Appendix E 

Public Process 
(page intentionally blank) 
The Arizona Department of Environmental Quality (ADEQ) will open a public comment period and hold a 

public hearing to receive comments on Arizona’s Proposed Regional Haze State Implementation Plan (SIP) 

to address visibility impairment at Arizona’s Class I areas (e.g., national parks and wilderness areas). This 

SIP specifically addresses the requirements under the federal Regional Haze Rule, 40 CFR 51.308. The SIP 

will be available on ADEQ’s Web site at: 

PUBLIC COMMENT AND HEARING NOTICE 

ARIZONA DEPARTMENT OF ENVIRONMENTAL QUALITY 

AIR QUALITY DIVISION 

PROPOSED REGIONAL HAZE STATE IMPLEMENTATION PLAN 

as required by 40 Code of Federal Regulations 51.308 

http://www.azdeq.gov/environ/air/haze/index.html 

The public comment period will open on October 28, 2010. The public hearing on the proposed Regional 

Haze SIP will be held on December 2, 2010, at 3:00 p.m., ADEQ, Room 3175, 1110 W. Washington Street, 

Phoenix, Arizona. The public comment period for the proposed SIP will end upon the closure of this public 

hearing or at 5:00 p.m. on December 2, 2010. 

All written comments must be received at ADEQ by 5:00 p.m. on December 2, 2010. Comments 

postmarked on or before that date will be accepted. Comments should be addressed, faxed, or e-mailed to:

Lisa Tomczak 

Air Quality Planning Section 

Arizona Department of Environmental Quality 

1110 W. Washington Street, Mail Code 3415A 

Phoenix, AZ 85007 

FAX: (602) 771-2366 

E-Mail: tomczak.lisa@azdeq.gov

The draft report is also available for review at the location below. 

Arizona Department of Environmental Quality 

Records Management Center 

1110 W. Washington Street 

Phoenix, Arizona 85007 

(602) 771-4380 

Meeting Agenda

Printed on recycled paper 

AIR QUALITY DIVISION

Proposed Regional Haze State Implementation Plan 

Under Section 308 of the Federal Regional Haze Rule 

Thursday, December 2, 3:00 p.m. 

Room 3175, Arizona Department of Environmental Quality 

1110 West Washington Street, Phoenix, Arizona 

Pursuant to A.R.S. § 38-431.02, notice is hereby given that the above-referenced meeting is open to the 

public. Materials distributed for the meeting are available for viewing in the Arizona Department of 

Environmental Quality Library, 1110 West Washington Street, Phoenix, Arizona. 

1. Welcome and Introductions 

2. Purposes of the Public Hearing 

3. Procedure for Making Public Comment 

4. Brief Overview of the Proposed Regional Haze State Implementation Plan 

5. Question and Answer Period 

6. Oral Comment Period 

7. Adjournment of the Public Hearing 

Additional information is available on the ADEQ website at 

http://www.azdeq.gov/environ/air/haze/index.html, or call Lisa Tomczak, ADEQ Air Quality Division, at 

(602) 771-4450 or 1-800-234-5677, Ext. 771-4450. 

Persons with a disability may request a reasonable accommodation, such as a sign language interpreter, by 

contacting Dan Flukas at (602) 771-4795 or 1-800-234-5677, Ext. 771-4795. Requests should be made as 

early as possible to allow sufficient time to make the arrangements for the accommodation. This 

document is available in alternative formats by contacting ADEQ TDD phone number at (602) 771-4829. 


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Proposed Arizona Regional Haze State Implementation Plan 

Under Section 308 of the Federal Regional Haze Rule 

Oral Proceeding 

Hearing Officer Script 

December 2, 2010 

Mark Lewandowski: Good afternoon. We are ready to get started here. Welcome to this Arizona 

Department of Environmental Quality hearing on the proposed Regional Haze State 

Implementation Plan under Section 308 of the Federal Regional Haze rule. I now open this 

public hearing to receive comments on the Proposed Regional Haze SIP (from this point on, I 

will just refer to it as the Regional Haze SIP). 

It is now Thursday, December 2. It’s about 3:05 p.m. We are in room 3175, at the Arizona 

Department of Environmental Quality, 1110 West Washington in Phoenix, Arizona. My name is 

Mark Lewandowski. I have been appointed by the Director of the ADEQ to preside at this 

proceeding. 

The purposes of this proceeding are to provide the public an opportunity to: 

hear about the substance of the proposed Regional Haze SIP. That’s the first thing. The second thing 

is to ask questions regarding the proposed Regional Haze SIP, and (3) if necessary, to present oral 

argument or data, and views regarding the proposed Regional Haze SIP in the form of formal 

comments on the record. 

Lisa Tomczak, to my right, is here representing the ADEQ. She is from the Air Quality Planning 

Section. Also out in the audience are other people from ADEQ, including Trevor Baggiore and 

Corky Martinkovic, who’s just walking in. 
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The Proposed Regional Haze SIP, which I noticed was on the back table, several hundred pages (?), 

was released for public comment on October 28, 2010, and public notices appeared in the Arizona 

Republic and on the ADEQ Web site regarding the proposed SIP. 

The procedure for making a public comment on the record is pretty straightforward. If you want to 

comment, you should fill out a speaker slip, which is available on the back table, and give it to me. 

Using speaker slips allows everyone an opportunity to be heard and allows us to match the name on 

the official record with the comments and to spell your name right. 

You may also submit written comments to me or to Lisa today. Please note, the comment period on 

the Proposed Regional Haze SIP closes at the completion of this public hearing or at 5:00 p.m. 

today, whichever is later. 

The agenda for this hearing is simple. First, Lisa will present a brief overview of the Proposed 

Regional Haze SIP 

After she’s done with her brief overview, I will conduct a question and answer period. The purpose 

of the question and answer period is to provide information that may help you in making comments 

on the Proposed Regional Haze SIP. 

After the question and answer period, we will actually go into the formal oral comment period. At 

that time, I will begin to call speakers in the order that I have received speaker slips. If I haven’t 

received any at that time, I will ask if anybody still wants to speak. 

Please be aware that any comments you make at today's hearing that you want the Department to 

formally consider must be given either in writing or on the record during the oral comment period of 

this proceeding. So you can do either oral comments or written comments today by close of 

comment. 

* * * * * 

At this time, Lisa Tomczak will give a brief overview of the Proposed Regional Haze SIP. 
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Lisa Tomczak: Under Section 308 of the Federal Regional Haze Rule in 40 CFR Part 51, states are 

required to submit state implementation plans or SIPs that address visibility impairment at Federal 

Class I areas. The plan must provide current visibility conditions, analysis of haze impairing 

pollutants, a demonstration of reasonable progress towards the goal at the end of the first planning 

period, and a long-term strategy describing how Arizona will improve visibility at its Class I areas. 

The visibility impairing pollutants required to be analyzed are sulfate, nitrate, organic carbon, 

elemental carbon, fine soil, coarse material, and sea salt. The primary pollutants that impair 

visibility at Arizona’s Class I areas are sulfate, organic carbon, and coarse material, and not 

necessarily in that order, either. All of the pollutants, however, do impair visibility at varying 

degrees depending on the location of the Class I area, location of sources, geography, and 

meteorology. The pollutants are both natural and anthropogenic in nature and are found to come 

from a variety of sources from within Arizona, neighboring states, and also internationally. 

For this planning period, which ends in 2018, Arizona, like many other states, will not meet the 

uniform rate of progress, also known as the URP, towards achieving natural visibility conditions on 

20% worst visibility days at Class I areas; however, visibility will improve through many 

regulations, both “on-the-books” and “on-the-way.” Reductions in anthropogenic pollutants, such as 

sulfur dioxide and nitrogen oxides, will occur through implementation of best available retrofit 

technology (also known as BART) on those sources that required a BART analysis. BART applies 

to emission units, at one of 26 listed source categories, that began operation after August 7, 1962, 

and were in existence prior to August 7, 1977, and potential emissions from all BART-eligible units 

exceed 250 tons per year for any visibility impairing pollutant, and also have the capacity to cause or 

contribute to visibility impairment at a designated Class I area. Dispersion modeling analyses were 

used to determine the extent of visibility impairment at the Class I areas. In Arizona, Catalyst Paper, 

SRP Coronado, APS Cholla, Arizona Electric Power Cooperative (in Benson), Freeport McMoRan 

Miami Smelter, and the Asarco Hayden Smelter were identified as subject to BART. Arizona used 

the following steps to make its BART determinations: 
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1 o Identify existing controls already in use 

2 o Identify all available retrofit control options 

3 o Eliminate technically infeasible control options 

4 o Evaluate control effectiveness for control options 

5 o Evaluate energy and non-air quality environmental impacts of each option (which 

includes cost) 

7 o Evaluate visibility impacts (which are benefits), and eventually 

8 o Select BART 

Reduction in visibility impairment caused by anthropogenic pollutants and anthropogenic activities 

will also occur through many on-going pollution control programs such as Prevention of Significant 

Deterioration, New Source Review, statewide rules regarding Reasonably Attributable Visibility 

Impairment, state and federal regulations regarding mobile sources, and also control programs to 

meet the National Standards for particulate matter. Visibility impairment resulting from activities 

such as prescribed burning and open burning are also addressed through Arizona’s Enhanced Smoke 

Management Program as well as a statewide permit program regarding open burning. 

ADEQ asserts that the modeled 2018 projections demonstrate reasonable progress towards achieving 

natural visibility conditions for the following reasons: the analyses conducted are representative of 

the best available data, the level of analysis used is appropriate for this planning period, natural 

sources have a significant impact on visibility at Class I areas and affect the ability to meet the URP. 

There are major reductions in anthropogenic pollutants, and there is significant contribution to 

visibility impairment from international and global sources, which ADEQ does not have the 

authority or the ability to control. 

Mr. Lewandowski: We just finished the explanation period of this proceeding on the Proposed 

Regional Haze SIP. For anyone who came in after we began, this is basically the beginning of this 

hearing. We had an introduction and this explanation period, and now we are moving to a question 

and answer period, so you didn’t really miss much. 

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So the question and answer period: any questions before we move on to oral comments? 

Again, the close of comment is today at 5 p.m. or after this hearing, whichever is later, and you can 

submit written comments if you want, instead of or in addition to oral comments. 

* * * * * 

Okay. We now move to the oral comment period for formal oral comments. Does anybody wish to 

speak or turn in a speaker slip? 

That was a world-record, fast oral comment period. 

* * * * * 

Thank you for your interest. I imagine people will stick around for a little bit afterwards if you 

want to have some informal questions and answers. 

If you have not already submitted written comments, you may submit them to us at this time. 

It is now 3:15 on December 2nd. Thank you for attending, and the oral proceeding is closed. 





National Park Service Initial Comments 

Arizona Draft Section 308 Regional Haze State Implementation Plan 

November 29, 2010 

General Comments: 

The National Park Service, in consultation with the Fish and Wildlife Service, has completed 

review of Arizona’s draft Section 308 regional haze State Implementation Plan (SIP). We 

appreciate the Arizona Department of Environmental Quality (ADEQ)’s long-term commitment 

to visibility improvement through the Grand Canyon Visibility Transport Commission, the 

Western Regional Air Partnership (WRAP), the Section 309 milestone process, and now the 

Section 308 SIP. We also appreciate the opportunity to discuss our initial comments with ADEQ 

on November 1, 2010. 

ADEQ has provided a good summary of the WRAP technical analyses that address emissions, 

source contributions to visibility impairment at the Class I areas in Arizona, and projected 

benefits of emissions reductions under current federal and state requirements. Our major 

concerns are with ADEQ’s determinations of Best Available Retrofit Technology (BART) and 

the lack of a substantive analysis of emissions controls under the reasonable progress analysis. 

Arizona is projecting degradation of visibility on 20% Best days by 2018 at two IMPROVE 

monitors representing four Class I areas. The regional haze rule requires that states improve 

visibility on the 20% worst visibility days and prevent degradation of visibility on the 20% best 

days. The Arizona SIP as written does not support ADEQ’s conclusion that the actions taken are 

sufficient to demonstrate reasonable progress in improving visibility in the Class I areas. 

 

Our more detailed comments are presented below. 

Specific Comments: 

Chapter 7 Visibility Impairment at Class I areas 

Organic Carbon (OC) is a dominate contributor to pollutants concentrations and visibility 

impairment at the Class I areas in Arizona. ADEQ attributes OC to fire, but the contributions are 

more complicated. We recommend that ADEQ address the relative contributions of natural and 

anthropogenic contributions to OC at the Class I areas. The WRAP Technical Support System 

provides daily time series of pollutant concentrations at the IMPROVE monitors 

 (http://vista.cira.colostate.edu/tss/Results/HazePlanning.aspxv; Monitoring) 

and daily time series of natural versus anthropogenic contributions to carbon 

(http://vista.cira.colostate.edu/tss/Results/HazePlanning.aspx; Emissions and Source 

Apportionment; Organic Aerosol Tracer). These time series indicate that a few days at each site 

with elevated primary OC levels that are likely due to fire events, but also indicate important 

contributions from anthropogenic and secondary natural carbon that vary seasonally and 

spatially. 

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Chapter 8 Sources of Visibility Impairment 

Please address explicitly the assumptions used in the WRAP 2018 PRP18b emissions inventory 

for Arizona’s BART sources and compare those modeling assumptions to the final emissions 

limits for sulfur dioxide (SO2) and nitrogen oxides (NOx) for the BART sources. If there are 

BART emissions reductions that were not included in the WRAP modeling inventory, these 

could be cited as evidence for greater than modeled visibility improvement. 

 

The emissions table (Table 8.1) indicates that total SO2 emissions from point sources will 

decrease by 2018. However, SO2 emissions from the two copper smelters are projected to 

increase significantly (13,273 tons) by 2018. Please discuss Arizona’s assumptions for future 

emissions from the smelters. These assumptions are critical to the source apportionment 

analyses in Chapter 9 that project that Arizona’s contribution to sulfate (SO4) will increase at 

several Class I areas. 

Table 8.2 indicates that NOx emissions from point sources will not change between 2002 and 

2018. Is this consistent with ADEQ’s final BART determinations? 

Tables 8.3-8.5 indicate that natural fire is the major source category for Volatile Organic Carbon 

(VOC), Primary Organic Aerosols (POA), and Elemental Carbon (EC). Note that anthropogenic 

emissions from area sources, road dust, and fugitive dust are projected to increase. 

Chapter 9 Visibility Modeling and Source Apportionment 

Please provide a brief summary of the model performance for the 2002 base year. Our 

confidence in the modeled responses to emissions changes is dependent on the model’s skill in 

representing atmospheric chemistry and transport. In general, model performance is better for 

SO4 and EC and less accurate for nitrate (NO3) and OC. Appendix C provides general references 

but does not give an overview of the model performance as is required in the SIP. 

Please briefly describe relative reduction factors and cite the technical reference or summarize 

how the factors are calculated using model results and monitoring data. 

Tables 9.3-9.21 indicate that soil (fine particulate matter) is projected to increase by 2018 at 

every Class I area and that organic carbon is projected to increase at Chiricahua (IMPROVE 

monitor represents 3 Class I areas), Saguaro, and Superstition. Since the natural sources are 

held constant, these increases are likely due to anthropogenic sources or influences from outside 

the U.S. 

Section 9.3 discusses results of the Particulate Source Apportionment Tool (PSAT). One of the 

measures that we consider as part of reasonable progress is whether the PSAT modeling supports 

that Arizona’s contribution to pollutant concentrations is decreasing. PSAT indicates that the 

contributions of Arizona’s point sources to SO4 concentrations will increase by 2018 at 

Chiricahua, Mazatzal, Petrified Forest, Saguaro, Superstition, Sierra Ancha, and Sycamore. 

Please discuss the basis for this increase. Projected increases in SO2 emissions from the two 

copper smelters (assigned to Gila County) may explain the increases in SO4 concentrations at the 

Class I areas. Note that in some instances (e.g., page 89-90 in the October 25 draft concerning 

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PSAT modeling for Mazatal) the narrative incorrectly refers to SO4 emissions when SO2

emissions were intended. 

PSAT also projects that NO3 concentrations due to NOx emissions from AZ point sources will 

increase by 2018. Increases in SO4 and NO3 contributions from Arizona point sources are not 

consistent with ADEQ’s assertion that the state has made reasonable progress toward improving 

visibility in Class I areas in Arizona (e.g., section 11.3.2 on page 154 of Oct draft). 

The Weighted Emissions Potential (WEP) projections indicate increases in Arizona’s 

contributions to fine and coarse particulate matter and to organic carbon from area sources, road 

dust, fugitive dust, and windblown dust. Area sources, road dust, and fugitive dust are 

anthropogenic sources. Based on the WEP results, we recommend that ADEQ consider 

measures to reduce anthropogenic particulate matter (PM) in the reasonable progress analysis. 

Section 9.4.5 (page 114 of October draft) incorrectly refers to Grand Canyon when the graphic 

and paragraph are addressing Petrified Forest. 

Chapter 10 Best Available Retrofit Technology (BART) 

BART Exemption Criteria 

During the development of the WRAP BART Modeling Protocol, the Federal Land Managers 

(FLM) recommended that the WRAP BART exemption modeling use surface and upper air 

meteorological observations as well as the MM5 meteorological model to initialize the 

CALMET meteorological model. WRAP used surface observations but did not use upper air 

observations. Thus the FLM recommended that states should use a conservative interpretation of 

the CALPUFF outputs. Specifically, the states should use either the maximum visibility impact 

with the annual average natural condition or the 98th percentile visibility impact with the 20% 

best natural conditions. ADEQ is reporting 98th percentile visibility impact with annual average 

natural conditions which is not consistent with good modeling practices as identified by 40 CFR 

51 Appendix W or EPA’s Model Clearing House memorandum. Use of a non-guideline 

modeling approach requires additional evaluation of performance and EPA Regional Office 

approval (Section 3.2, 40 CFR 51 Appendix W). 

Most states have followed EPA staff guidance to interpret the 98th percentile impact as either the 

maximum 8th highest value in any single year or the 22nd highest value for three years combined, 

whichever is more conservative. ADEQ used the 8th highest value averaged over three years, 

which is a less conservative metric. Had ADEQ used the 8th highest value in a single year, 

Chemical Lime Nelson Plant would not have been exempted from BART. We request that 

ADEQ re-evaluate the BART determination and use the more rigorous criteria. 

In the modeling to determine if a source is subject to BART, all emissions that are above the de 

minimus level are to be included, even if those emissions are less than 250 tons. 

Ammonia Modeling Assumptions 

We reviewed the BART modeling reports submitted by the three electric utilities. We do not 

agree with the assumptions used for ammonia by AECOM for Salt River Project’s Coronado 

Generating Station and by CH2MHill for Arizona Public Service’s Cholla Generating Station. 

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Both analyses use very low winter values for ammonia based on early monitoring in the region. 

More recent ammonia monitoring1,2

 indicates higher ammonia values commonly occur in the 

region. We support the ammonia values of 1 ppm recommended in the WRAP BART Modeling 

Protocol and used by CH2MHill for Arizona Electric Power Cooperative’s Apache Generating 

Station. We recommend that the same levels be used for Comanche and Cholla Generating 

Stations. 

BART Costs and Benefit Analyses 

We have developed a national data base of costs and effectiveness of control technology 

installations. As documented in our General BART Comments, based on national experience, it 

appears that ADEQ and the companies have under estimated the efficiency of Selective Catalytic 

Reduction (SCR) to reduce NOx emissions and have overestimated the costs of SCR installation 

and operation. 

Please clarify how the costs were factored into the BART determinations. ADEQ at the public 

stakeholder meeting on October 19 indicated that a threshold of $1500 to $2000 per ton was used 

in the BART determinations. However, the BART Technical Support Document indicates that 

ADEQ selected the least cost control option (low NOx burners, existing PM and SO2 controls) 

even when more effective controls were identified in the $1500-2000 range. 

ADEQ presents the visibility benefit in $/dv for just the Class I area with the maximum impact. 

