

control device. On existing units equipped with a fabric filter and wet FGD system such as FCPP, retrofitting the unit 

with SDA includes not only the redundant FGD control system but may also require fabric filter modifications. 

Application at Section 4.2.2.5. For the FCPP, an SDA system is considered technically feasible and further considered 

in this BACT analysis. 

Dry Sorbent Injection 

Dry sorbent injection (DSI) systems involve the injection of sodium- or calcium-based sorbents in the duct work from 

the boiler either: (1) before the SCR system, (2) after the SCR system but before the air preheater, or (3) after the air 

preheater. See Figure 2 above for reference. DSI systems consist of a storage silo, compressors or blowers to 

 

30 See Emission of Sulfur Trioxide From Coal-Fired Power Plants, page 15 - http://www.babcockpower.com/pdf/RPI-TP-0178.pdf. 

31 See, for example, Identification of (and Responses to) Potential Effects of SCR and Wet Scrubbers on Submicron Particulate Emissions and Plume Characteristics, 

page 4 (page 17 of the pdf). Available here: http://nepis.epa.gov/Adobe/PDF/P1000OS8.pdf. 
FCPP SCR Project Page 25 of 39 

Fact Sheet 

July 2014 

transport the sorbent to the duct, and associated piping. DSI using either a sodium or calcium- based sorbent is 

technically feasible. 

SBS InjectionTM Technology 

SBSTM is a trademarked DSI technology marketed by URS Corporation. The reagent used for SBS injection is 

sodium carbonate. In contrast to an SDA, which uses a slurry and dry sorbent injection, SBS injection uses a 

clear solution. The use of a clear solution eliminates problems associated with handling slurries, such as 

nozzle plugging and erosion. Dual fluid nozzles are used to produce small droplets that quickly form dry 

particles in the 1 to 10 micron range which are smaller than the 15 to 50 micron particles used for dry 

injection of sodium compounds or hydrated lime. 

 

Wet ESP 

Wet electrostatic precipitation (Wet ESP) is a type of particulate matter control device that uses water vapor saturated 

air streams. Wet ESPs are commonly used to remove liquid droplets such as SAM emissions from industrial process 

gas streams. The Wet ESP is also commonly used where the gases are high in moisture content, contain combustible 

particulate, or have particles that are sticky in nature. A Wet ESP is considered technically feasible for the FCPP SCR 

Project.

Step 3 – Rank Remaining Control Technologies 

The remaining control technologies for consideration are: 

· SCR Catalyst with a lower SO2 to SO3 Conversion Rate 

· Spray Dry Absorber (SDA) 

· Dry Sorbent Injection (DSI) (including SBS InjectionTM Technology) 

· Wet ESP 

To rank the remaining control technologies we evaluated SAM emissions limits for similar, pulverized coal (PC) 

boilers coal-fired power plants using a variety of technologies. A summary is provided in Table 8. We did not include 

boilers using circulating fluidized bed (CFB) technology in our summary, as limestone is generally used for assisting in 

creating the fluidized bed and greatly reduces SO2 and SO3 emissions during the combustion process. This is 

significantly different than the combustion process for PC boilers. Therefore, it is appropriate to eliminate SAM 

emission limits for CFB technology from consideration. 

As seen in this summary, the chosen control technologies and emissions limits vary greatly. In addition, there is no 

indication from the information we reviewed that more recent determinations have the lowest emission limits. We 

would expect more recent determinations to have lower emissions limits if the emissions limit was based on a newer, 

better technology. However, the available technologies today appear to be the same as those available over the last ten 

years. As detailed further below, based on our review of available information the variation in emission limits is mostly 

likely due to site-specific variations (e.g., fuel types, control technologies employed for other pollutants, type of SCR 

catalyst). 

SDA and DSI 

As seen in Table 8, the facilities with the lowest SAM emissions limits are in the range of 0.0010 to 0.0040 lb/MMBtu. 

Of the facilities in this range, the pollution control devices employed at these facilities varies and includes: (1) ESP + 

wet FGD, (2) baghouse + SDA, (3) baghouse +wet FGD, or (4) baghouse + DSI + Wet FGD. In addition, the 

lowest SAM emissions limits do not appear to be the most recent decisions. In reviewing these limits, we conclude 

that there is no clear and specific control technology used by the sources with the lowest emissions limits that is 

overwhelmingly better than any other particular technology or combination of technologies, particularly when it 

comes to the addition of SDA and DSI at FCPP. Consistent with the literature32, the chosen technology for SAM 

 

32 For example, see conclusions in SO3 Mitigation Guide and Cost Estimating Workbook available here: 
FCPP SCR Project Page 26 of 39 

Fact Sheet 

July 2014 

emissions appears to be highly dependent on site-specific factors (coal type, particulate matter controls, SO2 controls, 

etc.). Therefore, for the purposes of this analysis, we are grouping the addition of SDA or DSI technologies together 

(in conjunction with a particulate matter control device of either a baghouse or dry ESP), as one level of control to 

determine the best level of performance. This includes the SAM emissions limits in the range of 0.0012 to 0.0040 

lb/MMBtu. Note that the two lowest SAM emission limits in Table 8, and being grouped together for this analysis, 

did not require SDA or DSI. Both of these sources utilize wet FGD, which is already in use at FCPP. 

SCR Catalyst with a lower SO2 to SO3 Conversion Rate 

EPA has determined that the lowest achievable SO2 to SO3 conversion rate for the FCPP SCR Project is between 

0.5%33 and 0.67%34. APS states it will use SCR systems with a conversion rate of 1.0%. If a conversion rate of 0.5% 

was used instead this could have the potential to reduce SAM emissions by up to an additional 40% from APS’s 

proposed BACT emission limit of 0.00435 lb/MMBtu. However, APS indicated in its application that based on APS’s 

discussion with DSI and SBS vendors, available performance guarantees would not be affected by the lower precontrol emissions associated with an ultra-low oxidation SCR catalyst. As such, an ultra-low oxidation catalyst would 

not offer an emission performance advantage when compared to a low oxidation catalyst with DSI. This is likely 

based on the low sulfur coal used at FCPP and existing baghouses that could accommodate the difference in the SO3

when using a 1% conversion configuration versus a 0.5% configuration.35 That is, the outlet emissions from a 

baghouse are generally uniform and could accommodate additional inlet SO3 emissions without increasing outlet SO3

emissions from the baghouse. Nevertheless, we will still consider the use of 0.5% conversion catalyst in our analysis. 