If the cumulative benefits of controls were considered for all the Class I areas within 300 km of a 

source, the $/dv benefit would be much greater than reported. Please report the benefits of 

controls at all Class I areas, not just the benefit at the Class I area with maximum impact. 

Please provide a summary of the BART controls and expected emission reduction in Chapter 10 

in addition to Appendix D. 

BART Recommendations 

Our detailed comments on ADEQ’s BART determinations and national evidence supporting our 

cost estimates are provided in the enclosed documents. Our BART recommendations are 

summarized here. 

Arizona Electric Power Cooperative (AEPCO) – Apache Generating Station Units 2 and 3 

For NOx, we recommend SCR for Apache Units 2 and 3 rather than Low NOx Burners with 

Over Fired Air as proposed by ADEQ. Our cost estimate for SCR is $1,500 - $1,700 per ton 

based on an annual average NOx emissions rate of 0.05 lb/mmBtu. 

For SO2, we recommend that ADEQ require the existing scrubbers to achieve at least 90% SO2 

removal with an annual average SO2 emissions limit not to exceed 0.12 lb/mmBtu. We concur 

with ADEQ’s BART determination for PM. 

                                                           

1 Sather, M. E. et al., 2008, J of Environmental Monitoring 10, 1319-1325 

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 Tombach and Paine, 2010, Report to Salt River Project, “Measurements of Background Ammonia on the Colorado 

Plateau and Visibility Implications”

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Arizona Public Service Cholla Units 2, 3, and 4 

For NOx, we recommend SCR for Cholla Units 2, 3, and 4 rather than Low NOx Burners with 

Separated Over Fired Air as proposed by ADEQ. Our cost estimate for SCR is $1,700 - $1,900 

per ton based on an annual average NOx emissions rate of 0.05 lb/mmBtu. 

For SO2, we recommend that ADEQ require the existing scrubbers to achieve at least 90% SO2 

removal with an annual average SO2 emissions limit not to exceed 0.12 lb/mmBtu. We concur 

with ADEQ’s BART determination for PM. 

Salt River Project Coronado Generating Station Units 1 and 2 

The ammonia assumptions used to model visibility impacts are unacceptably low and therefore 

the visibility benefits of emissions controls were underestimated. The visibility modeling needs 

to be redone. 

For NOx, we concur with ADEQ’s estimated $1,021/ton for combustion controls plus SCR. It is 

likely the corrected visibility benefits would support support SCR as BART. 

For SO2, we concur with Wet Flue Gas Desulfurization for both units with an associated SO2

emission rate of 0.08 lbs/MMBtu on 30-day rolling average basis. 

For PM, ADEQ’s conclusion that the proposed 0.03 lb/mmBtu BART limit “is already meeting 

or exceeding the stringency of the emissions limitation” “for similar emissions units with similar 

emissions controls” is not consistent with its Cholla BART analysis which concluded that 

replacement of the existing hot-side ESP with fabric filters at 0.015 lb/mmBtu is BART. We 

recommend the BART determination for Coronado be re-evaluated. 

Catalyst Paper (Snowflake) Inc. (CPSI) 

The NOx emissions rate evaluated for control measures and proposed by ADEQ as BART is 

twice as high as the uncontrolled NOx emissions rate reported by CPSI and used in the cost 

estimates. The costs of control are over estimated by using a higher interest rate and shorter 

remaining useful life than recommended by the EPA Control Cost Manual. The visibility 

benefits to multiple Class I areas have not been included. The BART analysis for NOx is 

unacceptable and needs to be redone. The BART analysis for SO2 is flawed with unsupported 

costs and under estimated benefits. The BART analysis for SO2 is unacceptable and needs to be 

redone. 

Arizona Public Service (APS) West Phoenix 

Please provide the revised air dispersion modeling analysis that was submitted on October 7, 

2007 and was the basis for exempting the source from BART. 

Arizona Portland Cement Company 

Until the retirement of kiln #4 is made federally enforceable, it will remain BART-eligible. We 

disagree with the exemption of the source because the exemption criteria were incorrectly 

applied. We request the visibility impacts be evaluated against the correct exemption criteria. 

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Chemical Lime Company – Nelson Lime Plant

Please provide the September 21, 2007, letter from Chemical Lime Company (CLC) to ADEQ 

and the new modeling analysis by CLC. It appears that CLC did not include the 154 tpy of PM 

emissions modeled by WRAP into the company’s modeling. All emissions, not just those 

greater than 250 tons need to be included in the modeling to determine if a source is subject to 

BART. The exemption criteria were incorrectly applied; please apply corrected as discussed 

above. We conclude that the Chemical Lime Company – Nelson Lime Plant is subject to BART. 

Tucson Electric Power (TEP) – Irvington Generating Station 

The clear intent of EPA's BART Guidelines is to exempt a source that has gone through New 

Source Review (NSR) from a second review under BART. Because TEP Irvington Unit I4 did 

not go through NSR, the exemption does not apply. Our interpretation is that Unit I4 needs to be 

evaluated under BART. 

ASARCO Hayden Smelter 

We agree with ADEQ’s conclusion that the installation and operation of the double contact acid 

plant with the New Source Performance Standard of 650 ppm constitutes BART for SO2. We 

disagree with exempting the PM10 emissions from BART; in the BART guidelines the PM10 

level for exemption is 15, not 250 tons per year. 

Freeport-McMoRan Miami Smelter

We agree with ADEQ’s conclusion that the installation and operation of the double contact acid 

plant with the New Source Performance Standard of 650 ppm constitutes BART for SO2. We 

also agree that the NESHAP for Primary Copper Smelting constitutes BART for PM. 

Chapter 11 Reasonable Progress Goal Demonstration

Section 11.3.1 on page 153 of the October draft SIP incorrectly reports that visibility is 

maintained on the 20% best days for all the Class I areas in Arizona and in most cases are under 

the 2018 Uniform Rate of Progress. In fact, visibility on the 20% best days is projected to 

degrade at two IMPROVE monitors representing four Class I areas (Chiricahua National 

Monument, Chiricahua Wilderness, Galiuro Wilderness, and Saguaro National Park). Uniform 

Rate of Progress is not met at any Class I area in Arizona on the 20% worst days. These results 

do not support ADEQ’s assertion that Arizona is doing all that is needed to demonstrate 

reasonable progress by 2018. 

As additional weight of evidence that visibility on the 20% Best Days is being protected, ADEQ 

should include the trends from 2000-2008 at the Chiricahua and Saguaro monitors 

(http://vista.cira.colostate.edu/dev/web/AnnualSummaryDev/Trends.aspx). 

Because Arizona will not meet the uniform rate of progress by 2018, the Regional Haze Rule 

requires ADEQ to project the year that natural background visibility will be achieved at the 

Arizona Class I areas under the lower rate of progress. 

We agree that mobile sources do not need to be considered under reasonable progress because 

significant emissions reductions are expected under existing federal and state requirements. We 

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also agree that Arizona’s Enhanced Smoke Management Program addresses emissions from 

forestry and agricultural burning and that these source categories do not need to be considered in 

the reasonable progress analysis. 

We agree with ADEQ’s conclusion to focus on SO2 and NOx emissions in the reasonable 

progress analysis. We disagree with ADEQ’s decision not to consider particulate matter and 

organic carbon emissions since anthropogenic emissions of these pollutants are projected to 

increase. We recommend that ADEQ consider what controls may be feasible to reduce 

anthropogenic emissions of dust, VOC, and POA from area source categories such as 

agricultural and construction practices and residential wood smoke. 

In Section 11.3.2, there appears to be a discrepancy between the text and Table 11.1 in the 

percentage contributions from Arizona sources to SO4 and NO3 at Class I areas in Arizona. The 

table indicates Arizona’s contribution to SO4 is 7-24% and to NO3 is 7-53%. 

ADEQ identifies major source categories for SO2 and NOx emissions (Table 11.2). We disagree 

with ADEQ’s assumption that visibility benefits from emissions reductions from these sources 

will be minimal. If the sources are located near Class I areas, the visibility benefits of controls 

could be substantial. 

We noticed that between the September and October drafts of the SIP, ADEQ has removed the 

tables in Section 11.3.3 that identify specific sources and emissions that may be candidates for 

controls under reasonable progress. We found those tables very informative and encourage 

ADEQ to reinstate them. 

The four-factor analyses reported in Section 11.3.3 are incomplete. We recommend that ADEQ 

use the Four Factor Analysis reported by the WRAP’s contractor EC/R to support ADEQ’s 

analyses. The EC/R report covers industrial boilers, cement manufacturing, lime kilns, and 

internal combustion engines that are major source categories identified by ADEQ. 

We also recommend that point sources that were BART-eligible but determined not to be subject 

to BART should be considered for reasonable progress. It is appropriate to consider a lower 

visibility impact threshold than 0.5 dv in a reasonable progress analysis. 

We recommend that ADEQ review the reasonable progress analysis completed by Colorado 

http://www.cdphe.state.co.us/ap/regionalhaze.html for an example of a strong analysis of 

potential emissions control costs and benefits. 

In Section 11.3.4 ADEQ concludes that no controls on non-BART sources are reasonable at this 

time and indicates that ADEQ will develop guidance for a more comprehensive review of 

individual sources over the next five years to identify any additional emission reductions that 

could improve visibility in the Class I areas by 2018. We encourage ADEQ to make a more 

binding commitment to emissions controls to be implemented within the next five years. 

Correction under Section 11.4.1, item 4: mobile sources are not the largest anthropogenic source 

of SO2. 

7
ADEQ asserts that as yet undefined controls to be identified in the long term strategy will further 

improve visibility. There is no evidence presented in the long term strategy to support this 

statement. 

Chapter 12 Long Term Strategy 

Section 4.3 Arizona Regional Haze Monitoring Commitments

ADEQ needs to discuss its commitment to assuring continued visibility monitoring in the future. 

In Section 12.3 we disagree with ADEQ’s conclusion that OC, EC, PM fine and coarse do not 

need to be considered in the long term strategy. The anthropogenic sources of these pollutants 

(e.g., area sources, road dust, fugitive dust) are projected to increase with population and should 

be considered by ADEQ. 

Section12.3 provides a good discussion of Arizona impacts to Class I areas in neighboring states 

and neighboring states impacts to Class I areas in Arizona. What percentage contribution does 

Arizona have to Class I areas in Colorado? 

We appreciate that in Section12.6.1 ADEQ discusses Arizona’s requirements for Prevention of 

Significant Deterioration and New Source Review to evaluate air quality related values and 

specifically visibility. 

In Section 12.6, the discussion of measures to control dust and area sources in PM10 

nonattainment areas is very helpful. Do the PM10 monitoring data demonstrate the effectiveness 

of these controls? 

Section 12.6.3 refers to compliance schedules for BART sources that install controls or accept 

federally enforceable permit limitations. Which BART source(s) accepted permit limits to 

exempt from BART? 

In Section 12.6.5 ADEQ discusses the Enhanced Smoke Management Plan. Please clarify if the 

Plan answers the three key questions for visibility protection in the Class I areas. If the Plan 

does not, is there a schedule to add these components to the plan? 

 are the smoke management measures are voluntary or mandatory? 

 does the Plan specifically identify the Class I areas as sensitive receptors? 

 specify that avoiding impacts to Class I areas be considered in the smoke management 

decisions? 

Section 12.7 discusses federal requirements for renewable fuels. Does Arizona have state rules 

requiring implementation of renewable fuels? If so, it would be appropriate to mention in this 

section. 

Section 12.7.3 is intended to describe the long term control strategies for BART facilities but is 

incomplete in the October 25 draft. 

8
9

Section 12.8: It is not likely that WRAP will be able to fulfill the commitment to provide final 

regional modeling once the BART determinations are complete. We recommend deleting this 

commitment. 

As evidence of reasonable progress beyond the existing WRAP modeling, it is important for 

ADEQ to identify any additional BART or other emissions reductions that were not included in 

the WRAP 2018 PRPb emissions inventory. 

Chapter 13 Consultation 

Please correct references to Oregon. 

Conclusion 

We appreciate the opportunity to work with ADEQ to improve visibility in our Class I areas. We 

are available to assist ADEQ to address our comments. 
NPS General BART Comments on ADEQ BART Analyses 

November 29, 2010 

As with any new program, much has been learned, and much is left to learn by all parties 

involved, and we are pleased to share the information we have obtained from our reviews of 

BART proposals across the nation. Following are our general comments on the five-step BART 

analyses conducted by ADEQ. 

Step 1: “Identify All Available Technologies” and Step 2: “Eliminate Technically Infeasible 

Options” were generally comprehensive and well supported. 

Step 3: Evaluate Control Effectiveness of Each Remaining Technology

Effectiveness of Selective Catalytic Reduction (SCR) 

A common problem was an underestimation of the effectiveness of SCR to reduce emissions. 

SCR is different from many other control technologies in that its efficiency is not highly 

dependent upon the concentration of the pollutant to be controlled.1

 Instead, SCR efficiency is 

primarily influenced by the design of the catalyst reactor, that is, the volume of the catalyst, its 

cross-sectional area, number of layers, and measures to prevent blinding and deactivation, as 

well as replacement schedule. If it is necessary to achieve a high degree of removal efficiency on 

an inlet stream with a low concentration, more catalyst can be included in the design. It is 

generally understood that NOX reductions of approximately 90% or more may be achieved with 

SCR systems.2

 And, according to the June 13, 2009 “Power” magazine article “Air Quality 

Compliance: Latest Costs for SO2 and NOX Removal (effective coal clean-up has a higher–but 

known–price tag)” by Robert Peltier, “An excellent example of the significant investment many 

utilities have made over the past decade is American Electric Power (AEP), one of the largest 

public utilities in the U.S. with 39,000 MW of installed capacity with 69% of that capacity coalfired. AEP is under a New Source Review (NSR) consent decree signed in 2007 that requires the 

utility install air quality control systems to reduce NOX by 90%...” 

 

1

 ADEQ has included this statement taken from the company BART analysis: 

SCR can achieve NOx control efficiencies as high as 90% with inlet concentrations in the range of 300 to 

400 ppmvd. If inlet NOx concentrations are less than 250 ppmvd, SCR can achieve NOx control efficiencies 

ranging from 70% to 80%. 

This assertion is contrary to our understanding of SCR performance factors. We suspect that ADEQ may have 

misunderstood because SCRs on lower concentration gas streams may have been designed to achieve lower removal 

efficiencies. Our understanding is that SCR performance is primarily a function of catalyst temperature, volume, 

type, and area. However, as noted below in an excerpt from the EPA Control Cost manual, at very low inlet 

concentrations, removal efficiency may be lower: 

In general, higher uncontrolled NOx inlet concentrations result in higher NOx removal efficiencies due to 

reaction kinetics. However, NOx levels higher than approximately 150 parts per million (ppm), generally 

do not result in increased performance. Low NOx inlet levels result in decreased NOx removal efficiencies 

because the reaction rates are slower, particularly in the last layer of catalyst. 

We request that ADEQ provide support for its contention. 

2

 According to the Institute of Clean Air Companies white paper titled “Selective Catalytic Reduction (SCR) Control 

of NOx Emissions from Fossil Fuel-Fired Electric Power Plants” (published in May 2009), “By proper catalyst 

selection and system design, NOX removal efficiencies exceeding 90 percent may be achieved.” 

1 
We are aware of vendor guarantees of 0.05 lb/mmBtu,3

 and understand that major vendors are 

designing SCR systems to achieve 0.02 lb/mmBtu4 on coal-fired boilers. 

Operational evidence from SCR retrofits on eastern EGUs (see Appendix EGUs less than 0.06 

lb/mmBtu in 2009) clearly indicates that SCR can achieve 0.05 lb/mmBtu or lower on an annual 

basis. For example, we found 12 tangentially-fired boilers operating at or below 0.05 lb/mmBtu 

in 2009. 

ADEQ has assumed that 24-hour and 30-day rolling average SCR emissions would be the same 

as the corresponding annual average emission rate. However, we looked at monthly data for 28 

EGUs with SCR’s operating at or below 0.05 lb/mmBtu on an annual average (see Appendix 

2009 monthly emissions) and found that, of the 228 months of data, 214 were at or below 0.06 

lb/mmBtu. For tangentially-fired EGUs, we found that 84 of 89 were at or below 0.06 

lb/mmBtu. We conclude that SCR can achieve 0.05 lb/mmBtu on an annual basis and 0.06 

lb/mmBtu on a 30-day rolling average basis. 

Step 4: Evaluate Impacts and Document Results

Non-Air Quality Environmental Impacts

ADEQ: SNCR and SCR installation could impact the salability and disposal of fly ash due to 

ammonia levels. Other environmental impacts involve the potential public and employee safety 

hazard associated with the storage of ammonia, especially anhydrous ammonia, and the 

transportation of the ammonia to the power plant site. 

NPS: According to the Institute for Clean Air Companies, ammonia can be handled safely.5 Our 

discussions with SNCR vendors indicate that the concern about ash salability is likely 

unfounded. 

Cost of Compliance

SCR Costs 

Although there are several methods for estimating SCR costs, our experience leads us to believe 

that no one method is perfect and that the costing methods need to be tempered by real-world 

 

3

 Minnesota Power Taconite Harbor BART analysis. 

4

 Babcock & Wilcox presentation to Minnesota Pollution Control Agency. 

5

 “Concern over the handling of ammonia was initially raised as a problem with SCR technology applications due to 

the transportation and storage of a hazardous gas under pressure. However, large quantities of ammonia already are 

used for a variety of applications with an excellent overall safety record. (In 2006, 17 billion pounds of ammonia 

were produced in the U.S.) These applications include the manufacture of fertilizers and a variety of other 

chemicals, as well as refrigeration. With the proper controls, ammonia use is safe and routine.” WHITE PAPER 

SELECTIVE CATALYTIC REDUCTION (SCR) CONTROL OF NOX EMISSIONS FROM FOSSIL FUELFIRED ELECTRIC POWER PLANTS PREPARED BY: NOx CONTROL TECHNICAL DIVISION INSTITUTE 

OF CLEAN AIR COMPANIES, INC. May 2009 Copyright

2 
data. Both OAQPS and EPA Region 8 have advised against the use of CUECost. Instead, the 

BART Guidelines recommend use of the OAQPS Control Cost Manual: 

The basis for equipment cost estimates also should be documented, either with data supplied by an 

equipment vendor (i.e., budget estimates or bids) or by a referenced source (such as the OAQPS Control 

Cost Manual, Fifth Edition, February 1996, 453/B-96-001). In order to maintain and improve consistency, 

cost estimates should be based on the OAQPS Control Cost Manual, where possible. The Control Cost 

Manual addresses most control technologies in sufficient detail for a BART analysis. The cost analysis 

should also take into account any site-specific design or other conditions identified above that affect the 

cost of a particular BART technology option. 

EPA’s belief that the Control Cost Manual should be preferred over CUECost for developing 

cost analyses that are transparent and consistent across the nation and provide a common means 

for assessing costs is further supported by this November 7, 2007, statement from EPA Region 8 

to the North Dakota Department of Health: 

The SO2 and PM cost analyses were completed using the CUECost model. According to the BART 

Guidelines, in order to maintain and improve consistency, cost estimates should be based on the OAQPS 

Control Cost Manual. Therefore, these analyses should be revised to adhere to the Cost Manual 

methodology.

Larry Sorrels, an economist at EPA’s Office of Air Quality Planning and Standards (OAQPS) 

wrote the following to Aaron Worstell of EPA Region 8 on September 8, 2010: 

the way that CUECost estimates total capital cost and O&M cost is different from the Control Cost Manual. 

In particular, the total capital cost estimate from CUECost is the same as the total capital requirement 

(TCR), an estimate that is part of the levelized cost methodology devised by EPRI. A TCR estimate 

includes Allowance for Funds Used During Construction (AFUDC), an estimate that is not included in the 

total capital cost according to the Control Cost Manual method. Also, O&M costs are calculated 

differently, with fixed and variable components being included in the O&M costs, a distinction at odds with 

the Cost Manual method. 