Wet ESP 

Although none of the facilities with the lowest BACT limits employ a wet ESP we still consider this technology to 

represent the top level of performance – with potential emission reductions of 90%36 from APS’s estimated pre-add 

on control emission rate of 0.00751 lb/MMBtu. 

Technology Ranking 

Based on the considerations discussed above we are ranking the remaining control technologies as follows, in Table 9. 

The overall percent reduction includes reductions from the existing equipment and air pollution control devices, 

specifically the air preheater, the baghouse, and the wet FGD. These three pieces of equipment will affect the 

achievable emissions rate, and their effectiveness could change upon installation of SCR, and should be accounted for 

in our analysis. In addition, the rankings assume the emission limits in Table 8 are based on a 1.0% SO2 to SO3

conversion catalyst. It is expected this rate actually varies by source, especially among new and older installations. 

 

 

http://170.94.134.156/ftproot/pub/commission/p/Closed%20Permit%20Dockets%202006-2010/08-006-

P%20AEP%20Service%20Corp.%20&%20SWEPCO-Sierra%20Club%20&%20Audubon%28Consolidated%29/2009-03-06_HC_SCBP_EX_16.PDF. “The cost effectiveness of the various options depend on site specifics such as the location of the plant relative to reagent 

sources, coal combustion byproduct reuse and disposal practices, the sulfuric acid mist control level required, and the extent to which other 

particulate matter contributes to plume opacity”. Also, see SO3 Mitigation Strategy Process available here: 

http://www.netl.doe.gov/publications/proceedings/06/ecc/pdfs/White_Summary.pdf. “The result is a unit specific, least-cost mitigation 

recommendation to achieve the desired strategy objective.” See also, conclusions in A System Approach to SO3 Mitigation available here: 

http://www.babcock.com/library/Documents/br-1781.pdf. “In conclusion, a system approach to SO3 mitigation based on plant-specific 

conditions may reduce the overall cost of mitigation equipment.” 

33 In Section 4.2.2.6 of the Application, APS states that a 0.5% conversion rate may be achievable by increasing the catalyst replacement rate 

from every 3 years to every 2 years. 

34 See footnote 27. 

35 See, for example, email from S. Gray to L. Beckham dated June 2, 2014. 

36 See pages 2-3 of An Emissions Approach to SO3 Mitigation, Babcock & Wilcox, 2008, available at 

http://www.babcock.com/library/Documents/BR-1815.pdf. 
FCPP SCR Project Page 27 of 41 

Fact Sheet 

July 2014

Table 8 Summary of H2SO4 Emission Limits for PC Boiler, Coal-Fired EGUs 

Facility Location H2SO4 Limit Control Permit

Issuance

Comments

Newmont Nevada Energy Investment Nevada 2.06 lb/hr 

(equivalent to 

0.0010 lb/MMBtu) 

SDA, baghouse 12/21/2005 New unit(s) 

Naughton Plant (Unit 3) Wyoming 0.0012 lb/MMBtu Wet FGD, baghouse 5/20/2009 Existing unit, complying with BART - 

SCR will not be installed in lieu of 

converting to natural gas 

Santee Cooper Cross Generating Station South 

Carolina 

0.0014 lb/MMBtu Wet FGD, dry ESP 2/5/2004 Existing unit, synthetic minor limit 

Basin Electric Power Cooperative – Dry 

Fork 

Wyoming 0.0025 lb/MMBtu SDA, baghouse 10/15/2007 New unit(s) 

Hugo Generating Station Oklahoma 0.0037 lb/MMBtu Wet FGD, baghouse 2/9/2007 Project Cancelled 

Tenaska Trailblazer Energy Center Texas 0.0037 lb/MMBtu Wet FGD, baghouse 12/30/2010 Project cancelled 

Jim Bridger Power Plant (Units 3 and 4) Wyoming 0.0040 lb/MMBtu Wet FGD, dry ESP 6/17/2013 Existing unit 

Coleto Creek Unit 2 Texas 0.0040 lb/MMBtu SDA and baghouse 5/3/2010 New unit(s) 

Karn Weadock Generating Complex Michigan 0.0040 lb/MMBtu Wet FGD, DSI and 

baghouse 

12/29/2009 Project cancelled 

Desert Rock New 

Mexico 

0.0040 lb/MMBtu Wet FGD, DSI, 

baghouse 

 NA Project cancelled 

Dallman Power Plant - City of Springfield Illinois 0.005 lb/MMBtu Dry ESP, WFGD, 

WESP 

8/10/2006 New unit(s) 

Detroit Edison- Monroe Michigan 0.0050 lb/MMBtu Dry ESP and WFGD 12/21/2010 Existing unit 

Salt River Project - Coronado Generating 

Station 

Arizona 0.006 lb/MMBtu Low conversion 

catalyst, dry ESP 

1/22/2009 Existing unit 

Crystal River Power Plant Florida 0.0090 lb/MMBtu DSI, dry ESP, WFGD 5/18/2007 Existing unit 

AEP Generation Station Ohio 0.0075 lb/MMBtu Baghouse, WFGD, 

wet ESP 

10/8/2009 Project cancelled 

Elm Road Generating Station Wisconsin 0.0100 lb/MMBtu Baghouse, WFGD, 

wet ESP 

2004 New unit(s) 
FCPP SCR Project Page 28 of 41 

Fact Sheet 

July 2014

Table 9 Rank Remaining H2SO4 Control Technologies 

H2SO4 Control Technology Emission Rate Overall Percent

Reduction

Wet ESP + 0.5% Catalyst 0.00027 lb/MMBtu 99.2% 

DSI/SDA + dry ESP/baghouse +0.5% Catalyst 0.00060 – 0.0024 lb/MMBtu 98.3-93.2% 

Wet ESP + 1.0% Catalyst 0.00075 lb/MMBtu 97.9% 

DSI/SDA + dry ESP/baghouse +1.0% Catalyst 0.0010 – 0.0040 lb/MMBtu 97.2-88.6% 

0.5% Conversion Catalyst 0.0027 lb/MMBtu 92.3% 

Baseline (1% Conversion Catalyst)37 0.00751 lb/MMBtu 78.7% 

Step 4 –Economic, Energy and Environmental Impacts 

For this step we evaluate the most effective control alternative and document our results, considering energy, 

environmental, and economic impacts as appropriate. If the top option is not selected as BACT, we evaluate the next 

most effective control option. 