Cost Escalation 

Mr. Sorrels also commented6 upon PSCo’s use of Present Value of Revenue Requirements 

(PVRR) model to calculate the levelized cost of each technology. 

The PVRR model really can't be complementary to the EPA air pollution control cost methodology. The 

PVRR model is designed to generate nominal, levelized costs that incorporate a return to the equity and 

debt incurred by the utility that purchases the control equipment. The EPA air pollution control cost 

methodology generates real (inflation-adjusted), equivalent annual costs over the life of control equipment 

without consideration of return on equity or debt. Any presentation of PVRR results should state clearly 

that the pollution control investment is treated just like any other capital investment for a regulated entity - 

the utility still receives its expected rate of return on its investment and really loses no profit as a result of 

installation and operation of this NOx control equipment. 

This would not be the case for any non-regulated utility or non-utility firm. 

The discount rate of 7.88% is a nominal rate, not a real one (consistent with the comment I made above). 

Estimating real annual costs means no use of escalation factors, something that is utilized in the PVRR 

model. 

 

6

 E-mail dated September 7, 2010 to Don Shepherd of NPS. 

3 
There needs to be more detail on what the capital and O&M estimation methodologies include. There are 

some allusions to what is contained in these estimates as prepared by GAAR, but no detail. I suppose this 

detail is in the reports that Xcel will send to the State of Colorado at their request. 

In summation, it is not appropriate to use the CUECost model, nor is it appropriate to escalate 

costs into the future and compare them against current cost thresholds. 

Mr. Sorrels also provided7 insight on matters pertaining to inflation and the Allowance for 

Funds During Construction (AFUDC): 

On cost indexes, I prefer the CEPCI for escalating/deescalating costs for chemical plant and utility 

processes since this index specifically covers cost items that's pertinent to pollution control equipment 

(materials, construction labor, structural support, engineering & supervision, etc.). The Marshall & Swift 

cost index is useful for industry-level cost estimation, but is not as accurate at a disaggregated level when 

compared to the CEPCI. Thus, I recommend use of the CEPCI as a cost index where possible. 

I agree with including AFUDC in a capital cost estimate if this is already included in the base case as per a 

utility commission decision. Otherwise, I do not agree with its inclusion. 

Evidence that ADEQ has overestimated its SCR costs can be found in a June 2009 article in 

“Power” magazine:8 

“One more current data set is the historic capital costs reported by AEP averaged over several 

years and dozens of completed projects. For example, AEP reports that their historic average 

capital costs for SCR systems are $162/kW for 85% to 93% NOX removal...” 

“...historical data finds the installed cost of an SCR system of the 700MW-class as 

approximately $125/kW over 22 units with a maximum reported cost of $221/kW in 2004 

dollars. This data was reported prior to the dramatic increase in commodity prices of 14% per 

year average experienced from 2004 to 2006 (from the FGD survey results). Applying those 

annual increases to the 2004 estimates for three years (from the date of the survey to the end of 

2007) produces an average SCR system installed cost of $185/kW...” 

“Overall, costs were reported to be in the $100 to $200/kW range for the majority of the systems, 

with only three reported installations exceeding $200/kW.” 

Five industry studies conducted between 2002 and 2007 have reported the installed unit capital 

cost of SCRs, or the costs actually incurred by owners, expressed in dollars per kilowatt. These 

actual costs are generally lower than estimated by ADEQ. 

The first study evaluated the installed costs of more than 20 SCR retrofits from 1999 to 2001. 

The installed capital cost ranged from $106 to $213/kW, converted to 2007 dollars.9 Costs are 

escalated through using the CEPCI. 

 

7

 7/21/10 e-mail to Don Shepherd 

4 
The second survey of 40 installations at 24 stations reported a cost range of $76 to $242/kW, 

converted to 2007 dollars.10 

The third study, by the Electric Utility Cost Group, surveyed 72 units totaling 41 GW, or 39% of 

installed SCR systems in the U.S. This study reported a cost range of $118/kW to $261/kW, 

converted to 2007 dollars.11

A fourth study, presented in a course at PowerGen 2005, reported an upper bound range of 

$180/kW to $202/kW, converted to 2007 dollars.12 

A fifth summary study, focused on recent applications that become operational in 2006 or were 

scheduled to start up in 2007 or 2008, reported costs in excess of $200/kW on a routine basis, 

with the highest application slated for startup in 2009 at $300/kW.13

EPA’s Region 8 Office has compiled a graphic presentation of SCR capital costs adjusted to 

2009 dollars—please see Appendix. The EPA data confirm that SCR capital costs range from 

$73 – $243/kW. 

Thus, the overall range for these industry studies is $50/kW to $300/kW. The upper end of this 

range is for highly complex retrofits with severe space constraints, such as Belews Creek, 

reported to cost $265/kW,14 or Cinergy's Gibson Units 2-4. Gibson, a highly complex, spaceconstrained retrofit in which the SCR was built 230 feet above the power station using the largest 

crane in the world,15 only cost $251/kW in 2007 dollars.16

 8 June 13, 2009 “Power” magazine article “Air Quality Compliance: Latest Costs for SO2 and NOx Removal 

(effective coal clean-up has a higher–but known–price tag)” by Robert Peltier. 

http://www.masterresource.org/2009/06/air-quality-compliance-latest-costs-for-so2-and-nox-removal-effective-coalclean-up-has-a-higher-but-known-price-tag/

9

 Bill Hoskins, Uniqueness of SCR Retrofits Translates into Broad Cost Variations, Power Engineering, May 2003. 

Ex. 2. The reported range of $80 to $160/kW $123 - $246/kW was converted to 2008 dollars ($116 - $233/kW) 

using the ratio of CEPCI in 2008 to 2002: 575.4/395.6. 

10 J. Edward Cichanowicz, Why are SCR Costs Still Rising?, Power, April 2004, Ex. 3; Jerry Burkett, Readers Talk 

Back, Power, August 2004, Ex. 4. The reported range of $56/kW - $185/kW was converted to 2008 dollars ($83 - 

$265/kw)using the ratio of CEPCI for 2008 to 1999 (575.4/.390.6) for lower end of the range and 2008 to 2003 

(575.4/401.7) for upper end of range, based on Figure 3. 

11 M. Marano, Estimating SCR Installation Costs, Power, January/February 2006. Ex. 5. The reported range of $100 

- $221/kW was converted to 2008 dollars ($130 - $286/kW) using the ratio of CEPCI for 2008 to 2004: 575.4/444,2. 

http://findarticles.com/p/articles/mi_qa5392/is_200602/ai_n21409717/print?tag=artBody;col1 

12 PowerGen 2005, Selective Catalytic Reduction: From Planning to Operation, Competitive Power College, by 

Babcock Power, Inc. and LG&E Energy, December 2005, Ex. 6. The reported range of $160 - $180/kW) was 

converted to 2008 dollars ($197 - $221/kW) using the ratio of CEPCI for 2008 to 2005 (575.4/468.2). 

13 J. Edward Cichanowicz, Current Capital Cost and Cost-Effectiveness of Power Plant Emissions Control 

Technologies, June 2007, pp. 28-29, Figure 7-1 (Ex. 1). 

14 Steve Blankinship, SCR = Supremely Complex Retrofit, Power Engineering, November 2002, Ex. 7. The unit 

cost: ($325,000,000/1,120,000 kW)(608.8/395.6) = $290/kW. 

http://pepei.pennnet.com/display_article/162367/6/ARTCL/none/none/1/SCR-=-Supremely-Complex-Retrofit/ 

15 Standing on the Shoulder of Giants, Modern Power Systems, July 2002, Ex. 8. 

5 
We have been working with an Excel workbook we derived from the SCR cost estimation 

method presented by EPA’s Office of Air Quality Planning and Standards Control Cost Manual 

(Cost Manual). We now believe that the Cost Manual method tends to underestimate the Direct 

Capital Cost (DCC) component of the SCR cost estimate. Because the Total Capital Investment 

(TCI) component is directly proportional to the DCC, a straightforward application of the Cost 

Manual usually results in TCI costs lower than what we would expect from the real-world 

industry data presented above, we have been trying to find a way to modify the Cost Manual 

method to provide TCI estimates more consistent with industry data. First, we adjust the DCC 

from the 1998 baseline to current cost using the Chemical Engineering Plant Cost Index (CEPCI) 

to adjust costs for inflation using the CEPCI. Our current approach is to use the DCC presented by 

the source and apply the Cost Manual ratios for Indirect Installation and Contingency costs to the 

DCC to estimate TCI. If the resulting TCI, expressed in $/kW is within the expected range, we 

carry that estimate through the remainder of the cost estimation process. If this TCI estimate is 

outside the expected range, we can override the TCI calculation by inserting our best estimate 

based upon the size of the EGU and the degree of retrofit difficulty. 

The Direct Annual Cost (DAC) component of the process is also important because it represents 

a significant portion of the Total Annual Cost. The methods presented by the Cost Manual for 

estimating DAC appear to be straight-forward and should accurately represent annual costs with 

no need for adjustment. However, we note in our review of the BART analyses resented by the 

sources that there appears to be a consistent significant overestimation of DAC. 

Step 5: Evaluate Visibility Results

We believe that it is appropriate to consider both the degree of visibility improvement in a given 

Class I area as well as the cumulative effects of improving visibility across all of the Class I 

areas affected. It simply does not make sense to use the same metric to evaluate the effects of 

reducing emissions from a BART source that impacts only one Class I area as for a BART 

source that impacts multiple Class I areas. And, it does not make sense to evaluate impacts at one 

Class I area, while ignoring others that are similarly significantly impaired. If we look at only the 

most-impacted Class I area, we ignore that the other Class I areas are all suffering from 

impairment to visibility “caused” by the BART source. It follows that, if emission from the 

BART source are reduced, the benefits will be spread well beyond only the most impacted Class 

I area, and this must be accounted for.17

The BART Guidelines represent an attempt to create a workable approach to estimating visibility 

impairment. As such, they require several assumptions, simplifications, and shortcuts about 

when visibility is impaired in a Class I area, and how much impairment is occurring. The 

Guidelines do not attempt to address the geographic extent of the impairment, but assume that all 

Class I areas are created equal, and that there is no difference between widespread impacts in a 

 16 McIlvaine, NOX Market Update, August 2004, Ex. 9. SCR was retrofit on Gibson Units 2-4 in 2002 and 2003 at 

$179/kW. Assuming 2002 dollars, this escalates to ($179/kW)(608.8/395.6) = $275.5/kW. 

http://www.mcilvainecompany.com/sampleupdates/NoxMarketUpdateSample.htm 17 For example, the cumulative benefits have been a factor in the BART determinations by NM, OR, and WY, as 

well as EPA in its proposals for the Navajo Generating Station and the Four Corners Power Plant. 

6 
7 

large Class I area and isolated impacts in a small Class I area. To address the problem of 

geographic extent, we have been looking at the cumulative impacts of a source on all Class I 

areas affected, as well as the cumulative benefits from reducing emissions. While there are 

certainly more sophisticated approaches to this problem, we believe that this is the most 

practical, especially when considering the modeling techniques and information available. 

Step 6: Select BART Control

Cost-Effectiveness Metrics 

BART is not necessarily the most cost-effective solution. Instead, it represents a broad 

consideration of technical, economic, energy, and environmental (including visibility 

improvement) factors. For example, Oregon DEQ has established a cost/ton threshold of $7,300 

based upon the premise that improving visibility in multiple Class I areas warrants a higher 

cost/ton than where only one Class I area is affected. In their BART proposal for the San Juan 

Generating Station, New Mexico used a range from $5,946/ton to $7,398/ton, and Wisconsin is 

using $7,000 - $10,000/ton as its BART threshold.18

One of the options suggested by the BART Guidelines to evaluate cost-effectiveness is 

cost/deciview. We believe that visibility improvement must be a critical factor in any program 

designed to improve visibility. Compared to the typical control cost analysis in which estimates 

fall into the range of $2,000 - $10,000 per ton of pollutant removed, spending millions of dollars 

per deciview (dv) to improve visibility may appear extraordinarily expensive. However, our 

compilation19 of BART analyses across the U.S. reveals that the average cost per dv proposed 

by either a state or a BART source is $14 - $18 million,

20 with a maximum of $51 million per 

dv proposed by South Dakota at the Big Stone power plant. We note that OR DEQ has chosen 

$10 million/dv as a cost criterion, which is somewhat below the national average. 

 

18 “The Department used cost-per-ton reduced as the primary metric for determining the BART level of control. The 

upper limit for this metric was $7,000 to $10,000 per ton, which reflects historical low-end costs for controls 

required under BACT.” BEST AVAILABLE RETROFIT TECHNOLOGY AT NON-EGU FACILITIES April 19, 

2010, WISCONSIN DEPARTMENT OF NATURAL RESOURCES 

19 http://www.wrapair.org/forums/ssjf/bart.html 

20 For example, PacifiCorp has stated in its BART analysis for its Bridger Unit #2 that “The incremental cost 

effectiveness for Scenario 1 compared with the baseline for the Bridger WA, for example, is reasonable at $580,000 

per day and $18.5 million per deciview.”
NPS Comments 

 Arizona Electric Power Cooperative (AEPCO) – Apache Generating Station BART 

Analysis and Determination 

November 29, 2010 

Process Description 

The Apache Generating Station consists of seven electric generating units (two coal/natural gasfired steam electric units, a natural gas/fuel oil-fired steam electric, combined cycle unit, and 

four natural gas/fuel oil-fired turbines) with a total generating capacity of 560 megawatts (MW). 

The power plant is located approximately three miles southeast of the town of Cochise in 

Cochise County. Apache Generating Station Units 1, 2, and 3 are potentially subject-to-BART. 

Of 1,228 plants, EPA Clean Air Markets (CAM) data for 2008 rank the Apache facility #352 for 

SO2 and #141 for NOX. 

Steam Unit 1 (ST1)

Apache Steam Unit 1 is a wall-fired steam-electric generating unit that can burn natural gas and 

numbers 2 through 6 fuel oils. The unit is permitted to produce up to a maximum capacity of 85 

MW of electricity. Since 2000, SO2 emissions have not exceeded one ton per year (tpy), and 

NOX emissions have averaged 0.14 lb/mmBtu and declined to 30 – 60 tpy. 

NOx BART Analysis 

Step 1: Identify the Existing Control Technologies in Use at the Source

There is no NOx emissions control equipment installed on ST1. 

Step 2: Identify All Available Retrofit Control Options

The second step of the BART process is to evaluate NOx control technologies with practical 

potential for application to ST1, including those control technologies identified as BACT or 

LAER by permitting agencies across the United States. ST1 NOx emissions are currently 

controlled through the use of good combustion practices. 

The following potential NOx control technology options were considered: 

 New LNBs with Cver-Fire Air (OFA) 

 Flue Gas Recirculation (FGR) 

 Rotating Opposed Fire Air (ROFA) 

 LNBs with selective non-catalytic reduction system (SNCR and Rotamix) 

 LNBs with selective catalytic reduction system (SCR) 

 Neural Net Controls 

Step 3: Eliminate All Technically Infeasible Control Options

1 
ADEQ has determined that all of the identified control technologies are technically feasible. 

Step 4: Evaluate Control Effectiveness of Remaining Technologies

ADEQ has estimated the installation of LNB with FGR can achieve a NOx emissions limit of 

0.056 lb/MMBtu when burning PNG, and 0.06 lb/MMBtu when burning No. 2 fuel oil. 

Step 5: Evaluate the Energy and Non-Air Quality Environmental Impacts and Document Results-

-Economic Impacts

ADEQ has estimated that LNB with FGR will have a Total Capital Investment of $1.2 million, a 

Total Annual Cost of $0.552 million/yr, and cost-effectiveness of $1,856/ton. 

Step 6: Evaluate Visibility Impacts

ADEQ estimates the total deciview reduction for Chiricahua Wilderness Area and National 

Monument at 0.194 dv. 

Step 7: BART Determination

ADEQ has determined that, for Unit 1, BART for NOx is the installation of LNB with FGR with 

a NOx emissions limit of 0.056 lb/MMBtu when burning PNG, and 0.06 lb/MMBtu when 

burning No. 2 fuel oil. The cost-effectiveness is $2.8 million/dv. 

PM10 BART Analysis 

The PM10 BART analysis is only completed for the case when ST1 burns 100 percent No. 6 fuel 

oil. This was done for comparison only, as AEPCO has never combusted No. 6 fuel oil in the 

unit). 

SO2 BART Analysis 

Emissions indicate that BART analysis is not required when ST1 burns PNG or fuel oil No. 2. 

ADEQ has determined that, for Unit 1, BART for SO2 is the use of PNG or No. 2 fuel oil with an 

SO2 emissions limit of 0.00064 lb/MMBtu when burning PNG, and 0.051 lb/MMBtu when 

burning No. 2 fuel oil. 

Steam Units 2 and 3

Steam Units 2 and 3 are similar 195 MW natural gas and coal-fired steam electric generating 

units equipped with dry-bottom turbo-fired coal boilers. Of 3,558 EGUs, 2008 CAM data rank 

Units 2 and 3 at #909 and #823, respectively for SO2, and #344 and #261, respectively for NOX. 

ADEQ modeling data show that Apache Units 2 and 3 have a combined maximum impact at 

Chiricahua Wilderness Area and National Monument of 4.84 dv. The cumulative impacts of 

2 
Apache Units 2 and 3 across the nine Class I areas modeled is 20.5 dv, which ranks these units 

among the highest1

 of any facility we have evaluated under the BART program. 

NOx BART Analysis 

Step 1: Identify the Existing Control Technologies in Use at the Source

Both Units 2 and 3 currently use OFA and under-fired air systems to control NOx emissions. 

Step 2: Identify All Available Retrofit Control Options

ADEQ: The Units are dry turbo-fired boilers, with 12 Riley directional flame burners. The 

following potential NOx control technology options were considered: 

 New/modified state-of-the-art LNBs with advanced OFA 

 Rotating opposed fire air (ROFA) 

 Selective non-catalytic reduction system (Rotamix and SNCR) 

 Selective catalytic reduction (SCR) system 

 Neural Network Controls/Boiler Combustion Controls (Neural Net) 

NPS: ADEQ also considered combinations of control options such as LNB+OFA+SCR 

Step 3: Eliminate All Technically Infeasible Control Options

ADEQ has determined that all of the identified control technologies are technically feasible. 

Step 4: Evaluate Control Effectiveness of Remaining Technologies

NPS: ADEQ selected LNB+OFA as BART at 0.31 lb/mmBtu with an estimated reduction of 

34% and 28% for Units #2 & #3, respectively. 

For its cost-effectiveness analysis, ADEQ has estimated that LNB+OFA+SCR can achieve 0.07 

lb/mmBtu on an annual basis,2 which represents a 77% reduction by SCR from the emission rate 

to be achieved by LNB+OFA alone. It is generally assumed that SCR can achieve at least 90% 

NOX reduction, and we have presented evidence in our General BART Comments demonstrating 

that SCR can achieve 0.05 lb/mmBtu (or lower) on similar tangentially-fired boilers. 

We conclude that ADEQ has underestimated the ability of a modern SCR retrofit to reduce NOX

emissions. Because such an underestimate adversely affects the cost-benefit analysis, we 

conducted our analysis as discussed in our General BART Comments and below. 

 

1

 The highest are Cholla Generating Station, Coronado Generating Station, Four Corners Power 

Plant, Navajo Generating Station, Centralia, PGE Boardman, San Juan Generating Station. 

2

 ADEQ appears to have assumed that SCR would achieve 0.07 lb/mmBtu regardless of averaging time. While we 

agree that 0.07 lb/mmBtu is a reasonable estimate for input into a visibility model that requires a 24-hour emission 

rate, it is always the case that average emission rates decrease as the averaging period increases. The data we present 

in our General BART Comments indicate that, if SCR can achieve 0.07 lb/mmBtu on a 24-hour basis, it is likely that 

that same SCR is achieving 0.06 lb/mmBtu (or lower) on a 30-day average basis and 0.05 lb/mmBtu (or lower) on 

an annual average. 