Currently, the top level of control is use of a wet ESP with a 0.5% conversion catalyst. The Applicant conducted a 

cost analysis to determine the cost effectiveness of a wet ESP. The Applicant’s analysis is provided in Tables 4-3 and 

4-4 of the Application. Our analysis is summarized in Table 10 below and is based on the Applicant’s analysis, except 

that we made the following adjustments38: 

· Taxes, direct costs – reduced from 10% to 7% of capital cost – EPA’s cost control manual 

· Foundation & supports, direct installation costs – reduced from 20% to 4% - EPA’s cost control manual 

· Electrical, direct installation costs – reduced from 10% to 8% of purchased equipment cost – EPA’s cost 

control manual 

· Demolition and Relocation, removed – unclear basis 

· Contingencies, indirect costs – reduced from 20% to 3% - EPA’s cost control manual 

· Miscellaneous costs – removed – unclear basis 

· Variable annual costs – reduced operating hours from 8760 to 7884 – expected maximum annual capacity 

factor 

Table 10 Wet ESP Cost Analysis 

Cost Amount Basis

Capital Cost

Direct Costs 

Purchased equipment costs 

WESP system includes casing, electrical $41,208,000 Engineering estimate 

Ash handling system $1,888,000 Engineering estimate 

Booster fans $2,467,000 Engineering estimate 

Electrical system upgrades $2,467,000 Engineering estimate 

Ductwork $5,664,000 Engineering estimate 

Subtotal Capital Cost (CC) $53,694,000 

 

37 The baseline emission rate is found in Table 4-1 of the Application. 

38 Some adjustments were based on EPA’s Control Cost Manual for ESPs, which is available here: 

http://www.epa.gov/ttn/catc/dir1/cs6ch3.pdf
FCPP SCR Project Page 29 of 39 

Fact Sheet 

July 2014 

Cost Amount Basis

Instrumentation and controls $2,684,700.00 CC x 5% 

Freight $2,416,230.000 CC x 4.5% 

Taxes $3,758,580.00 CC x 7% 

Total purchased equipment cost (PEC) $62,554,000 

 

Direct installation costs 

Foundation & supports $2,502,160 PEC x 4% 

Handling & erection $31,277,000 PEC x 50% 

Electrical $5,004,320 PEC x 8% 

Piping $625,540 PEC x 1% 

Insulation $1,251,080 PEC x 2% 

Painting $625,540 PEC x 1% 

Total direct installation costs (DIC) $41,285,640 

Total direct costs (DC) = (PEC) + (DIC) $103,840,000 

 

Indirect Costs 

Engineering $10,384,000 DC x 10% 

Construction management $5,192,000 DC x 5% 

Startup and spare parts $1,557,600 DC x 1.5% 

Performance test $100,000 Engineering estimate 

Contingencies $3,115,200 DC x 3% 

Total indirect costs (IC) $20,348,800 

Total capital investment (TCI) = (DC)+(IC) $124,189,000 

 

Annual Cost 

Direct Annual Costs 

Fixed annual costs 

Maintenance materials and labor $3,115,200 DC x 3% 

Operating labor $73,000 1 FTE and 72,800 $/year 

Total fixed annual costs $3,188,000 

 

Variable annual costs 

Operating hours 7884 

hours/yr (~90% capacity 

factor) 

Reagent [Mg(OH)2] $66,226 80 lb/hr and 210 $/ton 

Auxiliary power $1,324,512 2,800 kW and 0.06 $kW 

ID fan power $1,986,768 4,200 kW and 0.06 $kW 

Service water $331 350 gpm and 0.002 $/kgal 

Total variable annual costs $3,377,837 

Total direct annual costs (DAC) $6,566,000 
FCPP SCR Project Page 30 of 39 

Fact Sheet 

July 2014 

Cost Amount Basis

 

Indirect Annual Costs 

Overhead $1,912,800 

60% of Total fixed annual 

costs 

Taxes, Insurance, and Administration $4,964,560 4% of Total installed cost 

Capital Recovery $5,451,897 7.0%, 20 years, 0.09439 

Total indirect annual costs (IDAC) $12,329,000 

 

Total Annual Cost (TAC)=(DAC)+(IDAC) $18,895,000 

 

Pre-control H2SO4 emissions, tpy 435.6 

Post-control H2SO4 , tpy (90% reduction) 43.6 

H2SO4 emission reduction, tpy 392 

Cost effectiveness $48,000 per ton

The value of $48,000 per ton of SAM emissions removed is not within the typical range of what EPA considers cost 

effective for this pollutant.39 Based on this cost effectiveness calculation, which shows that a wet ESP is more cost 

effective than the Applicant’s estimate of $178,000/ton, a wet ESP is still not cost effective40. This determination 

appears to be consistent with the fact that the lowest BACT determinations reviewed in Table 9 did not require wet 

ESP. We are not aware of a BACT determination that determined $48,000+ per ton to be cost effective. As such, we 

are eliminating wet ESP from further consideration based on economic impacts. This applies to both wet ESP 

options – 0.5% conversion catalyst and 1.0% conversion catalyst. 

With elimination of wet ESP, the next highest level of control is DSI/SDA with a baghouse or dry ESP and 0.5% 

conversion catalyst. The only difference between this option and the next best option is the use of 0.5% conversion 

catalyst versus 1.0% conversion.41 The Applicant indicated that a lower catalyst conversion rate might be achievable, 

while meeting the required BART NOX emission rate, by replacing the catalyst on a more frequent basis – 2 years 

instead of 3 years. APS estimated this would cause an extra $5,000,000 in operating costs on an annual basis. 

Application at Section 4.2.4.3. Because the cost of controls is otherwise equal between this option and the next best 

option, using 1% conversion catalyst, this option would cost approximately $50,000 per ton of additional SAM 

emissions removed.42 We do not consider an incremental cost of $50,000 per ton to be cost effective for BACT. 