3 
Step 5: Evaluate the Energy and Non-Air Quality Environmental Impacts and Document Results

Non-Air Quality Environmental Impacts

ADEQ: SNCR and SCR installation could impact the salability and disposal of fly ash due to 

ammonia levels. Other environmental impacts involve the potential public and employee safety 

hazard associated with the storage of ammonia, especially anhydrous ammonia, and the 

transportation of the ammonia to the power plant site. 

NPS: Please see our General BART Comments. 

Economic Impacts 

NPS: Although a 90% reduction from the emission rate to be achieved by LNB+OFA would lead 

to an annual average emission rate of 0.03 lb/mmBtu in this case, as a conservative estimate, we 

have assumed that SCR would achieve 0.05 lb/mmBtu (84% reduction) on an annual average 

basis. 

In generating our SCR cost estimate, we note the following differences between our analysis and 

that provided by AEPCO: 

Our review of 2000 – 2009 CAM data (Please see the “Unit emissions” tab of the workbooks in 

Appendix.) found that actual annual average hourly heat input rates exceed the maximum heat 

input rates used by AEPCO. Maximum actual total annual heat input was also greater than 

estimated by AEPCO, as were maximum actual annual emissions. 

In our analyses, we used the maximum actual operating hours, maximum actual annual heat 

input, and maximum actual annual average hourly heat input. However, we also used the 2000 – 

2009 average annual NOX emission rate (in lb/mmBtu), which was lower than used by AEPCO, 

to estimate annual NOX emissions. In effect, we assumed that the units would operate at their 

historic maxima for operating hours and heat input, but emit at their historic average rate. The 

result was an annual NOX emission rate (Please see cell E31 on the “Boiler Calcs” tab.) that was 

greater than average and estimated by AEPCO, but less than the maximum actual annual 

emissions. As such, we based our estimates upon a greater gas flow that would be generated 

which would require a larger catalyst reactor, and more reagent would be required to treat the 

greater quantity of NOX emissions and the costs associated with reducing them. 

We used ADEQ’s estimates for costs associated with LNB+OFA, and AEPCO’s unit costs for 

catalyst, reagent, and electricity. 

A critical cost element is the Total Capital Investment (TCI) upon which much of the EPA Cost 

Manual method is based. As discussed in our General BART Comments, SCR costs can be 

expected to fall between $50 and $300/kW, with the recent average at slightly below $200/kW. 

However, a rigid application of the Cost manual tends to produce TCI that fall toward the lower 

end of the expected range, and company cost estimates typically substantially exceed the upper 

end of the range. In this case, the Cost Manual method yields $90/kW (Please see cell L18 in the 

“ICC” tab.), which appears too low for EGUs this size and thus prompted us to over-ride the 

4 
Cost manual’s TCI calculation. On the other hand, the AEPCO estimate of $226/kW (cell P18) is 

more expensive than average, and no reason has been provided to justify any exceptional costs, 

further evaluation is warranted. 

We have developed a hybrid approach that combines the Direct Capital Cost (DCC) provided by 

the source and the ratios applied by the Cost Manual to the DCC to generate the TCI. The Cost 

Manual assumes that the TCI for SCR will be 141% (cell N17) of the DCC (cell L4), and that the 

costs that comprise the TCI will also be ratios of the DCC. Instead, the AEPCO $44 million TCI 

estimate is 161% (cells P17 and Q17 on the “ICC” tab) of its $27 million DCC estimate, and 

includes a $3 million Allowance for Funds During Construction (AFUDC) which may not be 

justified (Please see our General BART Comments on AFUDC.) 

Our next step assumed that the AEPCO estimate for DCC is reasonable, and applied the Cost 

Manual 141% ratio to estimate a new TCI. In this case, the result is a TCI of $38 million @ 

$197/kW (cells N20 and N21 on the “ICC” tab). Because this new TCI falls very near the 

expected $200 average, it will be used for further estimates and is fed back to cell C7 of the 

“Given/Assume” tab and to cell F5 on the “Ann Cost” tab. 

Annual Cost estimates are generated by a direct application of the Cost Manual method to the 

new TCI and other interim values. We found that AEPCO’s Direct Annual Cost estimates were 

usually higher than the Cost Manual estimates. The most significant differences were between 

the Indirect Annual Cost (due to the different estimates of TCI) and the amount of NOX removed 

(due to our assumed higher SCR efficiency). 

A summary of our analysis can be found on the far-right tab of our workbook. We believe that 

our estimation method is more transparent and truer to the EPA Cost Manual approach than that 

provided by AEPCO, and that our $1500 - $1700/ton results are better supported by real-world 

industry experience. 

Step 6: Evaluate Visibility Impacts

ADEQ estimates the deciview reduction from each EGU provided by its BART proposal to be 

0.21 – 0.27 dv for the most-impacted Class I, the Chiricahua Wilderness Area and National 

Monument. The results provided by AEPCO show a cumulative improvement of 0.56 – 0.73 dv 

across the four Class I areas for which results were provided. 

ADEQ estimates the deciview reduction from each EGU provided by SCR to be 0.63 – 0.68 dv 

for the Chiricahua Wilderness Area and National Monument. The results provided by AEPCO 

show a cumulative improvement of 1.68 – 1.82 dv across the four Class I areas for which results 

were provided. 

Step 7: BART Selection

ADEQ: After reviewing the company’s BART analysis, and based upon the information above, 

ADEQ has determined that, for Units 2 and 3 BART for NOx is new LNBs with OFA system 

with a NOx emissions limit of 0.31 lb/MMBtu for both Units 2 and 3. 

5 
NPS: ADEQ estimates that all of the options it evaluated would cost less than $2,200/ton and 

$10 million/dv to implement, which is well below the $14 - $18 million/dv average of BART 

proposals across the nation. BART, like BACT, is not necessarily the most-cost-effective option. 

Instead, it is typically chosen based upon a comparison to options selected by other regulatory 

agencies in similar situations. For example, Oregon DEQ has established a cost/ton threshold of 

$7,300 based upon the premise that improving visibility in multiple Class I areas warrants a 

higher cost/ton than where only one Class I area is affected. In their BART proposal for the San 

Juan Generating Station, New Mexico used a range from $5,946/ton to $7,398/ton, Colorado is 

using $5,000/ton as a non-binding “guidepost,” and Wisconsin is using $7,000 - $10,000/ton as 

its BART threshold.3

 Because BART is the best option that meets the selection criteria, SCR 

should be selected as BART due to the reasonable cost/ton, the lower-than-average 

cost/deciview, and the benefits to several Class I areas. 

PM10 BART Analysis 

Step 1: Identify the Existing Control Technologies in Use at the Source

Both Steam Units 2 and 3 are currently equipped with hot-side Electrostatic Precipitators (ESPs). 

Step 2: Identify All Available Retrofit Control Options

ADEQ: Steam Units 2 and 3 are currently equipped with hot-side ESPs. Historically, outlet ESP 

particulate emissions on Units 2 and 3 have ranged from approximately 0.007 to 0.045 

lb/MMBtu. This wide range in outlet emissions can in part be attributed to the hot-side operation, 

as well as the wide variety of coals being burned in the boilers. Hot-side ESP effectiveness may 

also be impacted by sodium content in the ash. 

Three retrofit control technologies have been identified for additional particulate matter control: 

 Performance upgrades to existing hot-side ESP 

 Replace current ESP with a fabric filter unit 

 Install a polishing fabric filter after ESP 

Step 3: Eliminate All Technically Infeasible Control Options

ADEQ has determined that all of the identified control technologies are technically feasible. 

Step 4: Evaluate Control Effectiveness of Remaining Technologies

ADEQ Table 12 lists the various control technologies and estimated emissions rates. 

Table 12: Control Technology and Respective Emission Rates 

 

3

 “The Department used cost-per-ton reduced as the primary metric for determining the BART level of control. The 

upper limit for this metric was $7,000 to $10,000 per ton, which reflects historical low-end costs for controls 

required under BACT.” BEST AVAILABLE RETROFIT TECHNOLOGY AT NON-EGU FACILITIES April 19, 

2010, WISCONSIN DEPARTMENT OF NATURAL RESOURCES

6 
Control Technology Expected PM10 Emission Rate 

ESP Upgrades 0.03 lb/MMBtu 

Full size fabric filter 0.015 lb/MMBtu 

Polishing Fabric Filter 0.015 lb/MMBtu 

Step 5: Evaluate the Energy and Non-Air Quality Environmental Impacts and Document Results

Economic Impacts 

Specific costs for the precipitator upgrades were not evaluated as AEPCO has yet to evaluate the 

upgrades that may be applicable to Units 2 and 3. 

Step 6: Evaluate Visibility Impacts

Visibility improvements for the precipitator upgrades were not evaluated. 

Step 7: BART Selection

ADEQ: Based upon its review of the analysis provided by AEPCO, and the information provided 

above, ADEQ has determined that BART for PM10 emissions is upgrades to the existing ESP and 

a PM10 emissions limit of 0.03 lb/MMBtu for both Units 2 and 3. The upgrades to the existing 

ESP will involve a possible installation of a flue gas conditioning system, improvements to the 

scrubber bypass damper system, and implementing programming optimization measures for ESP 

automatic voltage controls.

NPS: We concur. 

SO2 BART Analysis 

Step 1: Identify the Existing Control Technologies in Use at the Source

Units 2 and 3 currently operate wet limestone scrubbers for SO2 removal, with current emissions 

of 0.184 lb/MMBtu and 0.151 lb/MMBtu respectively. 

Step 2: Identify All Available Retrofit Control Options

Enhancement of current wet limestone scrubber or SDAS was the only SO2 control technology 

option considered 

The EPA BART guidelines state that for existing units with SO2 controls achieving at least 50 

percent SO2 removal, cost-effective scrubber upgrades should be considered. EPA has 

recommended consideration of the following potential upgrades: 

 Elimination of bypass reheat 

 Installation of liquid distribution rings 

 Installation of perforated trays 

 Use of organic acid additives 

 Improve or upgrade scrubber auxiliary system equipment 

7 
 Redesign spray header or nozzle 

Step 3: Eliminate All Technically Infeasible Control Options

ADEQ has determined that all of the identified control technology upgrades are technically 

feasible. 

Step 4: Evaluate Control Effectiveness of Remaining Technologies

ADEQ: When evaluating the control effectiveness of SO2 reduction technologies, each option 

can be compared against benchmarks of performance. In its BART analysis, AEPCO chose to 

compare its proposed technology upgrades to EPA’s presumptive BART emission limitations. 

According to EPA’s BART guidance documents, the presumptive limit for SO2 on a BARTeligible coal-burning unit, used here as a point of reference, is 95 percent removal, or 0.15 

lb/MMBtu. 

NPS: ADEQ must evaluate the potential of the scrubber upgrades to achieve emission rates 

lower than the presumptive rate. The AEPCO reports indicate: 

 For Unit #2, uncontrolled SO2 emissions are 0.69 lb/mmBtu, and current controls reduce 

SO2 emissions by 73% down to 0.18 lb/mmBtu. 

 For Unit #3, uncontrolled SO2 emissions are 0.69 lb/mmBtu, and current controls reduce 

SO2 emissions by 78% down to 0.15 lb/mmBtu. 

For example, Minnesota is requiring that Xcel Energy upgrade the existing scrubbers at it King 

and Sherburne County plants to meet 0.12 lb/mmBtu. 

According to the Colorado Department of Public Health & Environment, “Colorado Ute Electric 

Association, which owned Craig before TriState, installed wet limestone FGD systems, on Craig 

Units 1 and 2 when the units began operations in 1980 and 1979, respectively. TriState upgraded 

these FGD systems in the 2003 – 2004 timeframe. The current Operating Permit also requires that 

100% of the flue gas in the FGD be treated and that the Craig Unit 1 and 2 FGDs be designed to meet 

at least a 97.3% removal rate.” 

In the late 1990s, Public Service of New Mexico (PSNM) replaced its existing SO2 controls with 

new limestone forced-oxidation scrubbers. In 2005 PSNM agreed to upgrade the scrubbers by 

2009 such that the annual rolling average SO2 percentage reduction for San Juan Units 1, 2, 3, 

and 4 shall not be less than 90% for each unit (based upon measurements upstream and 

downstream of scrubbers). 

It is clear that existing scrubbers can be upgraded to achieve better removal efficiency and lower 

emission rates than the 78% and 0.15 lb/mmBtu proposed by ADEQ. ADEQ must evaluate those 

options. 

Step 5: Evaluate the Energy and Non-Air Quality Environmental Impacts and Document Results

Over the past several years AEPCO has completed several scrubber upgrades to improve 

performance, including the following: 

8 
9 

 Elimination of flue gas bypass 

 Splitting the limestone feed to both the absorber feed tank and tower sump 

 Upgrade of the mist eliminator system 

 Installation of suction screens at pump intakes 

 Automation of pump drain valves 

 Replacement of scrubber packing with perforated stainless steel trays 

Dibasic acid additive was tested; however results did not show significantly higher SO2 removal. 

Energy Impacts 

 

Upgraded operation of the existing wet limestone scrubber or SDAS system is not expected to 

result in any additional power consumption. 

Environmental Impacts 

There will be incremental additions to scrubber waste disposal and makeup water requirements 

and a reduction of the stack gas temperature if there is elimination of flue gas bypass. 

Economic Impacts 

There are no anticipated cost impacts attributable to upgraded scrubber operation. 

Step 6: Evaluate Visibility Impacts

A Visibility Impact Analysis was not performed for SO2 since the existing scrubbers are 

proposed as BART. 

Step 7: BART Selection

ADEQ: After reviewing the company’s BART analysis, and based upon the information above, 

ADEQ has determined that BART for SO2 emissions is no new controls and an emission limit of 

0.15 lb/MMBtu. 

NPS: Neither AEPCO nor ADEQ has conducted a proper BART analysis of upgrading the 

existing scrubbers. We suggest that ADEQ require that Apache Units 2 and 3 achieve at least 

90% SO2 removal across the scrubbers, not to exceed 0.12 lb/mmBtu. 
NPS Comments 

APS Cholla Generating Station BART Analysis and Determination 

November 29, 2010 

Process Description 

The Arizona Public Service (APS) Cholla Generating Station (Cholla) is located approximately 

two miles east of Joseph City along Interstate 40 in Navajo County, Arizona, and consists of the 

following four electric generating units with a total generating capacity of 1,150 megawatts 

(MW). 

Unit 1: 125 MW 

Unit 2: 300 MW 

Unit 3: 300 MW 

Unit 4: 425 MW 

Each unit is a coal-fired steam-generating unit equipped with a tangentially-fired, dry-bottom 

boiler and burns bituminous or sub-bituminous coal purchased from the Lee Ranch and El 

Segundo mines. Of 1,228 plants, EPA Clean Air Markets (CAM) data for 2008 rank the Cholla 

facility #143 for SO2 and #88 for NOX. 

Cholla Units 2, 3 and 4 are subject-to-BART, and presumptive BART limits apply at this facility 

with a total capacity greater than 750 MW. Of 3,558 EGUs, 2008 CAM data rank Cholla Units 2, 

3, and 4 at #821, #230, and #527, respectively for SO2, and #302, #241, and #335, respectively 

for NOX. 

Despite the improper modeling methods applied by APS and the resulting underestimations of 

impacts, the cumulative impacts of Cholla Units 2, 3, and 4 across the 13 Class I areas modeled 

rank among highest of any facility we have evaluated under the BART program. 

Nitrogen Oxides (NOx) BART Analysis and Determination for Units 2, 3 and 4 

Step 1: Identify the Existing Control Technologies in Use at the Source

The Cholla BART Analysis was completed in late 2007. At that time, the Units were equipped 

with Close-coupled Overfire Air (COFA). Overfire air is used to reduce NOx by reducing excess 

air in the combustion zone. Low NOx Burner (LNBs) and Separated Overfire Air (SOFA) were 

installed on Units 2, 3 and 4 in March 2008, May 2009 and May 2008, respectively. LNBs and 

SOFAs are utilized for increased NOx reduction. 

Step 2: Identify All Available Retrofit Control Options

APS has identified the following available retrofit control technologies for NOx control in Units 

2, 3 and 4. 

 LNB with Separate Overfire Air (SOFA) System 

 LNB with SOFA and Selective Non-Catalytic Reduction (SNCR) System 

 Rotating Opposed Flow Air system (ROFAs) 

 ROFA with Rotary Mixing of Additives (Rotamix) 

 LNB with SOFA and Selective Catalytic Reduction (SCR) 

1 
NPS: We agree with the suite of options. 

 

Step 3: Eliminate All Technically Infeasible Control Options

ADEQ has determined that all of the options identified above are technically feasible. 

Step 4: Evaluate Control Effectiveness of Remaining Technologies

NPS: ADEQ selected LNB+SOFA as BART at 0.22 lb/mmBtu with an estimated reduction of 

46% - 56%. 

For its cost-effectiveness analysis, ADEQ has estimated that LNB+OFA+SCR can achieve 0.07 

lb/mmBtu on an annual basis,1 which represents a 68% reduction by SCR from the emission rate 

to be achieved by LNB+OFA alone. It is generally assumed that SCR can achieve at least 90% 

NOX reduction, and we have presented evidence in our General BART Comments demonstrating 

that SCR can achieve 0.05 lb/mmBtu (or lower) on similar tangentially-fired boilers. 

We conclude that ADEQ has underestimated the ability of a modern SCR retrofit to reduce NOX

emissions. Because such an underestimate adversely affects the cost-benefit analysis, we 

conducted our analysis as discussed in our General BART Comments and below. 

Step 5: Evaluate the Energy and Non-Air Quality Environmental Impacts and Document Results

Non-Air Quality Environmental Impacts

ADEQ: SNCR and SCR installation could impact the salability and disposal of fly ash due to 

ammonia levels. Other environmental impacts involve the potential public and employee safety 

hazard associated with the storage of ammonia, especially anhydrous ammonia, and the 

transportation of the ammonia to the power plant site. 

NPS: Please see our General BART Comments. 

Economic Impacts 

NPS: Although a 90% reduction from the emission rate to be achieved by LNB+OFA would lead 

to an annual average emission rate of 0.02 lb/mmBtu in this case, as a conservative estimate, we 

have assumed that SCR would achieve 0.05 lb/mmBtu (77% reduction) on an annual average 

basis. 

In generating our SCR cost estimate, we note the following differences between our analysis and 

that provided by APS: 

 

1

 ADEQ appears to have assumed that SCR would achieve 0.07 lb/mmBtu regardless of averaging time. While we 

agree that 0.07 lb/mmBtu is a reasonable estimate for input into a visibility model that requires a 24-hour emission 

rate, it is always the case that average emission rates decrease as the averaging period increases. The data we present 

in our General BART Comments indicate that, if SCR can achieve 0.07 lb/mmBtu on a 24-hour basis, it is likely that 

that same SCR is achieving 0.06 lb/mmBtu (or lower) on a 30-day average basis and 0.05 lb/mmBtu (or lower) on 

an annual average. 

2 
Our review of pre-modification 2000 – 2007 CAM data (Please see the “Unit emissions” tab of 

the workbooks in Appendix.) found that APS’ estimates were higher than maximum actual 

annual emissions. 

In our analyses, we used the maximum actual operating hours, maximum actual annual heat 

input, and APS’ estimate for actual maximum hourly heat input. However, we also used the 2000 

– 2007 average annual NOX emission rate (in lb/mmBtu), which was lower than used by APS, to 

estimate annual NOX emissions. In effect, we assumed that the units would operate at their 

historic maxima for operating hours and heat input, but emit at their historic average rate. The 

result was an annual NOX emission rate (Please see cell E31 on the “Boiler Calcs” tab.) that was 

greater than average, but less than the maximum annual emissions estimated by APS. As such, 

based on our estimates, less reagent would be required to treat the lesser quantity of NOX

emissions and the costs associated with reducing them would be lower. 

We used ADEQ’s estimates for costs associated with LNB+OFA, and APS’ unit costs for 

catalyst, reagent, and electricity. 