Looking at incremental cost effectiveness is appropriate in this case, and consistent with EPA’ New Source Review 

Workshop Manual, because this control option and the next control option are the two dominant control options and 

would cost the same, except for the incremental cost of more frequent catalyst replacement associated with the top 

 

39 For example, in EPA Region 9’s recently finalized PSD permit for the SPI-Anderson facility an average cost of $8,930 per ton for CO was not 

considered cost effective. EPA Region 9 has not recently conducted a cost effective analysis for SAM emissions. However, for the Deseret 

Power Electric Cooperative PSD permit, EPA Region 8 determined that an average cost effectiveness for a wet ESP of $26,039 to $175,234 per 

ton was economically prohibitive for BACT. This analysis included the consideration of SAM emissions as a portion of condensable PM10. See 

Final Statement of Basis at 73-74. In addition, Region 8 also provided a sample of other cost effectiveness determinations by other permitting 

agencies. See Statement of Basis, at 33-37. All of the determinations that a technology was cost prohibitive are at lower $/ton values than being 

evaluated for FCPP. Region 8’s Statement of Basis is available here: 

http://www2.epa.gov/sites/production/files/documents/FinalStatementOfBasis.pdf. 

40 The Applicant appears to have conducted an incremental cost analysis, looking at the cost of reducing additional SAM from their proposed 

BACT limit of 0.00435 lb/MMBtu. We do not think that is appropriate for this portion of the analysis, as the average cost of the control 

technology first needs to be considered. 

41 While according to Table 9 the next best option is wet ESP and 1.0% conversion catalyst, the use of wet ESP was already eliminated based on 

cost. 

42 Based on an estimated 40% reduction from APS’s projected actual emissions of 250.6 tons per year. 
FCPP SCR Project Page 31 of 39 

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level of control.43 While we have not calculated the specific average cost effectiveness, such a calculation would have 

no effect on our determination because the cost of the two technologies is otherwise equal. 

In addition, we must also consider that (1) it is possible the additional cost of more frequent catalyst replacement 

would cause the 0.5% control option to not be cost effective on an average basis, as this option is clearly more costly, 

(2) based on the Applicant’s discussions with vendors the 0.5% catalyst option may not result in any real emission 

reductions (given the proposed use of hydrated lime and a baghouse we are inclined to agree with this reasoning), (3) 

the Applicant must balance achieving the required NOX BART limit with the appropriate catalyst configuration while 

also meeting the SAM BACT limit, and (4) more frequent catalyst replacements may increases hazardous waste from 

the FCPP. 

Therefore, considering all of the available information, the 0.5% catalyst is not cost effective, may not result in 

additional emission reductions, or may interfere with the Applicant’s ability to meet the NOX BART limit and is 

eliminated from further consideration based on economic and environmental impacts. 

This leaves DSI or SDA, in conjunction with a baghouse or dry ESP, and 1.0% conversion catalyst as the top level of 

control carried on to Step 5. There are no economic, energy, or environmental impacts that would exclude the use of 

these technologies. 

Step 5 – Select BACT 

In this step we select BACT, which will be the most stringent technology not rejected based on technical, energy, 

environmental, and economic considerations. The Applicant’s proposal is that the addition of DSI, utilizing hydrated 

lime as the sorbent, is BACT in conjunction with its existing wet FGD and baghouse. This is consistent with the top 

level of control remaining from Step 4 – use of DSI or SDA. 

However, determining the achievable SAM emission limit for the DSI systems with the existing controls is not as 

straightforward. We are not aware of a BACT determination that is the same as this case – retrofit at a facility using 

DSI and a baghouse. While there are two determinations for the selected control train (DSI, baghouse and wet 

FGD)44 both of those projects were cancelled. As such, we must look at site-specific factors and similar facilities in 

making our determination. 

Site-Specific Factors 

· FCPP will need to operate its SCR systems with an additional layer of catalyst compared to typical 

installations in order to meet EPA’s BART FIP NOX limit. The additional layer of catalyst (3+1) may increase 

the achievable SAM emission rate by increasing the oxidation of SO2 to SO3. 

· Source testing at FCPP prior to installation of the SCR controls indicates that greater than 90% reduction of 

SAM emissions is achieved across the air preheater. However, as explained above, the addition of SCR will 

result in some flue gas bypassing the economizer, causing the flue gas to be hotter and potentially increasing 

the exit temperature from the air preheater. The flue gas may be above the dew point for SAM and would 

mean less SAM would condense and be removed from the air preheater.45 

· Source testing at FCPP indicates only 57.39% reduction of SO3 is currently being achieved across the 

baghouse and wet FGD. The use of a baghouse at FCPP for particulate control is expected to be beneficial in 

controlling SAM emissions, compared to other retrofit application such as using a dry ESP. Generally, SAM 

 

43 See NSR Workshop Manual at B.43, which states: “A comparison of incremental costs can also be useful in evaluating the economic viability 

of a specific control option over a range of efficiencies.” (emphasis added) 

44 The two facilities listed in the RBLC are Hugo Generating Station and Tenaska Trailblazer Energy Center both with a SAM emissions limit of 

0.0037 lb/MMBtu.

45 See Addendum at 4-5. 
FCPP SCR Project Page 32 of 39 

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July 2014 

emissions reductions of up to 90% across the baghouse can be expected.46,47The addition of DSI using 

hydrated lime as the BACT technology proposed by APS, is expected to be particularly beneficial in 

combination with a baghouse to make even greater reductions possible. Not only will SO3 in the flue gas 

prior to the baghouse react with hydrated lime to form particulates that are removable in the baghouse, but 

the hydrated lime will also affect the chemistry of the filter cake of the baghouse and further enhance capture. 

Similar Facilities 

The two lowest SAM emissions limits for a facility with a baghouse (although not with DSI, but with SDA instead) 

are the Newmont Nevada Energy Investment at 0.0010 lb/MMBtu in Nevada and Basin Electric Power Cooperative 

– Dry Fork in Wyoming at 0.0025 lb/MMBtu. However, there are three significant factors to consider: 

1. The Newmont Nevada facility has recently, since adding the final layer of catalyst, had trouble meeting its 

SAM emissions limit and is currently in the process of requesting the limit be revised.48

2. Although the Basin Electric Power Cooperative – Dry Fork facility has consistently achieved its 0.0025 

lb/MMBtu limit, it is a limit for a newly constructed unit, which can more easily be designed for optimal 

emission reductions.49

3. SDA technology (also referred to as a dry FGD) is a more advanced form of acid gas control than DSI and 

generally used as a primary SO2 control device. In the case of FCPP, DSI is supplementing the existing acid 

gas controls – wet FGD. 