A critical cost element is the Total Capital Investment (TCI) upon which much of the EPA Cost 

Manual method is based. As discussed in our General BART Comments, SCR costs can be 

expected to fall between $50 and $300/kW, with the recent average at slightly below $200/kW. 

However, a rigid application of the Cost Manual tends to produce TCI costs that fall toward the 

lower end of the expected range, and company cost estimates typically substantially exceed the 

upper end of the range. In this case, the Cost Manual method yields $67 - $74/kW (Please see the 

“ICC” tab cell L18.), which appears too low for EGUs this size and thus prompted us to override the Cost manual’s TCI calculation. On the other hand, the APS estimate of $249 - $258/kW 

(Please see the “ICC” tab cell P18.) is more expensive than average, and no reason has been 

provided to justify any exceptional costs, so further evaluation is warranted. 

We have developed a hybrid approach that combines the Direct Capital Cost (DCC) provided by 

the source and the ratios applied by the Cost Manual to the DCC to generate the TCI. The Cost 

Manual assumes that the TCI for SCR will be 141% (cell N17) of the DCC (cell L4), and that the 

costs that comprise the TCI will also be ratios of the DCC. Instead, the APS $77 - $106 million 

TCI estimates are 258% (cells P17 and Q17 on the “ICC” tab) of their corresponding DCC 

estimates, and include a $3 - $5 million Allowance for Funds During Construction (AFUDC) 

which may not be justified (Please see our General BART Comments on AFUDC.) 

Our next step assumed that the APS estimate for DCC is reasonable, and applied the Cost 

Manual 141% ratio to estimate a new TCI (cells N20 and N21 on the “ICC” tab). Because this 

new $136 - $141/kW TCI falls within the expected values for EGUs of this size, it will be used 

for further estimates and is fed back to cell C7 of the “Given/Assume” tab and to cell F5 on the 

“Ann Cost” tab. 

Annual Cost estimates (Please see the “Ann Cost” tab.) are generated by a direct application of 

the Cost Manual method to the new TCI and other interim values. We found that APS’ Direct 

Annual Cost estimates were usually higher than the Cost Manual estimates. The most significant 

3 
differences were between the Indirect Annual Cost (due to the different estimates of TCI) and the 

amount of NOX removed. We believe that our estimation method is more transparent and truer to 

the EPA Cost Manual approach than that provided by APS, and that our $1700 - $1900/ton 

results are better supported by real-world industry experience. 

Step 6: Evaluate Visibility Impacts

ADEQ: CALPUFF modeling was performed at 13 Class I areas that are located within 300 

kilometers of Cholla Power Plant. The impacts are modeled for different NOx control scenarios, 

combined with SO2 and PM10 technologies at Petrified Forest National Park

NPS: Because APS used background ammonia levels that are unacceptably low (Section 4.4.1 of 

the company report), the visibility benefits are under-estimated and the Evaluation of Visibility 

Impacts step is unacceptable. 

Step 7: BART Selection

ADEQ: According to the Regional Haze Rule, only dV changes in excess of 1.0 dV are 

perceptible. 

A review of the data presented in Tables 3, 4, and 5 indicates that CALPUFF model-predicted 

visibility improvements (delta dV) for all five NOx control scenarios are less than 0.5 dV. For 

example, in the case of Unit 3, the dV changes range from 0.126 dV for the LNB with SOFA 

(Scenario 1) to 0.230 dV for LNB with SOFA and SCR (Scenario 5). The change in dV between 

the least expensive and most expensive NOx control technologies (the two noted above) is only 

0.104 dV. The corresponding capital costs are $5.4 million for LNB/SOFA and $82.8 million 

for LNB/SOFA with SCR. 

Based on these facts and the five-factor analysis discussed above, ADEQ has concluded that 

LNB with SOFA constitute BART for NOx emissions for Cholla Units 2, 3, and 4. 

NPS: EPA has explicitly rejected the premise that visibility improvement must be perceptible to 

qualify as BART. Because of the improper visibility modeling analysis noted above, ADEQ has 

not conducted a valid five-factor BART analysis. 

ADEQ estimates that all of the options it evaluated would cost less than $2,600/ton to 

implement. BART, like BACT, is not necessarily the most-cost-effective option. Instead, it is 

typically chosen based upon a comparison to options selected by other regulatory agencies in 

similar situations. For example, Oregon DEQ has established a cost/ton threshold of $7,300 

based upon the premise that improving visibility in multiple Class I areas warrants a higher 

cost/ton than where only one Class I area is affected. In their BART proposal for the San Juan 

Generating Station, New Mexico used a range from $5,946/ton to $7,398/ton, Colorado is using 

$5,000/ton as a non-binding “guidepost,” and Wisconsin is using $7,000 - $10,000/ton as its 

BART threshold.2

 Because BART is the best option that meets the selection criteria, SCR should 

be selected as BART due to the reasonable cost/ton and the benefits to multiple Class I areas. 

 

2

 “The Department used cost-per-ton reduced as the primary metric for determining the BART level of control. The 

upper limit for this metric was $7,000 to $10,000 per ton, which reflects historical low-end costs for controls 

4 
PM10 BART Analysis 

Step 1: Identify the Existing Control Technologies in Use at the Source

Unit 2 currently has a mechanical dust collector for control of PM10 emissions. Additional 

particulate matter control is provided by a Venturi scrubber. Cholla 2 is currently able to achieve 

emission rate of 0.020 lb/MMBtu. 

Unit 3 was previously equipped with a hot-side ESP and was able to achieve an emission rate of 

0.015 lb/MMBtu of PM10. The facility completed installation of a fabric filter in May 2009. 

With the installation of the fabric filter, the facility expects to consistently achieve an emission 

rate of 0.015 lb/MMBtu for PM10. 

Unit 4 was previously equipped with a hot-side ESP and was able to achieve an emission rate of 

0.024 lb/MMBtu of PM10. The facility completed installation of a fabric filter in May 2008. 

With the installation of the fabric filter, the facility expects to consistently achieve an emission 

rate of 0.015 lb/MMBtu for PM10. 

Step 2: Identify All Available Retrofit Control Options

Since Units 3 and 4 will be equipped with fabric filters, and fabric filters are considered the top 

control technology for reducing PM emissions. As a result, no other technology is considered 

for these two Units. The following retrofit technologies are considered for Unit 2: 

 Electrostatic Precipitators 

 Fabric Filters 

Step 3: Eliminate All Technically Infeasible Control Options

ADEQ has determined that all of the identified control technologies are technically feasible. 

Step 4: Evaluate Control Effectiveness of Remaining Technologies

Fabric filters are proven to be highly effective and provide a consistent particulate matter 

reduction. The emissions at the outlet of fabric filter are expected to be less than 0.015 

lb/MMBtu. 

Step 5: Evaluate the Energy and Non-Air Quality Environmental Impacts and Document Results

Economic Impacts 

APS has chosen to install a new fabric filter at an annual cost of $9.4 million to remove 58 tons 

per year. The cost-effectiveness of this strategy is $160,747/ton. 

 required under BACT.” BEST AVAILABLE RETROFIT TECHNOLOGY AT NON-EGU FACILITIES April 19, 

2010, WISCONSIN DEPARTMENT OF NATURAL RESOURCES

5 
Step 6: Evaluate Visibility Impacts

The installation of a fabric filter is the only option considered for BART for all the 3 units. 

Step 7: BART Selection

Based upon its review of the company’s BART analysis and the information provided above, the 

Department has determined that, fabric filter with an associated emission limit of 0.015 

lb/MMBtu is the BART for control of PM10 for Units 2, 3 and 4. 

NPS: We concur. 

SO2 BART Analysis 

Step 1: Identify the Existing Control Technologies in Use at the Source

According to ADEQ: 

Unit 2. This unit is equipped with four Venturi flooded disc scrubbers/absorber with lime 

reagent for SO2 control. Currently, APS Cholla is able to achieve 0.14 lb/MMBtu to 0.25 

lb/MMBtu of SO2 on Unit 2. 

Unit 3. This unit did not have any SO2 control technology when the BART analysis was 

completed in late 2007. The facility installed a new wet lime scrubber in May 2009 to capture 

and treat all flue gases. This will result in Unit 3 consistently meeting an emission limit of 0.15 

lb/MMBtu. 

Unit 4. This Unit was previously operating with 36% flue gas scrubbing with emission rate of 

0.734 lb/MMBtu. The facility installed a new wet lime scrubber in May 2008 to capture and 

treat all flue gases. This will result in Unit 4 consistently meeting an emission limit of 0.15 

lb/MMBtu. 

Step 2: Identify All Available Retrofit Control Options

Unit 2. The facility plans to remove the Venturi section of the scrubber and considered a wet 

lime scrubber section for possible operational upgrades. Installation of bag filter as a part of 

BART will improve the performance of scrubber due to decreased plugging of scrubber. The 

facility expects to achieve 0.15 lb/MMBtu consistently with these operational upgrades.

Unit 3. In late 2007, APS Cholla identified the following available retrofit control technologies 

for SO2 control in Unit 3: 

 Dry Flue Gas Desulfurization (FGD) System 

 Dry Sodium Sorbent Injection 

 Wet Lime Scrubber 

6 
Subsequently, Cholla installed a new Wet Lime Scrubber on Unit 3 in May 2009. Therefore, the 

new wet lime scrubber, as described above, is the only retrofit control technology considered for 

this unit. 

Unit 4. The wet lime scrubber, as described above, is the only retrofit control technology 

considered for this unit. 

Step 3: Eliminate All Technically Infeasible Control Options

ADEQ has determined that all of the identified control technology upgrades are technically 

feasible. 

Step 4: Evaluate Control Effectiveness of Remaining Technologies

NPS: ADEQ must evaluate the potential of the scrubbers and possible upgrades to achieve 

emission rates lower than the presumptive rate. The APS reports indicate that uncontrolled SO2

emissions are 1.00 lb/mmBtu, and the ADEQ proposal would reduce SO2 emissions by 85% 

down to 0.15 lb/mmBtu. 

For example, Minnesota is requiring that Xcel Energy upgrade the existing scrubbers at it King 

and Sherburne County plants to meet 0.12 lb/mmBtu. 

According to the Colorado Department of Public Health & Environment, “Colorado Ute Electric 

Association, which owned Craig before TriState, installed wet limestone FGD systems, on Craig 

Units 1 and 2 when the units began operations in 1980 and 1979, respectively. TriState upgraded 

these FGD systems in the 2003 – 2004 timeframe. The current Operating Permit also requires that 

100% of the flue gas in the FGD be treated and that the Craig Unit 1 and 2 FGDs be designed to meet 

at least a 97.3% removal rate.” 

In the late 1990s, Public Service of New Mexico (PSNM) replaced its existing SO2 controls with 

new limestone forced-oxidation scrubbers. In 2005 PSNM agreed to upgrade the scrubbers by 

2009 such that the annual rolling average SO2 percentage reduction for San Juan Units 1, 2, 3, 

and 4 shall not be less than 90% for each unit (based upon measurements upstream and 

downstream of scrubbers). 

It is clear that existing scrubbers can achieve better removal efficiency and lower emission rates 

than the 85% and 0.15 lb/mmBtu proposed by ADEQ. ADEQ must evaluate those options. 

Step 5: Evaluate the Energy and Non-Air Quality Environmental Impacts and Document Results

Economic Impacts for Unit 3 

Control Emission 

Rate 

(lb/ 

MMbtu) 

Total 

Emssn 

(Tons/ 

Yr) 

Total 

Emssn 

Rdctn 

(Tons) 

Annlzd 

Cost 

(Million$

) 

Cost/ 

Ton 

($) 

Incrmntl 

Cost/ton 

($/ton) 

Baseline 

(no control) 1.00 11,033 - - - - 

7 
8 

Wet Lime 

scrubber 0.15 1,655 9,378 $8.80 936 $936 

Step 6: Evaluate Visibility Impacts

A Visibility Impact Analysis was not performed for SO2 since the existing scrubbers are 

proposed as BART. 

Step 7: BART Selection

ADEQ: Based upon its review of the BART analysis provided by the company, and the 

information provided above, the Department has determined that wet lime scrubbers with an 

associated emission limit of 0.15 lb/MMBtu is the BART for control of SO2 for Units 2, 3 and 4. 

NPS: Neither APS nor ADEQ has conducted a proper BART analysis of upgrading the existing 

scrubbers. We suggest that ADEQ require that Cholla Units 2, 3, and 4 achieve at least 90% SO2

removal across the scrubbers, not to exceed 0.12 lb/mmBtu. 
NPS Comments 

Salt River Project (SRP)’s Coronado Generating Station BART Analysis and 

Determination 

November 29, 2010 

Process Description 

Salt River Project (SRP) Coronado Generating Station (CGS) is located near St. Johns in Apache 

County and is comprised of two dry-turbo-fired Units 1 and 2 with a net rated output of 395 MW 

and 390 MW, respectively. Presumptive BART applies to these two units with total capacity 

greater than 750 MW. Of 1,228 plants, EPA Clean Air Markets (CAM) data for 2008 rank the 

Coronado facility #146 for SO2 and #59 for NOX. Of 3,558 EGUs, 2008 CAM data rank 

Coronado Units 1 and 2 at #298 and #300, respectively for SO2, and #76 and #85 respectively for 

NOX. 

Despite the improper modeling methods applied by SRP and the resulting underestimations of 

impacts, the cumulative impacts of Coronado Units 1 and 2 across the 17 Class I areas modeled 

rank among highest of any facility we have evaluated under the BART program. 

 

Consent Decree

On December 22, 2008, SRP and EPA entered into a Consent Decree which requires the 

implementation of the following pollution control projects for SO2 and NOx at SRP’s CGS 

facility. 

 Addition of Low-NOX Burners (LNB) to Units 1 and 2 to reduce NOx emissions to 0.32 

lb/mmBtu by June 2011. Coupled with the burner additions, the furnace combustion air 

system on each Unit (ACC) will be modified. 

 Addition of a Selective Catalytic Reduction (SCR) to Unit 2 by June 2014. The SCR will 

further reduce NOx emissions from Unit 2 to 0.08 lb/mmBtu. 

 Replacement of the existing wet limestone Flue Gas Desulfurization (WFGD) systems on 

Unit 1 and Unit 2 with new WFGD systems by January 2012 to reduce SO2 emissions by 

95% or to 0.08 lb/mmBtu. 

BART for NOx

Step 1: Identify the Existing Control Technologies in Use at the Source

ADEQ: NOx emissions from both Units 1 and 2 are currently controlled by good combustion 

practices and overfire air. The resulting emission rate ranges from 0.45 to 0.50 lbs/MMBtu. 

NPS: 2000 – 2008 CAM data show Units 1 and 2 averaged 0.41 & 0.44 lb/mmBtu, respectively. 

 

Step 2: Identify All Available Retrofit Control Options

ADEQ: The alternative NOx control technologies for limiting NOx emissions from Unit 1 and 

Unit 2 are listed as follows: 

1 
 Advanced Combustion Control-Low NOx burners (LNB) and over fire air (OFA) 

 Selective non-catalytic reduction (SNCR) 

 Selective catalytic reduction (SCR) 

NPS: We agree with the suite of options. 

Step 3: Eliminate All Technically Infeasible Control Options

ADEQ has determined that all of the above control technologies are feasible options for BART 

at CGS. 

Step 4: Evaluate Control Effectiveness of Remaining Technologies

NPS: ADEQ selected LNB+OFA as BART at 0.32 lb/mmBtu with an estimated reduction of 

26% for Unit 1.

ADEQ has included this statement (copied from the company BART analysis): 

SCR can achieve NOx control efficiencies as high as 90% with inlet concentrations in the range of 300 to 

400 ppmvd. If inlet NOx concentrations are less than 250 ppmvd, SCR can achieve NOx control efficiencies 

ranging from 70% to 80%. 

This assertion is contrary to our understanding of SCR performance factors. (Please see our 

General BART Comments.) We suspect that ADEQ may have misunderstood because SCRs on 

lower concentration gas streams may have been designed to achieve lower removal efficiencies.1

Our understanding is that SCR performance is primarily a function of catalyst temperature, 

volume, type, and area. It is unlikely that the NOX concentration proposed as BART by ADEQ 

would present such a low concentration as to significantly reduce SCR removal efficiency. We 

request that ADEQ provide support for its contention. 

Because SCR will be applied to Unit 2 as a result of the Consent Decree, we will confine the 

remainder of our comments to Unit 1. 

For its cost-effectiveness analysis, ADEQ has estimated that LNB+OFA+SCR can achieve 0.08 

lb/mmBtu on an annual basis,2 which represents a 75% reduction by SCR from the emission rate 

to be achieved by LNB+OFA alone. It is generally assumed that SCR can achieve at least 90% 

NOX reduction, and we conclude that ADEQ has underestimated the ability of a modern SCR 

retrofit to reduce NOX emissions. Because such an underestimate adversely affects the costbenefit analysis, we conducted our analysis as discussed in our General BART Comments and 

below. 

 

1

 However, as noted below in an excerpt from the EPA Control Cost manual, at very low inlet concentrations, 

removal efficiency may be lower: 

In general, higher uncontrolled NOx inlet concentrations result in higher NOx removal efficiencies due to 

reaction kinetics. However, NOx levels higher than approximately 150 parts per million (ppm), generally 

do not result in increased performance. Low NOx inlet levels result in decreased NOx removal efficiencies 

because the reaction rates are slower, particularly in the last layer of catalyst. 2

 ADEQ appears to have assumed that SCR would achieve 0.07 lb/mmBtu regardless of averaging time. While we 

agree that 0.07 lb/mmBtu is a reasonable estimate for input into a visibility model that requires a 24-hour emission 

rate, it is always the case that average emission rates decrease as the averaging period increases. The data we present 

in our General BART Comments indicate that, if SCR can achieve 0.08 lb/mmBtu on a 24-hour basis, it is likely that 

that same SCR is achieving 0.06 lb/mmBtu (or lower) on a 30-day average basis and 0.05 lb/mmBtu (or lower) on 

an annual average. 

2 
Step 5: Evaluate the Energy and Non-Air Quality Environmental Impacts and Document Results

Non-Air Quality Environmental Impacts

ADEQ: SNCR and SCR installation could impact the salability and disposal of fly ash due to 

ammonia levels. Other environmental impacts involve the potential public and employee safety 

hazard associated with the storage of ammonia, especially anhydrous ammonia, and the 

transportation of the ammonia to the power plant site. 

NPS: Please see our General BART Comments. 

Economic Impacts 

NPS: A critical cost element is the Total Capital Investment (TCI) upon which much of the EPA 

Cost Manual method is based. As discussed in our General BART Comments, SCR costs can be 

expected to fall between $50 and $300/kW, with the recent average at slightly below $200/kW. 

In this context, the SRP estimate of $167/kW appears reasonable. 

Annual Cost estimates are generated by a direct application of the Cost Manual method to the 

new TCI and other interim values. We applied the Cost Manual method and found that SRP’s 

Annual Cost estimates are also reasonable. 

We concur with ADEQ’s estimated $1,021/ton for combustion controls plus SCR. 

Step 6: Evaluate Visibility Impacts

NPS: Because SRP used background ammonia levels that are unacceptably low (Appendix A 

Table A-2 of the company report), the visibility benefits are under-estimated and the Evaluation 

of Visibility Impacts step is unacceptable. 

Step 7: Select BART

ADEQ: After reviewing the BART analysis provided by the company, and based upon the 

information above, ADEQ has determined that BART control at CGS for NOx is ACC (Low NOx

burners with OFA) with an associated NOx emission rate of 0.32 lbs/MMBtu on 30-day rolling 

average basis. 

NPS: Because of the improper visibility modeling analysis noted above, ADEQ has not 

conducted a valid five-factor BART analysis. However, based upon the relatively low cost/ton 

for SCR and the magnitude and extent of the visibility impacts, it is likely that a proper 

evaluation of costs and visibility benefits across the 17 impacted Class I areas would conclude 

that SCR is BART. 