In addition there are two other facilities with emission limits less than 0.0025 lb/MMBtu – the Naughton Plant in 

Wyoming and the Santee Cooper Cross Generating Station in South Carolina. However, the Santee Cooper Cross 

Generating Station’s determination is from 2004, and appears to have conducted only one initial stack test. Since then 

no other BACT determinations have been near this limit except for the Naughton Plant. And, the Naughton Plant 

will not install SCR on its coal-fired boiler because it is converting to natural gas instead.50 

Vendor Guarantee 

EPA was also contacted by the SBS TechnologyTM vendor and was provided a vendor guarantee for the FCPP SCR 

Project of 0.0015 lb/MMBtu.51 This low guarantee was provided specifically because FCPP has low sulfur coal and a 

baghouse. While we agree with the vendor that the low sulfur coal and baghouse will enhance FCPP’s ability to 

control SAM emissions we do not believe it is appropriate in this case to base the BACT limit on a single vendor 

estimate. As stated in EPA’s NSR Workshop Manual (page B.20): 

EPA does not consider a vendor guarantee alone to be sufficient justification that a control option will work. 

...Generally, decisions about technical feasibility will be based on chemical, and engineering analyses...in 

conjunction with information about vendor guarantees. 

 

46 See page 3 of An Emissions Approach to SO3 Mitigation, Babcock & Wilcox, 2008, available at 

http://www.babcock.com/library/Documents/BR-1815.pdf. 

47 See page 25-26 of Identification of (and Response to) Potential Effects of SCR and Wet Scrubbers on Submicron Particular Emissions and Plume Characteristics, 

EPA-600/R-04-107, August 2004, available at http://nepis.epa.gov/Adobe/PDF/P1000OS8.pdf. 

48 See for example, letter from D. Laybourn to Jeffrey Kinder Re: TS Power Plant Class I Permit AP4911-2502 Newmont Nevada Energy 

Investment, LLC 

49 Generally, EPA does not consider a retrofit application to be a sufficient basis for determining a technology or level of control is not feasible, 

as it is generally a matter of cost. However, in this case EPA, is considering other existing controls (baghouse and wet FGD) in our analysis that 

will have an effect on the achievable emission reductions with the selected add-on controls - DSI. The existing baghouse and wet FGD would 

not be expected to perform as well as a newly built facility, without upgrades. Such upgrades, to make the FCPP control train equivalent to other 

new facilities, would likely make the addition of SDA cost prohibitive for BACT. As such, this difference is an area of concern as to whether or 

not the FCPP could consistently achieve a BACT limit of 0.0025 lb/MMBtu. 

50 See Memo to File dated July 10, 2014 Re: SAM Emissions Limits in Permits Issued by Wyoming Department of Environmental Quality 

51 See Email from S. Gray to L. Beckham dated June 2, 2014. 
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In this case we believe the site-specific factors and emission limits for similar facilities create significant uncertainty in 

the achievable emission limit. A vendor must only meet its guarantee on a one-time basis, whereas the BACT limit 

must be met over the entire life of the unit over a range of operating conditions. As such, we do not think 0.0015 

lb/MMBtu represents BACT in this case. In addition, the use of SBS Technology would also negatively affect the 

FCPP’s ash that it currently sells for reuse. The sodium bicarbonate would increase the sodium content of the fly ash 

and potentially make the FCPP’s fly ash unsalable. As such, we would likely eliminate this technology under Step 4 as 

well due to environmental impacts as the fly ash would have to be landfilled. In addition, APS estimated the cost of 

not selling fly ash to be $4,000,000 per year. 

Section 6.3 BACT for SAM Emissions

As noted above, there are site-specific technical reasons that EPA must consider. EPA cannot determine the best 

achievable SAM emissions rate for the FCPP SCR Project by simply by looking at the single lowest BACT limit for 

another pulverized coal-fired boiler. Review of the RBLC demonstrates that there is a relatively wide range of SAM 

emissions rates that have been determined to be BACT from the lowest at 0.0012 lb/MMBtu (Naughton in 2009) to 

0.01/lb/MMBtu (Elm Road Generating Station in Wisconsin using a combination of a baghouse, a Wet ESP and a 

Wet FGD). The majority of the reported SAM emissions limits in the RBLC are between 0.0040 lb/MMBtu to 0.006 

lb/MMBtu. 

The SAM emission rate proposed by the Applicant is 0.00435 lb/MMBtu. However, EPA is proposing to find that 

the combination of the FCPP’s wet FGD, baghouse and DSI can achieve a lower SAM emissions limit. Based on the 

available data and our technical evaluation of the site-specific factors associated with the FCPP SCR Project, we are 

proposing to select 0.0025 lb/MMBtu as a BACT demonstration limit, as discussed below, for the FCPP SCR Project. 

The SAM emissions limit of 0.0025 lb/MMBtu is the most stringent limit for a similar facility with a baghouse (Basin 

Electric Power Cooperative in Wyoming). BACT will be achieved through the use of hydrated lime in DSI systems 

just prior to the baghouses at each Unit. 

Given the uncertainties associated with whether or not this same level of control can be consistently achieved, with a 

wet FGD, DSI system and baghouse rather than SDA and a baghouse (as installed at Basin Electric Power 

Cooperative – Dry Fork), we are proposing a BACT demonstration limit. This means that the initial BACT limit will 

be a proposed limit of 0.00435 lb/MMBtu, but after a 2-year demonstration period the limit will become 0.0025 

lb/MMBtu, unless APS can demonstrate that 0.0025 lb/MMBtu is unachievable. The proposed permit contains 

criteria for how APS would make such a demonstration (see Conditions 31-32) and requires that the permittee receive 

written notification from EPA indicating the Permittee shall apply for a permit revision to include the achievable limit 

(see Condition20). For purposes of the required analyses for this permit (e.g. ambient air quality impact report, 

additional impacts analysis), we are using the higher BACT limit of 0.00435 lb/MMBtu to ensure there will be no 

adverse impacts even at a higher SAM limit. 