ADEQ estimates that SCR would cost less than $1,100/ton, which is less than EPA assumed for 

presumptive BART costs. BART, like BACT, is not necessarily the most-cost-effective option. 

Instead, it is typically chosen based upon a comparison to options selected by other regulatory 

3 
agencies in similar situations. For example, Oregon DEQ has established a cost/ton threshold of 

$7,300 based upon the premise that improving visibility in multiple Class I areas warrants a 

higher cost/ton than where only one Class I area is affected. In their BART proposal for the San 

Juan Generating Station, New Mexico used a range from $5,946/ton to $7,398/ton, Colorado is 

using $5,000/ton as a non-binding “guidepost,” and Wisconsin is using $7,000 - $10,000/ton as 

its BART threshold.3 Because BART is the best option that meets the selection criteria, SCR 

should be selected as BART due to the reasonable cost/ton and lower-than-average 

cost/deciview. 

PM10 BART 

Step 1: Identify the Existing Control Technologies in Use at the Source

PM10 emissions from the facility are currently controlled through the use of a hot-side ESP. 

Steps 2-6: Streamlined Review

ADEQ: SRP’s BART analysis for PM10 was limited to a statement that the current emission 

levels associated with the existing controls at the Coronado Generating Station range from 0.01 

to 0.03 lb/MMBtu. As noted in Section X, PM10 BART for similar emissions units with similar 

emissions controls was determined to be 0.03 lb/MMBtu. Since SRP’s CGS is already meeting 

or exceeding the stringency of the emissions limitation, further analysis was determined to be 

unnecessary. 

NPS: ADEQ’s contention that its proposed 0.03 lb/mmBtu BART limit “is already meeting or 

exceeding the stringency of the emissions limitation” “for similar emissions units with similar 

emissions controls” is not consistent with its Cholla BART analysis which concluded that 

replacement of the existing hot-side ESPs with fabric filters at 0.015 lb/mmBtu is BART. 

Step 7: Select BART

ADEQ: After reviewing the analysis provided by SRP, and the information presented above, 

ADEQ has determined that BART for PM10 from Units 1 and 2 is no further control, and an 

emissions limitation of 0.03 lb/MMBtu. 

NPS: ADEQ did not conduct the necessary five-step BART anaysis. 

SO2 BART 

Step 1: Identify the Existing Control Technologies in Use at the Source

 

3

 “The Department used cost-per-ton reduced as the primary metric for determining the BART level of control. The 

upper limit for this metric was $7,000 to $10,000 per ton, which reflects historical low-end costs for controls 

required under BACT.” BEST AVAILABLE RETROFIT TECHNOLOGY AT NON-EGU FACILITIES April 19, 

2010, WISCONSIN DEPARTMENT OF NATURAL RESOURCES

4 
SO2 emissions are currently controlled with the use of low-sulfur coal and partial wet flue gas 

desulfurization. The resulting emission rate ranges from 0.6 to 0.7 lbs/MMBtu. 

Step 2: Identify All Available Retrofit Control Options

Following control options are available for control of SO2.

 Wet Flue Gas Desulfurization 

 Spray Dryer Absorber 

 Dry Sorbent Injection 

Step 3: Eliminate All Technically Infeasible Control Options

ADEQ has determined that all of the referenced control technologies are technically feasible. 

Step 4: Evaluate Control Effectiveness of Remaining Technologies

ADEQ: SRP and EPA’s consent decree stipulates the installation of WFGDs for both the units. 

WFGD is the most effective control technology available for controlling SO2 emissions. Since 

SRP is committing to the WFGD technology, other control technologies are not evaluated from 

this point forward in the BART analysis. 

Step 5: Evaluate the Energy and Non-Air Quality Environmental Impacts and Document Results

Costs of Compliance

ADEQ: Based on the vendor data on the capital cost and operation & maintenance cost for 

different control options, Table 9 provides the information on the annual costs associated with 

each of the control options. 

Table 9: Total Capital and Annual Costs associated with SO2 Controls 

Control 

Option 

Control 

Technology 

Total Capital 

Cost 

Fixed 

Capital Cost 

Annual 

O&M 

Total 

Annualized 

Cost 

1 Baseline- Partial 

FGD -- -- -- -- 

2 WFGD $347,000,000 $32,753,330 $11,600,000 $44,353,330 

* Fixed capital cost calculation is based on a Capital Recovery Factor (CRF) of 0.09439, assuming an interest rate 

of 7%, and amortization period of 20 years. 

Table 10 provides annual estimated emission numbers for SO2 and cost figures relating to the 

implementation of WFGDs. 

Table 10: Total Annual Emissions of SO2 and cost of reduction with WFGD 

Baseline, Option 1 Option 2, WFGD 

Unit 1 14,556 tpy 1,909 tpy 

Unit 2 14,828 tpy 1,722 tpy 

5 
6 

Total (Both Units) 29,384 tpy 3,631 tpy 

Reduction from Baseline - 25,753 tpy 

Annualized Cost - $ 44,353,330 

Cost of reduction ($ per ton) - $1,722 

Step 6: Evaluate Visibility Impacts

ADEQ: The new WFGD control scenario was modeled for each meteorological year (2001-

2003) and for all 17 Class I areas within 300 km. The modeling result indicates that the 

installation of a WFGD will provide for significant visibility benefit. The highest visibility 

improvement will occur at the Petrified National Forest where an improvement of 1.38 ∆dv is 

expected. 

Table 11 provides information on annualized cost and the cost in dollars per deciview average 

improvement in visibility achieved by implementing the control option. 

Table 11: Summary for SO2 BART 

Option 1, Baseline Option 2, WFGD 

Reduction in Emission (tpy) - 25,753 

Annualized Cost - $44,353,330 

Visibility index (dv) 2.66 1.28 

Improvement in Visibility Index (dv) - 1.38 

Incremental Cost Effectiveness ($ per dv) - $32,140,094 

NPS: Because SRP used background ammonia levels that are unacceptably low (Appendix A 

Table A-2 of the company report), the visibility benefits are under-estimated and the Evaluation 

of Visibility Impacts step is unacceptable. 

Step 7: Select BART

ADEQ: Based on its review of the company’s analysis and the information above, the 

Department accepts SRP’s recommended BART control of WFGDs for both units with an 

associated SO2 emission rate of 0.08 lbs/MMBtu on 30-day rolling average basis. 

NPS: We concur and note that ADEQ has accepted the WFGD option at $1,722/ton and $32.1 

million/dv. 
NPS comments on the Catalyst Paper (Snowflake) Inc. BART Analysis and Determination 

December 2, 2010 

Process Description 

Abitibi Consolidated was purchased by Catalyst Paper Snowflake Inc (CPSI) in April of 2008. 

CPSI operates a recycled paper mill near Snowflake, Arizona, which produces newsprint and 

newsprint-like grades at a capacity of approximately 1,460 tons per day. A Powerhouse 

consisting of 3 boilers provides steam and electricity for use at the mill. Power Boiler #2 is rated 

at 1,132 million British thermal units (MMBtu) per hour and is the primary boiler. 

Description of Emissions Units Subject to Best Available Retrofit Technology (BART) 

ADEQ: Power Boiler #2 is a coal-fired boiler installed in 1975. CALPUFF modeling performed 

by CPSI demonstrated that the boiler has a visibility extinction of 0.739 deciviews on the Sierra 

Ancha Wilderness Area and 0.523 deciviews on the Superstition Wilderness Area. Therefore, 

the unit contributes to the impairment of visibility at a Class I area and is subject-to-BART for 

NOx and SO2. 

NPS: Agreed. 

NOx BART Analysis and Determination 

Step 1: Identify the Existing Control Technologies in Use at the Source

CPSI currently does not operate any NOx control technology on Power Boiler #2 although there 

is a permit limit of 0.7 lb/MMBtu. There is an existing over fire air system (OFA) that has never 

been operated. 

Step 2: Identify All Available Retrofit Control Options

CPSI has identified seven control options: 

 Operate the existing OFA 

 Install Low NOx Burners (LNB) 

 Install LNB with new OFA 

 Install LNB, new OFA, and a selective non-catalytic reduction system (SNCR) 

 Install a Rotating Over Fire Air (ROFA) system 

 Install a ROFA with SNCR 

 Install LNB, new OFA, and a selective catalytic reduction system (SCR) 

NPS: ADEQ has chosen a reasonable suite of options. 

Step 3: Eliminate All Technically Infeasible Control Options

ADEQ has determined that all of the control options identified above are technically feasible. 

1 
Step 4: Evaluate Control Effectiveness of Remaining Technologies

According to the analysis performed by Catalyst Paper, the technically feasible control options 

were identified as being able to achieve the following emissions rates: 

Table 4: Control Effectiveness of Control Options 

Control Option Achievable Emissions Rate 

(lb/MMBtu) 

OFA 0.525 

LNB 0.370 

ROFA 0.348 

ROFA with SNCR 0.291 

LNB with new OFA 0.265 

LNB, OFA, and SNCR 0.194 

LNB,OFA, and SCR 0.070 

NPS: In its SNCR cost analyses, CPSI has assumed a boiler uncontrolled NOx emission rate of 

0.192 lb/mmBtu and a desired outlet emission rate of 0.148 lb/mmBtu. Because the uncontrolled 

emission rate is lower than the “Achievable Emission Rates” evaluated by ADEQ, the ADEQ 

analyses are invalid. 

In its SCR cost analyses, CPSI has assumed a boiler outlet NOx emission rate of 0.265 

lb/mmBtu. We have shown in our General BART Comments that SCR can reduce emissions by 

at least 90%, which corresponds to the 0.03 lb/mmBtu, less than half of the rate evaluated by 

CPSI. 

ADEQ must reconcile the wide disparity between the values in its Table 4 and the emission rates 

used by CPSI to generate its cost data below. 

Step 5: Evaluate the Energy and Non-Air Quality Environmental Impacts and Document Results

Cost of Compliance

ADEQ: During the course of Catalyst Paper’s review of the technically feasible control options, 

the company identified the expected amount of emissions reduced by the application of each 

control option, as well as the annualized cost, and the average cost effectiveness of the controls. 

That information is summarized in Table 5 below. 

2 
Table 5: Cost of Compliance of Control Options 

Control Option 

Expected 

emissions 

reduction 

(tpy) 

Annualized Cost 

Average Cost 

Effectiveness 

($/ton NOx) 

OFA 868 $3,221,3592 $3,711 

LNB 1,636 $3,400,185 $2,078 

ROFA 1,745 $4,262,553 $2,443 

ROFA with SNCR 2,028 $4,903,534 $2,418 

LNB with new OFA 2,157 $3,509,992 $1,627 

LNB, OFA, and SNCR 2,509 $3,968,779 $1,582 

LNB,OFA, and SCR 3,124 $7,181,536 $2,299 

1. This analysis assumes the facility is current emitting NOx at the permit limit of 0.7 lb/MMBtu. That is the 

rate at which CPSI modeled visibility impacts and therefore must be held constant for any analysis based on emission 

rates. 

2. There is a large annualized cost to this existing equipment because it has been assumed that its operation 

would make the fly ash from the boiler unsellable. 

ADEQ: From Table 5 it can be seen that ROFA and ROFA with SNCR are inferior options 

because there is an option (LNB with new OFA) that provides greater annual reduction at a 

lower annualized cost. ADEQ has eliminated those control options from consideration and the 

incremental cost effectiveness associated with the remaining control options is as follows: 

NPS: Despite ADEQ’s assertion that the cost analysis must be based upon the 0.7 lb/mmBtu 

permit limit, the analyses submitted by CPSI and used by ADEQ were actually based upon the 

lower NOx emission rates we noted above. Furthermore, the CPSI BART analysis used a 10.5% 

interest rate instead of the 7% interest rate recommended by the Cost manual. As a result, the 

ADEQ costs are overestimated and its analyses are invalid. 

As explained by ADEQ in footnote #2 to its Table #5, “There is a large annualized cost to this 

existing equipment because it has been assumed that its operation would make the fly ash from 

the boiler unsellable.” Neither CPSI nor ADEQ have provided any concrete justification to 

support its speculation. On the contrary, our conversations with SNCR vendors indicate that this 

claim is probably invalid. 

Energy Impacts

ADEQ: According to the analysis provided by CPSI, there are adverse energy impacts that 

require consideration for several of the technically feasible control options. Specifically, CPSI 

reported that the OFA would require 224 kW of power, the SNCR would require 10 kW, and the 

SCR would require 377 kW. ADEQ notes that the LNB would require no additional power. 

NPS: These energy costs are included in the overall cost analysis. 

Non Air-Quality Environmental Impacts

3 
ADEQ: According to CPSI’s analysis, non-air quality impacts may result due to the application 

of several technically feasible control technologies. Specifically, CPSI stated that due to the 

potential increase in the amount of unburnt carbon, the installation of LNB and OFA may have 

the potential of rendering the fly ash unsellable. If the fly ash were rendered unsellable, the fly 

ash would increase the amount of solid waste generated at the facility, ultimately increasing the 

amount sent to the landfill. 

In addition to the LNB and OFA technologies, SCR and SNCR have the potential to impact the 

sellability of the fly ash. As noted above, both technologies rely on the injection of ammonia to 

reduce the formation of NOx. Most SCR and SNCR vendors recommend that the operator inject 

more than the stoichiometric amount of ammonia to drive NOx formation to a minimum. This 

practice results in emissions of ammonia (called ammonia slip). Since the ammonia has an 

affinity for the fly ash, its presence in the exhaust stream could result the spoiling of the fly ash, 

leading to increased solid waste from the facility. 

NPS: The concerns raised by CPSI and ADEQ are speculative and unsupported. 

Remaining Useful Life

ADEQ: None of the documentation submitted by CPSI has indicated that the facility will be shut 

down in the near future. For the purposes of its analyses, CPSI assumed a typical equipment life 

of 15 years for calculating the annualized cost of control options. As a result, ADEQ has 

determined that the remaining useful life of the mill has no effect on this BART analysis. 

NPS: CPSI incorrectly assumed a 15-year life for SNCR and SCR. The Cost Manual 

recommends a 20-year life. As a result, ADEQ has overestimated the annual costs of SNCR and 

SCR. 

Step 6: Evaluate Visibility Impacts

ADEQ: As part of its analysis of potential BART options, CPSI estimated the total visibility 

improvement that is projected to occur should one of the technically-feasible and cost-effective 

control options be applied. Based upon that information, ADEQ was also able to calculate the 

average cost effectiveness in terms of dollars per deciview of visibility improvement. CPSI’s 

results are summarized in Table 7 below. 

Table 7: Visibility Impacts of Remaining Control Options

Control Option Deciview Improvement* Cost Effectiveness* 

($/Deciview) 

OFA 0.076 $42.4 million 

LNB 0.164 $20.7 million 

LNB with new OFA 0.207 $17.0 million 

LNB, OFA, and SNCR 0.252 $15.7 million 

LNB,OFA, and SCR 0.309 $23.2 million 

*Based on visibility effects at most impacted Class I area – Sierra Ancha WA 

NPS: ADEQ must also consider the benefits to the other Class I areas. 

4 
Step 7: Select BART

ADEQ: Based upon its review of CPSI’s analysis, and in particular the marginal visibility impact 

from the current facility operations and the magnitude of the dollar per deciview costs in Table 7, 

ADEQ has determined that BART for control of NOx from Power Boiler #2 is the current 

emission limit of 0.7 lb/MMBtu. 

NPS: ADEQ is proposing that BART be an emission rate more than double that used by CPSI in 

its analyses. Even though the cost estimates relied upon by ADEQ are inflated, the $/dv values 

estimated by ADEQ for Sierra Ancha WA for LNB with new OFA and LNB, OFA, and SNCR 

fall within the range of average $/dv costs proposed or accepted by other sources and states. 

ADEQ has incorrectly evaluated the effectiveness and cost of the control options, and ignored 

the visibility benefits to multiple Class I areas. ADEQ’s BART analysis for Catalyst Paper is not 

acceptable. 

SOx BART Analysis and Determination 

Step 1: Identify the Existing Control Technologies in Use at the Source

ADEQ: Power Boiler #2 has a SO2 permit limit of 0.8 lb/MMBtu and is controlled with a wet 

sodium flue gas desulfurization system tray tower scrubber. 

Step 2: Identify All Available Retrofit Control Options

ADEQ: CPSI has identified two control options as potentially being BART: 

 Upgrade the existing scrubber 

 Add a second scrubber 

In 2008, CPSI was forced to switch to Lee Ranch Mine coal due to the closure of the McKinley 

Mine. The coal now available to CPSI has an average sulfur content of 2.3 lb/MMBtu and the 

facility has been forced to complete much of the upgraded scrubber project in order to maintain 

compliance with the 0.8 lb/MMBtu emission limit in its operating permit. As it now represents 

baseline control, it is no longer appropriate to consider upgrading the scrubber to be an additional 

control option. 

Add a second scrubber. A second scrubber could be added in order to capture 100% of the flue 

gas at an efficiency of 98%. This would increase the overall control efficiency from 63.9% to 

98% control. 

Step 3: Eliminate All Technically Infeasible Control Options

ADEQ has determined that both control options identified above are technically feasible. 

Step 4: Evaluate Control Effectiveness of Remaining Technologies.

5 
According to the analysis performed by CPSI, the technologically feasible controls are capable 

of achieving the following emissions rates: 

Table 8: Control Effectiveness of Control Options 

Control Option Achievable Emissions Rate 

(lb/MMBtu)

Upgrade Current Scrubber / Baseline 

Control 

0.80 

Add Second Scrubber 0.044 

Step 5: Evaluate the Energy and Non-Air Quality Environmental Impacts and Document Results

Cost of Compliance

During the course of CPSI’s review of the technically feasible control options, the company 

identified the expected amount of emissions reduced by the application of each control option, as 

well as the annualized cost and the average cost effectiveness. That information is summarized 

in Table 9 below. 

Table 9: Cost of Compliance of Control Options 

Control Option 

Expected 

emissions 

reduction 

(tpy) 

Annualized Cost 

Average Cost 

Effectiveness 

($/ton SO2) 

Upgrade Current 

Scrubber / 

Baseline Control 

0 0 N/A 

Add second 

scrubber 3,743 $4,769,365 $1,274 

1. This analysis assumes the facility is current emitting SO2 at the permit limit of 0.8 lb/MMBtu. That is the rate at 

which CPSI modeled visibility impacts and therefore must be held constant for any analysis based on emission 

rates. 

NPS: The ADEQ data presented above does not match the data provided by CPSI in its 1/17/08 

BART analysis. For example, CPSI Tables 3-4 and in its Appendix A show that addition of a 

second wet scrubber would reduce SO2 emissions by 10,764 tpy at $901/ton at the same annual 

cost that ADEQ assumes to remove 3,743 tpy and $1,274/ton. The Alstom Power 10/21/06 

Budgetary Proposal quoted a turnkey price for the new scrubber at $11,500,000. However, the 

CPSI BART analysis increased this cost to $15 million in its Appendix A. It is therefore not 

possible to evaluate the ADEQ analysis without any supporting information. It appears that 

change to higher sulfur coal that occurred after the CPSI BART analysis was conducted has 

invalidated that analysis. 

Non Air-Quality Environmental Impacts

6 
7 

CPSI has stated that the addition of a second scrubber will result in the generation of an 

additional 8,000 tpy of solid scrubber waste and the additional use of 38 million gallons of water 

per year. 

Step 6: Evaluate Visibility Impacts

As part of its analysis of potential BART option, CPSI estimated the total visibility improvement 

that is projected to occur should one of the technically-feasible and cost-effective control options 

be applied. Based upon that information, ADEQ was also able to calculate the average cost 

effectiveness in terms of dollars per deciview of visibility improvement. CPSI’s results are 

summarized in Table 10 below. 

Table 10: Visibility Impacts of Control Options 

Control Option Deciview Improvement* Cost Effectiveness* 

($/Deciview) 

Add 2nd Scrubber 0.20 $23.8 million 

1. Based on visibility effects at most impacted Class I area – Sierra Ancha WA 

NPS: ADEQ must also consider the benefits to the other Class I areas. 