Compliance with this limit will be demonstrated by annual stack testing and through monitoring of the hydrated lime 

injection rate. However, during the initial demonstration period, if APS intends to demonstrate 0.0025 lb/MMBtu is 

not achievable, then at least 6 stack tests will be required as part of its demonstration. 

Note that a BACT determination must be no less stringent than an NSPS standard under section 111 of the Act. 

However, there is no SAM NSPS emissions limit for EGUs. 

Section 7: Ambient Air Quality Impact Report

Clean Air Act section 165 and EPA’s PSD regulations at 40 CFR 52.21 require an examination of the impacts of the 

proposed FCPP SCR Project on ambient air quality. Using air quality models, the Applicant must demonstrate that 

the facility’s emissions of the PSD-regulated air pollutants would not cause or contribute to a violation of (1) the 

applicable National Ambient Air Quality Standards (NAAQS), or (2) the applicable PSD increments. 40 CFR 52.21(k). 
FCPP SCR Project Page 34 of 39 

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July 2014 

The FCPP SCR Project does not trigger the PSD program for any pollutant with a NAAQS or PSD increment. 

Therefore, this analysis is not required for this permitting action. 

However, 40 CFR 52.21(m) requires that any application for a PSD permit shall contain an analysis of ambient air 

quality in the area that the major stationary source or major modification would affect. In the case of a major 

modification, this analysis applies to each pollutant that would result in a significant net emissions increase. For the 

FCPP SCR Project the only pollutant triggering a significant net emissions increase is SAM emissions. In addition, for 

any pollutant triggering this analysis, but for which there is not a NAAQS, the air quality monitoring data requirement 

by 40 CFR 52.21(m)(1) shall contain such data as the Administrator determines is necessary to assess ambient air 

quality. 40 CFR 52.21(m)(1)(ii). However, 40 CFR 52.21(i)(5) provides that the Administrator may exempt a source 

from the requirements in 40 CFR 52.21(m) if the source would have impacts below the levels established for certain 

pollutants in 40 CFR 52.21(i)(5)((i) or if a level has not been established for a particular pollutant. EPA has not 

established a regulatory level for SAM emissions. 

For this proposed PSD permit that applies only to SAM emissions, we are exercising our discretion under 40 CFR 

52.21(i)(5) to not require monitoring data. Our decision to not require monitoring data is based on the fact that there 

are no ambient air standards in place for evaluating ambient SAM emissions. Therefore, monitoring data for SAM 

emissions would not provide a useful measurement to inform our decision regarding this proposed PSD permit. 

EPA recognizes that an emissions increase of SAM may generally be of concern due to potential health impacts. At 

elevated concentrations, SAM will form visible plumes. However, as discussed below we do not expect any adverse 

health impacts as a result of the FCPP SCR Project because it will not cause elevated concentrations of SAM, as 

measured in ppmv. 

At elevated concentrations, SAM emissions can form visible plumes. At some other facilities with wet FGD scrubbers 

like the FCPP, blue SAM plumes have been observed and referred to as plume blight. Physiological responses such as 

eye irritation and breathing difficulty have been reported for episodes involving visible plumes containing SAM 

aerosols at ground level.52 Fine plume problems are expected to occur when SAM vapor or aerosol concentrations 

leaving the ESP or the wet FGD exceed the equivalent of 2 ppmv. These concentrations have the potential to form 

aerosols in the plume that will have an adverse effect on plume visibility and appearance53 – which could then lead to 

adverse health effects. 

In this case, the Applicant’s proposed SAM emission rate of 0.00435 lb/MMBtu is equivalent to 1.5 ppmv, and our 

proposed limit of 0.0025 lb/MMBtu is equivalent to 0.86 ppmv. Given that the Project’s emissions will be well below 

2.0 ppmv with either proposed limit, we have concluded there will not be adverse visible plume effects or air impacts 

associated with SAM emissions from this Project. 

Section 7.1 Class I Area Impact Analysis

In addition to the analysis of PSD Class I Increment compliance (which does not apply for the proposed permit 

because there is no increment for SAM emissions), the PSD Class I analysis must also address impacts to special 

attributes of a Class I area that deterioration of air quality may adversely affect. Such attributes are referred to as Air 

Quality Related Values and are specified by the Federal Land Manager (FLM) of the respective Class I area. These 

analyses generally include visibility impacts, such as plume blight or contribution to regional haze, and impacts from 

acid deposition. 

 

52 See Identification of (and Responses to) Potential Effects of SCR and Wet Scrubbers on Submicron Particulate Emissions and Plume Characteristics, EPA-600/R04-107, August 2004, at 2. Available at: http://nepis.epa.gov/Adobe/PDF/P1000OS8.pdf

53 Id. at 59. 
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Based on the 2010 guidance from the Federal Land Managers’ Air Quality Related Values Work Group (FLAG 

2010)54, this Project screens out of visibility and acidic deposition analyses due to the overall emissions decreases 

associated with this Project. (See Section 8 below.) 

A project locating greater than 50 km from the nearest Class I area is considered to have negligible impacts with 

respect to Class I AQRV’s if its total SO2, NOX, PM10, and SAM annual emissions (in tons per year, based on 24-hour 

maximum allowable emissions), divided by the distance (in km) from the Class I area (Q/D) is 10 or less. Because 

FCPP is greater than 50 km from the nearest Class I areas (the nearest being Mesa Verde National Park), and the sum 

of emissions of SO2, NOX, PM10 and SAM associated with this Project causes an overall decrease in the value of Q, 

further analysis of AQRV impacts is not triggered.55 No further analysis of Class I area impacts is required. There are 

16 Class I areas near the FCPP that are not expected to be adversely affected by the FCPP SCR Project. The overall 

intent of the FCPP SCR Project, as required by EPA’ BART FIP is to improve visibility and AQRVs in these areas. 

As provided in 40 CFR 52.21(p), EPA is directed to provide written notice of any permit application for a proposed 

major modification, if the emissions may affect a Class I area, to the appropriate Federal Land Manager (FLM). For 

this Project the FLM is the National Park Service. In this case, the Applicant provided the application to both EPA 

and the National Park Service electronically. In addition, EPA re-sent the application to the NPS at a later date and 

received confirmation from the NPS that no further analysis was required.56

Section 8: Additional Impacts Analysis

40 CFR 52.21(o) of the PSD regulations require that EPA evaluate other potential impacts on 1) soils and vegetation; 

2) growth; and 3) visibility impairment. The depth of the analysis generally depends on existing air quality, the quantity 

of emissions, and the sensitivity of local soils, vegetation, and visibility in the source's impact area. 

The Project is not expected to have any adverse additional impacts as discussed below. Other than the temporary 

construction activities associated with the installation of the SCR and ancillary systems, there will be very little change 

in the operational support needed to run Units 4 and 5. The temporary construction activities will primarily occur 

within the footprint of the existing facility and on established transportation corridors. Therefore, EPA is concluding 

that there will not be increases in air pollution impacts due to growth of emissions related to the FCPP SCR Project. 

This project results in an approximately 19,000 tpy decrease in NOX emission and up to 237 tpy increase in SAM 

emissions. Any effects on soils, vegetation, or visibility due to the potential of the 237 tpy increase in SAM emissions 

will be offset by the actual 19,000 tpy NOX emission decreases noted above because NOX and SAM both contribute 

to visibility impairment and acid deposition on soils and vegetation. As such, no negative impacts on soils, vegetation, 

or visibility are expected as a result of the FCPP Project. In addition, the proposed permit requires BACT for SAM 

emissions. 

Section 9: Tribal Minor NSR

EPA must also consider whether this project is subject to the New Source Review Program in Indian Country found 

in 40 CFR 49.151-161. This program includes preconstruction permitting requirements for minor modifications at 

major sources located in Indian country. The requirements of this permitting program are triggered based on the 

applicability criteria contained in 40 CFR 49.153. The FCPP is an existing major source and subject to the specific 

applicability criteria in 40 CFR 49.153(a)(1)(ii). 

Step 1 of the applicability determination requires evaluation of: 

 

54 Available at: http://www.nature.nps.gov/air/pubs/pdf/flag/FLAG_2010.pdf. 

55 See email dated July 21, 2014 from D. Shepherd to L. Beckham. 

56 Id. 
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Fact Sheet 

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1. For the pollutant being evaluated, determine whether your proposed modification is subject to review under 

the applicable major NSR program. 

Analysis: Requirement met. As previously discussed in this Fact Sheet, the FCPP SCR Project is subject to the 

applicable major NSR program (the PSD program) for SAM emissions. 

2. If the modification at your existing major source does not qualify as a major modification under that program 

based on the actual-to-projected-actual test, it is considered a minor modification and is subject to the minor 

NSR program requirements, if the net emissions increase from the actual-to-projected-actual test is equal to 

or exceeds the minor NSR thresholds. 

Analysis: Not Applicable. Tables 11-13 below contain the minor NSR permitting thresholds and the results of 

the actual-to-projected-actual test for the FCPP SCR Project. EPA and the Applicant followed the same 

hybrid actual-to-projected-actual test for this evaluation as for the evaluation under the PSD program. Based 

on this information the Project does not have a net emissions increase from the actual-to-projected-actual test 

above any minor NSR threshold subject to review. 

Table 11 Actual-to-Projected Actual Emissions from the Project 

Emission Increases from the

Project NOX SO2 PM PM10 PM2.5 CO VOC Lead

Total Baseline Actual Emissions 24,029 8,373 644 801 550 1,444 5.79 0.115 

Total Projected Actual Emissions 4,783 8,403 647 1,134 843 1,449 5.81 0.115 

Emission Increases -19,246 30 3 333 293 5 0.02 0 

Tribal Minor NSR Thresholds 10 10 10 5 3 10 10 0.1 

Above Thresholds? No Yes No Yes Yes No No No 

Table 12 Contemporaneous Emission Increases and Decreases 

Emission Unit PM10 PM2.5 SO2

Units 1-3 -551.5 -421.8 -3,110.1 

Limited-Use Auxiliary Boiler 0.96 0.96 0.05 

Total -550.5 -420.8 -3,110.1 

Table 13 Net Emission Increases for the Project and Tribal Minor NSR Applicability 

Tribal Minor NSR Applicability PM10 PM2.5 SO2

Significant emissions increases from the Project 333 293 30 

Combined contemporaneous emission decreases -550.5 -420.8 -3,110 

Net emissions increase -217.5 -127.8 -3,080 

Tribal NSR Threshold 15 10 7 

Minor NSR Applicable? No No No

 
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Fact Sheet 

July 2014 

3. For a modification at your existing minor source go to Step 2 (40 CFR 49.153(a)(1)(ii)(B). 

Analysis: Not Applicable. The FCPP is not an existing minor source, so Step 2 and Step 3 of the applicability 

determination process do not apply. 

Increase in an Emission Unit’s Annual Allowable Emissions Limit 

Per 40 CFR 49.153(a)(2), a physical or operational change at a minor or major source that would increase an emissions 

unit's allowable emissions of a regulated NSR pollutant above its existing annual allowable emissions, but does not 

otherwise trigger the Minor NSR Program in Indian Country requires a permit revision to reflect the increase in the 

allowable emissions prior to making the change. Such an increase in the annual allowable emissions may be 

accomplished through an administrative permit revision as provided in 40 CFR 49.159(f). 

Except for SAM emissions, which are subject to permitting review under the PSD program, the FCPP SCR Project 

does not trigger the Minor NSR Program in Indian Country, but causes increases in allowable emissions (as 

determined by 40 CFR 49.153(b)) for: 

· Truck traffic will increase due to the delivery of reagent for the dry sorbent injection system resulting in 

increased fugitive emissions from paved plant roads. 

· Truck traffic will increase due to the delivery of urea pellets, 29% aqueous ammonia, or anhydrous ammonia 

for the SCR system resulting in increased fugitive emissions from paved plant roads. 

· A new pneumatic dry sorbent truck unloading system and silo will be installed. 

· A new pneumatic urea pellet truck unloading system and silo may be installed if this reagent option is selected 

for the SCR system or a new ammonia truck unloading station and storage tank will be installed if either the 

aqueous or anhydrous ammonia option is selected for the SCR system. 

Consistent with this requirement, the proposed permit contains permit conditions for these increases in allowable 

emissions from this new equipment and operations. 