Step 7: Select BART

ADEQ: Based upon its review of CPSI’s analysis, and the all of the considerations listed above, 

ADEQ has determined that BART for control of SO2 from Power Boiler #2 is the current 

upgraded scrubber, as defined in Step #2, with an emission limit of 0.80 lb/MMBtu. 

NPS: ADEQ has incorrectly evaluated the cost of the control options, and ignored the visibility 

benefits to multiple Class I areas. ADEQ’s BART analysis for Catalyst Paper is not acceptable. 
NPS Comments on ADEQ BART Exemptions 

December 1, 2010 

Arizona Public Service (APS) West Phoenix 

ADEQ states: On October 7, 2007, APS West Phoenix submitted a second letter to ADEQ. In 

that letter, APS West Phoenix explained that it agreed with ADEQ’s assessment that the 

Combined Cycle Units CC1, CC2 and CC3 were BART-eligible. APS West Phoenix stated, 

however, that after correcting the air dispersion modeling analysis using the assumptions 

identified above, the 98th percentile visibility impacts that ADEQ had predicted in the 

Superstition Wilderness and the Mazatzal Wildernerss areas dropped from 0.69 dv and 0.64 dv, 

to 0.24 dv and 0.31dv respectively. 

Based on the revised air dispersion modeling analysis that was submitted on October 7, 2007, 

APS West Phoenix stated that it did not cause or contribute to regional haze in a Class I area, and 

therefore was not subject-to-BART. Based upon its review of the information that has been 

submitted, and a review of the conditions in Maricopa County Air Quality Permit V95-006, 

ADEQ concurs that this facility is not subject-to-BART. 

NPS: Please provide the revised air dispersion modeling analysis that was submitted on October 

7, 2007 and was the basis for exemption.

Arizona Portland Cement Company 

ADEQ states: In 2003, during its review of a proposed Title V permit that would have provided 

APCC with the flexibility to choose between three operating scenarios, including the 

construction of Kiln 5, EPA identified an error in APCC’s fugitive dust emissions calculations. 

According to EPA’s calculations, the modifications that were completed in 1998 should have 

gone through New Source Review. As a result, EPA issued a Notice of Violation to APCC, 

alleging that the company avoided New Source Review when completing modifications to Kiln 4 

in 1998. EPA also objected to the issuance of the proposed Title V permit, but later lifted its 

objection after ADEQ removed the alternative operating scenarios that would have allowed for 

further modification of the facility. A consent decree is being finalized between APCC and EPA 

to resolve the issue. 

In 2008, ADEQ issued a new permit to APCC which would have allowed the facility to stop 

operations at all four existing kilns and construct and operate a new Kiln 6. The 18 month 

construction window ended in June 2010 and APCC has since reapplied for a permit for the Kiln 

6 expansion. 

Based upon the consideration of the history of this facility, and the maximum 98th percentile 

three-year average impact from all pollutants is less than 0.5. dv, ADEQ concurs that APCC is 

not subject-to-BART. 

1 
NPS: We disagree with the exemption based on "the maximum 98th percentile three-year average 

impact from all pollutants is less than 0.5 dv". The BART exemption criteria should be that any 

98th percentile impact from all pollutants in any of the three modeled years is less than 0.5 dv. 

Further, as discussed in our technical comments, because the WRAP modeling did not use the 

upper air observations, the FLM recommended that the WRAP states use the maximum impact 

value with the annual average natural background conditions rather than the 8th highest impact 

value. In this case, the maximum impact exceeded 0.5 dv at Saguaro NM, Galiuro WA, 

Superstition WA, and Mazatzal WA. 

With regard to the "history of this facility," until the retirement of kiln #4 is made federally 

enforceable, it will remain BART-eligible, and, as explained above, subject to BART. 

Chemical Lime Company – Nelson Lime Plant 

ADEQ states: On September 21, 2007, CLC submitted a letter to ADEQ along with a new 

modeling analysis indicating that “...the 3-year average of the 8th highest visibility change is less 

than 0.5 dv in all Class I areas.” Based upon its review of the new modeling analysis, Chemical 

Lime concluded that the Nelson facility did not cause or contribute to visibility impairment in 

any Class I area, and that the emissions units were, therefore, not subject-to-BART. 

Based upon its refined visibility change analysis, CLC determined that the visibility change 

attributable to the Nelson facility is below 0.5 dv, and it concluded that the facility does not 

significantly contribute to visibility impairment within the Grand Canyon National Park. As a 

result, CLC determined that the results of the analysis indicated that the 3-year average of the 8th

highest visibility change was less than 0.5 dv in all Class I areas within 300 km of the facility, 

and concluded that its Nelson facility was not-subject-to-BART. 

The company also recognized, however, that the predicted impacts within the Grand Canyon 

were marginally below 0.5 dv. As a result, the company stated that “[a]lthough the maximum 

visibility change obtained in the screening modeling analysis is not equal to or greater than the 

0.5 dv contribution threshold, a refined analysis was performed in which light extinction in the 

Grand Canyon National Park was calculated using the CALPOST-IMPROVE implementation of 

the revised light extinction algorithm...” Based upon the refined analysis, the 98th percentile (8th

highest) Visibility Change in the Grand Canyon was calculated to be as follows: 

98th Percentile (8th highest) Visibility 

Class I Area Change (dv) 

2001 2002 2003 Average 

Grand Canyon NP 0.417 0.375 0.585 0.46 

Based upon the consideration of the analysis performed for this facility, CLC’s conservative 

approach for estimating emissions impacts during the meteorological period, and the maximum 

98th percentile three-year average impact from all pollutants is less than 0.5. dv, ADEQ concurs 

that the Chemical Lime Company’s Nelson Lime Plant is not subject-to-BART. 

2 
NPS: Please provide the September 21, 2007, CLC letter to ADEQ and the new modeling 

analysis by CLC. 

It appears that CLC did not include the 154 tpy of PM emissions modeled by WRAP: 

Emissions Unit 

SO2

emissions 

(lb/hr) 

NOX

emissions 

(lb/hr) 

Kiln 1 215.59 122.14 

Kiln 2 484.27 182.78 

Why were the PM emissions not included? All emissions are to be included in the BART 

exemption modeling. 

ADEQ incorrectly exempted the CLC Nelson Plant. The correct criteria for BART exemption is 

to determine whether any 98th percentile impact from all pollutants in any year is greater than 

0.5. dv. The 98th percentile impact at Grand Canyon NP in 2003 exceeded 0.5 dv. Further, the 

FLM recommended that because the WRAP modeling did not use upper air observations, the 

maximum impact, rather than the 98th percentile impact, should be used with the annual average 

natural background visibility conditions. 

We conclude that the Chemical Lime Company – Nelson Lime Plant is subject to BART. 

TEP – Irvington Generating Station 

ADEQ states: Regarding Unit I4, TEP stated that during the 1980s, Unit I4 was converted to 

burn coal in accordance with a prohibition order that was issued pursuant to Section 301(c) of the 

Power Plant and Industrial Fuel Use Act of 1978. The Final Prohibition Order became effective 

on September 21, 1981, as noted in Federal Register Vol. 46, p. 37960. In its January 2, 2007, 

letter, TEP stated that compliance with the Final Prohibition Order required TEP to reconstruct 

Unit I4. According to 40 CFR 51.301, Reconstruction is defined as follows: 

Reconstruction will be presumed to have taken place where the fixed capital cost of the new 

component exceeds 50 percent of the fixed capital cost of a comparable entirely new source. 

Any final decision as to whether reconstruction has occurred must be made in accordance with 

the provisions of § 60.15(f)(1) through (3) of this title. 

TEP stated that because Unit I4 was reconstructed after August 7, 1977, the Unit was not “in 

existence” before August 7, 1977, and, therefore, must be considered “not BART-eligible”. 

ADEQ concurs that the cost of modifying TEP Irvington’s Unit I4 is greater than 50 percent of 

the fixed capital cost of a comparable, entirely new source, and that Unit I4 was reconstructed in 

the 1980s. 

3 
In Federal Register, Vol. 70, No. 128, Wednesday, July 6, 2005, pages 39110-39112, EPA 

discusses Step 2 in determining whether a facility is BART-eligible. According to the 

background statement in the guidance: 

“Step 2 also addresses the treatment of ‘reconstruction’ and ‘modifications.’ Under the 

definition of BART-eligible facility, sources which were in operation before 1962 but 

reconstructed during the 1962 to 1977 time period are treated as new sources as of the time of 

reconstruction.” 

The footnote attached to this statement goes on to state: 

“However, sources reconstructed after 1977, which reconstruction had gone through NSR/PSD 

permitting, are not BART-eligible.” 

ADEQ has reviewed 40 CFR Part 51 Appendix Y, Section II.A.2 and has determined that EPA 

has addressed this issue: 

 “What is a ‘reconstructed source?’ 

1. Under a number of CAA programs, an existing source which is completely or 

substantially rebuilt is treated as a new source. Such ‘reconstructed’ sources are treated as 

new sources as of the time of the reconstruction. Consistent with this overall approach to 

reconstruction, the definition of BART-eligible facility (reflected in detail in the definition of 

‘existing stationary facility’) includes consideration of sources that were in operation before 

August 7, 1962, but were reconstructed during the August 7, 1962 to August 7, 1977 time period. 

2. ... 

3. ... 

4. The ‘in-operation’ and ‘in existence’ tests apply to reconstructed sources. If an emissions 

unit was reconstructed and began actual operation before August 7, 1962, it is not BARTeligible. Similarly, any emissions unit for which a reconstruction ‘commenced’ after August 7, 

1977, is not BART-eligible.” (emphasis added) 

ADEQ has determined that EPA’s guidance does not specifically address situations where a 

facility was reconstructed after August 7, 1977, but was exempted from PSD review at the time 

that reconstruction occurred. ADEQ concludes, however, that the plain reading of EPA’s 

guidance is most appropriate, and has determined that it is appropriate to treat reconstructed 

sources as new sources as of the time of the reconstruction. As a result, ADEQ concurs that the 

reconstructed Unit I4 at TEP’s Irvington Generating Station was not “in existence” prior to 

August 7, 1977. Therefore, ADEQ has determined that there are no BART-eligible emissions 

units at TEP’s Irvington Generating Station. 

NPS: The clear intent of EPA's BART Guidelines is to exempt a source that has gone through 

New Source Review (NSR) from a "second hit" by going through BART. Because TEP Unit I4 

did not go through NSR, that exemption does not apply. 

4 
5 

ASARCO Hayden Smelter 

For SO2, we participated in the WRAP group that reported that “[a] double contact acid plant is 

considered the appropriate retrofit control equipment” and agree with ADEQ’s conclusion that 

the installation and operation of the double contact acid plant with the New Source Performance 

Standard of 650 ppm constitutes BART for SO2. 

For PM10, ADEQ concluded that the PM10 emissions from the BART-eligible units are less 

than 250 tons per year. On this basis ADEQ determined that the smelter units are not BARTeligible for PM10. However the BART Guidelines do not allow exception of a PM10 source if 

its emissions exceed 15 tpy: 

(ii) A determination of BART for each BART-eligible source in the State that emits any air 

pollutant which may reasonably be anticipated to cause or contribute to any impairment of 

visibility in any mandatory Class I Federal area. All such sources are subject to BART. 

 

(C) Exception. A State is not required to make a determination of BART for SO2 or for NOx if a 

BART-eligible source has the potential to emit less than 40 tons per year of such pollutant(s), or 

for PM10 if a BART-eligible source emits less than 15 tons per year of such pollutant. 

Please explain how "ADEQ determined that the emissions units at the ASARCO smelter are not 

BART-eligible for PM10 emissions." 

Freeport-McMoRan Miami Smelter 

We concur with ADEQ’s conclusion that the NESHAP for Primary Copper Smelting constitutes 

BART for PM emissions. 

We participated in the WRAP group that reported that “[a] double contact acid plant is 

considered the appropriate retrofit control equipment” and agree with ADEQ’s conclusion that 

the installation and operation of the double contact acid plant with the New Source Performance 

Standard of 650 ppm constitutes BART for SO2.


U.S. Forest Service Specific Comments: Arizona Regional Haze SIP 

Chapter 8: Sources of Visibility Impairment

In Section 8.4 - Arizona Emission Data, Tables 8-1 through 8-8 display the differences between 

the Plan02d and Prp18b inventories to describe the net change in emissions between the baseline 

and future year during the first planning cycle. Interpretation of these tables is challenging 

because Arizona has elected to submit a plan under 51.308 yet the reductions anticipated in the 

Prp18b inventory represent the anticipated to meet milestone required under the original 51.309 

submittal. ADEQ must reconcile the inventory differences between original milestone reductions 

under 51.309 and those that would be realized as a result of SO2 BART reductions now required 

under the 51.308 portion of the Regional Haze Rule. 

The statewide SO2 emissions inventory presented in Table 8-1 do not comport with the PSAT 

modeling results presented in Chapter 9. According to Table 8-1, Arizona anticipates a 28.81% 

decrease in point source SO2 emissions between 2002 and 2018 yet PSAT results show an 

increase in point source impacts at several Class I areas in Arizona. 

Chapter 9: Visibility Modeling and Source Apportionment

Under 40 CFR 51.308(d)(3)(iii), a state must document the technical basis it is relying upon to 

meet its reasonable progress goals. Chapter 8 of the SIP provides a very brief summary of the 

Western Regional Air Partnership (WRAP) Technical Support System (TSS) and emission 

inventory data. Chapter 9 describes the air quality modeling source apportionment techniques 

relied upon to help inform strategy development. However, Chapter 9 does not provide a detailed 

discussion of the either the Particle Source Apportionment Technique (PSAT) or the Weighted 

Emissions Potential (WEP) processes, which are crucial to understanding the utility of the 

various assessment methodologies the state relies upon to set its reasonable progress goals. WEP 

and PSAT use different emission inventories which should be clarified to aid the interpretation of 

visibility projections. Additional information regarding the methodologies should be included in 

this chapter. 

Additionally, Chapter 9 does not provide performance evaluations of either prognostic 

meteorological model data or the base case results from the WRAP Base02d inventory used in 

the regional air quality models, CMAQ or CAMx. Without an understanding of model 

performance, we cannot conclude that the state’s model is reasonably reliable nor understand 

inherent model nuances that can aid in our understanding of the model results. 

Chapter 10: Best Available Retrofit Technology (BART) Evaluation

The Forest Service concurs with the initial comments provided by the Department of Interior on 

Arizona’s BART exclusion process. Specifically, the WRAP developed CALMET 

meteorological fields using a nonstandard method which did not require the incorporation of 

upper atmospheric data. Additionally, previous EPA testing of CALPUFF Version 6.112, 

utilized by WRAP for its initial CALPUFF modeling, indicated several issues with default 

technical options which could bias model estimates low. The FLMs have typically only agreed to 

such an approach for CALPUFF modeling if the states use either the maximum visibility impact 
with the annual average natural condition or the 98th percentile impact with 20% best natural 

conditions. In this SIP, Arizona has used the 98th percentile impact with the annual average 

natural condition. We request that sources that were determined to not be subject to BART be reevaluated using the more rigorous criteria using the approach described above. 

Chapter 11: Reasonable Progress Goal Demonstration

The Regional Haze Rule requires States to demonstrate reasonable progress in visibility 

improvement by 2018 for the 20% worst days and to protect visibility on the 20% best days. In 

mandatory Class I areas in Arizona, the plan goals do not meet the uniform rate of progress 

(URP) in improving visibility on the 20% worst days by 2018 as mandated in 40 CFR 

51.308(d)(1): 

What are the core requirements for the implementation plan for regional haze? The State must address 

regional haze in each mandatory Class I Federal area located within the State and in each mandatory 

Class I Federal area located outside the State which may be affected by emissions from within the State. To 

meet the core requirements for regional haze for these areas, the State must submit an implementation plan 

containing the following plan elements and supporting documentation for all required analyses: 

(1) Reasonable progress goals. For each mandatory Class I Federal area located within the State, 

the State must establish goals (expressed in deciviews) that provide for reasonable progress 

towards achieving natural visibility conditions. The reasonable progress goals must provide for 

an improvement in visibility for the most impaired days over the period of the implementation 

plan and ensure no degradation in visibility for the least impaired days over the same period. 

The proposed goals in Chapter 11 allow for incremental increases in anthropogenic impacts at 

most Arizona Class I areas, and also allow for degradation in the least impaired days at four 

Class I areas (Chiricahua NM, Chiricahua WA, Galiuro WA, and Saguro NP) represented by two 

IMPROVE monitors. This, again, is contrary to 40 CFR 51.308(d)(1). In a number of cases cited 

below, both the WEP and PSAT analyses show increases in anthropogenic emissions at a 

number of Arizona Class I areas. 

1. Section 9.3.1 – Chiricahua NM, Chiricahua WA, and Galiuro WA: PSAT results for SO4

and NO3 (Figure 9-11 and 9-12) show increases in the AZ point category. 

2. Section 9.3.2 – Grand Canyon NP: PSAT results for SO4 and NO3 (Figure 9-13 and 9-

14) also show an increase in the AZ point category over the baseline period. 

3. Section 9.3.3 – Mazatzal WA and Pine Mountain WA: PSAT results for SO4 and NO3

(Figure 9-15 and Figure 9-16) show an increase in the AZ point category over the 

baseline period. 

4. Section 9.3.4 – Mount Baldy WA: PSAT results for SO4 (Figure 9-17) shows nearly 

steady SO4 impacts from AZ point and NO3 (Figure 9-18) shows an increase from AZ 

point category. 

5. Section 9.3.5 – Petrified Forest NP: PSAT results for SO4 and NO3 (Figure 9-19 and 

Figure 9-20) show an increase from AZ point sources. 

6. Section 9.3.6 – Saguaro NP West Unit: PSAT results for SO4 and NO3 (Figure 9-21 and 

Figure 9-22) show an increase from AZ point sources. 

7. Section 9.3.6 – Saguaro NP East Unit: PSAT results for SO4 and NO3 (Figure 9-23 and 

Figure 9-24) show an increase from AZ point sources. 
8. Section 9.3.7 – Sierra Ancha WA: Figure 9-25 shows an increase in SO4 impact from AZ 

point category. 

9. Section 9.3.8 – Superstition WA: PSAT results for SO4 and NO3 (Figure 9-27 and 9-28) 

show increases in the AZ point category. 

10. Section 9.3.10 – Sycamore Canyon WA: PSAT results for SO4 and NO3 (Figure 9-29 and 

9-30) show increases in the AZ point category. 

In Section 11.3.3 – Non-BART Sources, the Forest Service strongly disagrees with the adequacy 

of the Arizona reasonable progress analysis, especially in lieu of the reality that the uniform rate 

of progress is not being met for either SO4 or NO3 at any of the Arizona Class I areas. The SIP 

identifies a several source categories for which no attempt was made to complete a reasonable 

progress analysis. This is also problematic inasmuch as the PSAT results indicate increases in 

point source impacts from Arizona sources between 2002 and 2018.

Chapter 12: Long Term Strategy

Section 12.4 – Other States’ Class I Areas Affected by Arizona Emissions discusses the 

contribution of Arizona to neighboring states’ Class I areas. However, we do not believe this 

discussion addresses the requirements as specified under 40 CFR 51.308(d)(3)(i-ii): 

 (3) Long-term strategy for regional haze. Each State listed in § 51. 300(b)(3) must submit a long-term 

strategy that addresses regional haze visibility impairment for each mandatory Class I Federal area within 

the State and for each mandatory Class I Federal area located outside the State which may be affected by 

emissions from the State. The long-term strategy must include enforceable emissions limitations, 

compliance schedules, and other measures as necessary to achieve the reasonable progress goals 

established by States having mandatory Class I Federal areas. In establishing its long-term strategy for 

regional haze, the State must meet the following requirements: 

(i) Where the State has emissions that are reasonably anticipated to contribute to visibility 

impairment in any mandatory Class I Federal area located in another State or States, the State 

must consult with the other State(s) in order to develop coordinated emission management 

strategies. The State must consult with any other State having emissions that are reasonably 

anticipated to contribute to visibility impairment in any mandatory Class I Federal area within the 

State. 