In addition, we note that the proposed permit also contains the limited use auxiliary boiler added to the FCPP in 2012 

and potentially subject to the Minor NSR Program in Indian Country. In 2012, EPA Region 9 reviewed the addition 

of the auxiliary boiler as an administrative amendment under 40 CFR 49.153(a)(2). In our approval of the boiler we 

noted that FCPP did not currently have an NSR permit to administratively amend and would include the boiler at the 

time FCPP is issued an NSR permit. 

Section 10: Endangered Species Act

Pursuant to section 7 of the Endangered Species Act (ESA), 16 U.S.C. 1536, and its implementing regulations at 50 

C.F.R. Part 402, EPA is required to ensure that any action authorized, funded, or carried out by EPA is not likely to 

jeopardize the continued existence of any endangered or threatened species or result in the destruction or adverse 

modification of such species’ designated critical habitat. EPA has determined that this PSD permitting action is 

subject to ESA section 7 requirements. 

APS submitted a draft Biological Assessment (BA), developed by AECOM, to examine potential impacts from our 

issuance of the PSD permit to listed species and critical habitat, which is included in our administrative record for this 

action. The BA identified seven species and their critical habitat that are listed, or proposed to be listed, as federally 

endangered or threatened that have the potential to occur within the Action Area of the facility. The Action Area 

includes areas where potential direct and indirect impacts on listed species and critical habitat may occur. The BA 

refers to the Action Area as the Deposition Area, and is the area where the predicted increase in soil concentration of 

metals (as a proxy for deposition of acids and other particulate matter) after 25 years of future full load operation of 

Units 4 and 5 with SCR, was modeled to be more than one percent of the current concentrations. The species that 
FCPP SCR Project Page 38 of 39 

Fact Sheet 

July 2014 

may occur within this area are the Mexican spotted owl (threatened), the Southwestern willow flycatcher (endangered), 

the yellow-billed cuckoo (proposed for listing as threatened), the Colorado pikeminnow (endangered), the razorback 

sucker (endangered), the Mancos milk-vetch (endangered), and the Mesa Verde cactus (threatened). 

The primary threats to the listed or proposed species relate to habitat destruction or modification. However, the 

construction activities associated with the installation of SCR and the operation of the SCR will occur within the 

existing fenceline and disturbed areas of FCPP. The increase in SAM emissions from operating the SCR is not 

expected to alter the pH of soils or surface water in the Deposition Area, and acid deposition rates of sulfur and 

nitrogen are expected to be well below critical load guidelines put forth by the WHO (World Health Organization). 

Although acid deposition was previously identified as a potential threat to the Mancos milk-vetch, there is no data to 

suggest that acid deposition poses an actual threat to the species. 

In an email dated May 19, 2014, EPA requested U.S. Fish and Wildlife Service’s (the Service) concurrence with EPA’s 

determination under ESA section 7 that the proposed PSD permit for the FCPP SCR Project is not likely to adversely 

affect listed species. On June 23, 2014, the Service concurred with EPA’s determination. 

Section 11: National Historic Preservation Act

Section 106 of the NHPA requires EPA to consider the effects of this permit action on properties listed in or eligible 

for inclusion in the National Register of Historic Places. To make this determination, EPA prepared a Cultural 

Resources Report for the FCPP SCR Project. 

For purposes of the NHPA review, we are proposing the Area of Potential Effect (APE) to include the existing 

footprint of the FCPP as well as a 50 km radius around the FCPP, to account for potential impacts from increases in 

SAM emissions. 

Because the FCPP is on Navajo Nation, EPA Region 9 is consulting with Navajo Nation’s Tribal Historic 

Preservation Officer (THPO) on this Project. In addition, EPA sent letters to other Indian tribes in the area of the 

FCPP to inquire if any of the tribes have historical interest in the particular project and the APE, and to inquire 

whether any of the tribes wished to consult with EPA in the Section 106 process. Upon such a request, EPA will 

consult with any tribes prior to seeking final concurrence from the Nation Navajo THPO and prior to issuing a final 

permit. 

We note that the FCPP itself is eligible for inclusion in the National Register of Historic Places. The FCPP has been 

in existence since the late 1960’s and has been an integral part of the economy and community of Navajo Nation since 

that time. In addition, there are numerous other historic properties within the APE. EPA is currently proposing to 

determine that the FCPP SCR Project will not adversely affect historic properties. 

A copy of the Cultural Resource Report is part of administrative record for this permitting action. Any interested 

party is welcome to bring particular concerns or information to our attention regarding this project’s potential effect 

on historic properties. 
FCPP SCR Project Page 39 of 39 

Fact Sheet 

July 2014 

Acronyms & Abbreviations 

Act Clean Air Act [42 U.S.C. Section 7401 et seq.] 

BA biological assessment 

BACT best available control technology 

BART best available retrofit technology 

Btu British thermal units 

CAA Clean Air Act [42 U.S.C. Section 7401 et seq.] 

CEMS continuous emissions monitoring system 

CFR Code of Federal Regulations 

CO carbon monoxide 

CO2 carbon dioxide 

CO2e carbon dioxide equivalent 

DSI dry sorbent injection 

EAB Environmental Appeals Board 

EPA U.S. Environmental Protection Agency 

ESA Endangered Species Act 

ESP electrostatic precipitator 

FCPP Four Corners Power Plant 

FGD flue gas desulfurization 

FIP federal implementation plan 

FWS U.S. Fish and Wildlife Service 

GHG greenhouse gases 

HHV higher heating value 

km kilometers 

MMBtu million British thermal units 

MW megawatts of electrical power 

NAAQS national ambient air quality standards 

NHPA National Historic Preservation Act 

NO nitrogen oxide or nitric oxide 

NO2 nitrogen dioxide 

NOX oxides of nitrogen (NO + NO2) 

NSPS new source performance standards 

NSR new source review 

PM particulate matter 

PM2.5 particulate matter less than 2.5 micrometers (μm) in diameter 

PM10 particulate matter less than 10 micrometers (μm) in diameter 

ppm parts per pillion 

PSD Prevention of Significant Deterioration 

PTE potential to emit 

RBLC U.S. EPA RACT/BACT/LAER Clearinghouse 

SAM sulfuric acid mist or H2SO4

SCR selective catalytic reduction 

SDA spray dryer absorber 

SO2 sulfur dioxide 

THPO Tribal Historic Preservation Officer 

tpy tons per year 

VOC volatile organic compounds