(ii) Where other States cause or contribute to impairment in a mandatory Class I Federal area, 

the State must demonstrate that it has included in its implementation plan all measures necessary 

to obtain its share of the emission reductions needed to meet the progress goal for the area. If the 

State has participated in a regional planning process, the State must ensure it has included all 

measures needed to achieve its apportionment of emission reduction obligations agreed upon 

through that process. 

First, the State must demonstrate that it has included all measures necessary to get its share of the 

emissions reductions needed to meet the progress goal for the area. The discussion in Section 

12.4.1 is presented in terms of the state level contribution for aggregate visibility for all Class I 

areas within a given state. This approach does not address the specific requirement of 

51.308(d)(ii) to examine the efficacy of a state’s emission reduction measures to help meet the 

progress goal of the area, which can only addressed by examination of the reasonable progress of 

specific Class I areas. Second, we do not believe that Arizona’s emission reduction measures are 
sufficient to meet this requirement given that incremental increases at a number of Arizona Class 

I areas attributed to increases in Arizona area sources as documented in the PSAT analysis 

results from Chapter 9. 
























RESPONSIVENESS SUMMARY 

Comments Taken at the Public Hearing and Written Comments Received on the 

Proposed 2010 Regional Haze State Implementation Plan Under Section 308 of the 

Federal Regional Haze Rule 

Chapter 1 – Introduction

(1) Comment: In Section 1.4, Background on the Regional Haze Rule, Grand Canyon Visibility Transport 

Commission Findings and Recommendations, the GCVTC concluded the contribution of nitrates to total light 

extinction on an annual basis on the Colorado Plateau is only 4%. APS encourages ADEQ to emphasize this 

point and suggests adding language to highlight that fact. 

Response: ADEQ acknowledges the comment but does not concur that it is necessary to revise the historical 

background information. Since the publication of the GCVTC report in 1996, total extinction from nitrates 

may have changed and ADEQ cannot confirm the continued accuracy of the stated percentage. 

(2) Comment: In Section 1.5, Purpose of the Document, Basic Plan Elements, Natural Sources of Visibility 

Impairment. APS believes it is important that ADEQ recognize the role Rayleigh scattering by air 

molecules. APS suggest that ADEQ include a paragraph clarifying that Rayleigh scattering contributes 

approximately 10 Mm-1 to total extinction. On the Colorado Plateau, this constitutes roughly one-third of 

the total extinction on an annual average basis. 

Response: ADEQ acknowledges the comment but does not concur that it is necessary to revise the 

information. Rayleigh scattering is factored into the visibility impairment analyses and further discussion is 

duplicative. 

Chapter 4 – Section 4.3 – Regional Haze Monitoring Commitments

(3) Comment: ADEQ needs to discuss its commitment to assuring continued visibility monitoring in the 

future. 

Response: ADEQ has revised Section 4.3 to include a discussion of its commitment to continue visibility 

monitoring in the future. ADEQ’s current monitoring plan identifies the IMPROVE sites as the visibility 

network for monitoring regional haze and are described in Section 4.2 of Chapter 4. ADEQ will continue to 

use the federally operated and funded IMPROVE sites for monitoring visibility conditions at the Class I 

areas and will encourage the continued funding and maintenance of IMPROVE. 

Chapter 6 – Arizona Class I Area Baseline, Natural Conditions, and Uniform Rate of Progress

(4) Comment: Section 6.3, Monitoring Data. APS suggests an editorial change on page 38 in the first 

sentence. APS recommends the replacement of the word “reflect” with “scatter.” The latter term better 

represents the visibility impairment dynamic of light in the atmosphere and how it is perceived by the human 

eye. APS also recommends ADEQ replace “Figure 6.3” with “Table 6 -3” in the fourth paragraph, because 

there is no such figure include. Furthermore, since Table 6 – 2 appears on page 39 (and Table 6-3 is on page 

40), APS recommends the order of Tables 6-2 and 6-3 be reversed. 

Response: ADEQ has revised the narrative and clarified the reference to Table 6.3. 

1
Chapter 7 – Visibility Impairment at Class I areas

(5) Comment: ADEQ indicates elevated organic carbon (OC) may be due to fire. Include daily time series 

in addition to monthly time series to identify the specific dates of elevated OC and compare to Arizona fire 

activity data, because the contributions are more complicated and include anthropogenic and secondary 

natural carbon that vary seasonally and spatially. 

Response: ADEQ has included daily time series for those Class I areas with elevated OC and included 

information in Sections 7.4, 7.5, and 7.6.2 regarding fires that coincide with the elevated readings. 

Chapter 8 – Emissions Inventory

(6) Comment: Please address explicitly the assumptions used in the Western Regional Air Partnership 

(WRAP) 2018 PRP18b emissions inventory for Arizona’s BART sources and compare those modeling 

assumptions to the final emissions limits for sulfur dioxide (SO2) and nitrogen oxides (NOX) for the BART 

sources. If there are BART emissions reductions that were not included in the WRAP modeling inventory, 

these could be cited as evidence for greater than modeled visibility improvement. 

Response: ADEQ has reviewed the WRAP 2018 PRP18b emission inventory and is unable to accurately 

attribute facility emissions on a unit-specific basis. In this regard, ADEQ is unable to compare the modeling 

assumptions between WRAP’s inventory and the BART limits that are proposed at this time. 

(7) Comment: The emissions table (Table 8.1) indicates that total SO2 emissions from point sources will 

decrease by 2018; however, SO2 emissions from the two copper smelters are projected to increase 

significantly (13,273 tons) by 2018. Please discuss Arizona’s assumptions for future emissions from the 

smelters. These assumptions are critical to the source apportionment analyses in Chapter 9 that project that 

Arizona’s contribution to sulfate (SO4) will increase at several Class I areas. 

Response: ADEQ has researched the matter regarding copper smelters and has determined that the projected 

emission increase of 13,273 tons per year from the 2 smelters is erroneous. The discrepancy is a result of the 

fact that the baseline emission inventory was based on actual emissions from the 2 facilities and the 2018 

inventory considered the facility wide emission limits for the 2 smelters based on state law. The Department 

expects that the actual 2018 inventory will show a decrease in emissions from the baseline years in part 

because of potential sulfur dioxide emission control upgrades that may be necessary at the 2 facilities to 

comply with the new 1-hour S02 primary standard. 

The emissions inventories in the SIP (Chapter 8) are plan02d and PRP18b. The Particulate Matter Source 

Apportionment Technology (PSAT) results were modeled by WRAP using plan02c and base18b emissions 

inventories and WRAP did not re-model using the current inventories (plan02d and PRP18b). The base18b 

inventory shows an increase in SO2 emissions from Arizona point sources. The PRP18b inventory shows a 

decrease in SO2 from point sources in Arizona. ADEQ expects that if the PSAT model was run using the 

current inventory (PRP18b), there would be reduced contribution to SO4 from point sources. 

(8) Comment: Table 8.2 indicates that NOX emissions from point sources will not change between 2002 and 

2018. Is this consistent with ADEQ’s final BART determinations? 

Response: ADEQ does not have any information to prove that the WRAP analysis is incorrect. It should be 

noted that using the BART limits to compare against the actual emissions from 2002 does not reflect that 

2
companies will be operating below the determined BART limits and therefore the decrease in NOx could 

larger than what was projected in the PRP18b inventory. 

(9) Comment: Tables 8.3 – 8.5 indicate that natural fire is the major source category for volatile organic 

carbon (VOC), primary organic aerosols (POA), and elemental carbon (EC). Emissions of VOCs and POA 

are held constant for natural fire and biogenic sources, but are projected to increase for anthropogenic point 

and area sources and dust. Does ADEQ agree with the WRAP emissions projections for 2018 for road dust, 

fugitive dust, windblown dust, and area sources? 

Response: ADEQ agrees with the emissions projections developed by WRAP; they are representative of the 

best data and information available. Western states consented with and invested time, money, and effort into 

the technical work conducted by WRAP. ADEQ has no other information that contradicts the work 

conducted by WRAP. 

(10) Comment: It is difficult to interpret the emissions inventories because Arizona has elected to submit a 

plan under 51.308, yet the reductions anticipated in the PRP 18b inventory represent anticipated to meet 

milestone required under the original 51.309 submittal. (sic) ADEQ must reconcile the inventory differences 

between original milestone reductions under 51.309 and those that would be realized as a result of SO2

BART reductions now required under the 51.308 portion of the Regional Haze Rule. 

Response: The PRP18b emissions inventory is a projection of 2018 emissions using states’ final BART 

determinations or a state’s best estimate of BART in addition to controls that were on-the-books and on-theway by December 2008. The PRP18b was a separate effort from the emissions inventory that was conducted 

by those states participating in the original 309 program and submitting revised 309 SIPs; however, both 

emissions inventories were developed using the same source data and information. The PRP18b emissions 

inventory utilized presumptive BART for Arizona sources. See response to comment six for reconciliation 

regarding SO2 emissions inventory compared to BART. 

(11) Comment: The statewide SO2 emissions inventory does not comport with the PSAT modeling results. 

The emissions inventory shows a decrease in SO2 emissions from Arizona, yet PSAT modeling shows 

increases in SO4 at several Class I areas. 

Response: The emissions inventories in the SIP (Chapter 8) are plan02d (January 2008) and PRP18b 

(December 2008), which are the current inventories using information that was up to date at the time the 

inventory was developed. The PSAT results were modeled by WRAP using the plan02c and base18b 

emissions inventories (December 2005) and were not re-modeled using the current inventories. The base18b 

inventory showed an increase in SO2 emissions from Arizona point sources. The PRP18b inventory shows 

decreases in SO2 from point sources in Arizona. ADEQ expects that if the PSAT model was run using the 

current inventory (PRP18b), there would be reduced contribution to SO4 from point sources. 

Chapter 9 –Visibility Modeling and Source Apportionment 

(12) Comment: Please provide a brief summary of the model performance for the 2002 base year. Our 

confidence in the modeled responses to emissions changes is dependent on the model’s skill in representing 

atmospheric chemistry and transport. In general, model performance is better for SO4 and EC and less 

accurate for nitrate (NO3) and OC. 

3
Response: ADEQ has added narrative and information regarding model performance to Appendix C, Section 

2. A Web link has also been provided in Chapter 9 to the Final Report for the Western Regional Air 

Partnership (WRAP) 2002 Visibility Model Performance Evaluation, which provides detailed information 

regarding model performance. 

(13) Comment: Chapter 9 does not include a detailed discussion of the Particulate Matter Source 

Apportionment Technology (PSAT) or Weighted Emissions Potential (WEP) processes. WEP and PSAT use 

different emissions inventories, which should be clarified to aid the interpretation of visibility projections. 

Additional information regarding the methodologies should be included in this chapter. 

Response: ADEQ has a narrative and more detailed description of the PSAT and WEP processes to 

Appendix C, Section 2. 

(14) Comment: The SIP does not contain a performance evaluation of either prognostic meteorological 

model data or the base case results from the WRAP Base02d inventory used in the regional air quality 

models, CMAQ or CAMx. Without an understanding of model performance, we cannot conclude that the 

state’s model is reasonably reliable nor understand inherent model nuances that can aid in our understanding 

of the model results. 

Response: ADEQ has added a narrative and information regarding model performance to Appendix C, 

Section 2. A Web link has also been provided in Chapter 9 to the Final Report for the Western Regional Air 

Partnership (WRAP) 2002 Visibility Model Performance Evaluation, which provides detailed information 

regarding model performance. 

(15) Comment: Please briefly describe relative reduction factors and cite the technical reference or 

summarize how the factors are calculated using model results and monitoring data. 

Response: ADEQ understands this comment to refer to relative response factors. Additional information 

regarding the relative response factor has been included in Appendix C, Section 2. 

(16) Comment: Soil (fine particulate matter) is projected to increase by 2018 at every Class I area and 

organic carbon is projected to increase at Chiricahua (IMPROVE monitor represents 3 Class I areas), 

Saguaro, and Superstition. Since the natural sources are held constant, these increases are likely due to 

anthropogenic sources or influences from outside the U.S. 

Response: ADEQ agrees with the assessment that fine particulate matter (PM) is projected to increase by 

2018 at all Class I areas and organic carbon (OC) is projected to increase at the IMPROVE monitors CHIR1 

(Chiricahua NM, Chiricahua WA, and Galiuro WA), SAGU1 (Saguaro NP-East Unit), and TONT1 

(Superstition WA). The Weighted Emissions Potential (WEP) indicates these increases are due to area 

sources and sources of fugitive dust. The WEP modeling does hold natural sources constant (e.g. natural 

fire); however, the potential for OC from natural fire varies between 60% and 80% at all Class I areas in 

Arizona. ADEQ notes that WEP projections show that sources of fine PM from Mexico and New Mexico 

have a higher potential to contribute to fine PM at CHIR1 on worst visibility days than sources of fine PM 

from Arizona. 

(17) Comment: Section 9.3 discusses results of the Particulate Source Apportionment Tool (PSAT). One of 

the measures that we consider as part of reasonable progress is whether the PSAT modeling supports that 

4
Arizona’s contribution to pollutant concentrations is decreasing. PSAT indicates that the contributions of 

Arizona’s point sources to SO4 concentrations will increase by 2018 at Chiricahua, Mazatzal, Petrified 

Forest, Saguaro, Superstition, Sierra Ancha, and Sycamore. Please discuss the basis for this increase. 

Projected increases in SO2 emissions from the two copper smelters (assigned to Gila County) may explain 

the increases in SO4 concentrations at the Class I areas. 

Response: The 2018 inventory (PRP18b) is the most current inventory developed by WRAP, which 

incorporates all of the controls on-the-books or on-the-way by December 2008. The 2018 inventory does not 

take into account the new SO2 standard proposed by EPA and reductions associated with implementation and 

compliance with the new standard. The emissions inventories in the SIP (Chapter 8) are plan02d and 

PRP18b. The PSAT results were modeled by WRAP using the plan02c and base18b emissions inventory, 

which were developed in December 2005, and were not re-modeled using the current inventories. The 

base18b inventory showed an increase in SO2 emissions from Arizona point sources. The PRP18b inventory 

shows decreases in SO2 from point sources in Arizona. ADEQ expects that if the PSAT model was run using 

the current inventory (PRP18b), there would be reduced contribution to SO4 from point sources. As 

explained in the Department’s response to Comment #7, the projected emission increase from the 2 smelters 

is erroneous and that the Department expects that SO2 emissions will decrease significantly from baseline 

levels as a result of the efforts of the two facilities to comply with the new 1-hour SO2 primary standard. 

(18) Comment: In some instances (e.g., page 89-90 in the October 25, 2010 draft concerning PSAT 

modeling for Mazatzal) the narrative incorrectly refers to SO4 emissions when SO2 emissions were intended. 

Response: ADEQ has made the appropriate corrections. 

(19) Comment: PSAT modeling shows that NO3 concentrations due to NOX emissions from Arizona point 

sources will increase by 2018. Increases in SO4 and NO3 contributions from Arizona point sources are not 

consistent with ADEQ’s assertion that the state has made reasonable progress toward improving visibility in 

Class I areas in Arizona. 

Response: The emissions inventories in the SIP (Chapter 8) are plan02d and PRP18b, developed in January 

2008 and December 2008, respectively. The PSAT results were modeled by WRAP using the plan02c and 

base18b emissions inventory, which were developed in December 2005, and were not re-modeled using the 

current inventories. The base18b inventory showed an increase in SO2 and NOX emissions from Arizona 

point sources. The PRP18b inventory shows decreases in both SO2 and NOX from point sources in Arizona. 

ADEQ expects that if PSAT was run using the current inventory (PRP18b), there would be reduced 

contribution to SO4 or NO3 from point sources. ADEQ notes that visibility projections assume growth and 

new sources. Prevention of Significant Deterioration (PSD) contains a visibility component and protects 

against visibility impairment as sources are permitted. Emissions inventories and visibility projections are 

representative of the best data and modeling available. 

(20) Comment: The WEP projections indicate increases in Arizona’s contributions to fine and coarse PM 

and to organic carbon from area sources, road dust, fugitive dust, and windblown dust, which are 

anthropogenic sources. The WEP analyses do not support ADEQ’s conclusions that PM is largely due to 

natural sources and therefore does not need to be considered in the reasonable progress analysis. It is 

recommended that ADEQ consider measures to reduce anthropogenic PM in the reasonable progress 

analysis. 

Response: ADEQ addresses measures to reduce anthropogenic PM in the long-term strategy. The 

nonattainment and maintenance areas for PM10 in Arizona contain measures to control PM10 from human 

5
activities. ADEQ addressed the anthropogenic contributions in a manner it deemed most appropriate for this 

SIP submission, which is a state discretionary decision. 

(21) Comment: Section 9.4.5 (page 114 of October draft) incorrectly refers to Grand Canyon when the 

graphic and paragraph are addressing Petrified Forest. 

Response: ADEQ has changed the incorrect reference. 

Chapter 10 – Best Available Retrofit Technology (BART)

BART Exemption Criteria 

(22) Comment: During the development of the WRAP BART Modeling Protocol, the Federal Land 

Managers (FLM) recommended that the WRAP BART exemption modeling use surface and upper air 

meteorological observations as well as the MM5 meteorological model to initialize the CALMET 

meteorological model. WRAP used surface observations but did not use upper air observations. Thus the 

FLMs recommended that states should use a conservative interpretation of the CALPUFF outputs. 

Specifically, the states should use either the maximum visibility impact with the annual average natural 

condition or the 98th percentile visibility impact with the 20% best natural conditions. ADEQ is reporting 

98th percentile visibility impact with annual average natural conditions, which is not consistent with good 

modeling practices as identified by 40 CFR 51 Appendix W or EPA’s Model Clearing House memorandum. 

Use of a non-guideline modeling approach requires additional evaluation of performance and EPA Regional 

Office approval (Section 3.2, 40 CFR 51 Appendix W). 

Response: EPA specified use of the CALPUFF model for states to use in determining the “subject-toBART” status of eligible sources. Although recent evaluations of CALPUFF against atmospheric tracer data 

performed by EPA/OAQPS show that CALPUFF is the worst-performing Long Range Transport (LRT) 

model of the LRT models reviewed (Anderson and Brode, 2010), at the time the modeling was performed 

WRAP followed EPA requirement to use the model. 

Part of CALPUFF’s problems are related to the CALMET diagnostic wind model that produces unphysical 

meteorological fields. The use of upper-air observations with MM5 prognostic meteorological output in 

CALMET exacerbates this problem. This is one reason why EPA has developed the Mesoscale Model 

InterFace (MMIF) tool to directly map MM5/WRF data to CALPUFF without using CALMET and 

EPA/OAQPS intends to promote guidance using MMIF instead of CALMET. Thus, whether observed 

upper-air data are used or not should not affect the CALPUFF estimates as they would still suffer from the 

inaccuracies inherent in the modeling system. 

Reporting impacts as Arizona has chosen to do, for the purposes of determining which sources are “subjectto-BART”, is a state discretionary decision under the BART rule. 

(23) Comment: Most states have followed EPA staff guidance to interpret the 98th percentile impact as 

either the maximum 8th highest value in any single year or the 22nd highest value for three years combined, 

whichever is more conservative. ADEQ used the 8th highest value averaged over three years, which is a less 

conservative metric. Had ADEQ used the 8th highest value in a single year, Chemical Lime Nelson Plant 

would not have been exempted from BART. We request that ADEQ re-evaluate the BART determination 

and use the more rigorous criteria. 

6
Response: The initial modeling analysis to assess BART applicability for CLC was conducted using 

potential to emit (PTE), as this was the information that was readily available. In its submittal, the company 

utilized actual emission rates based on historical stack test data. The company’s modeling analysis, using 

actual emissions data, followed the modeling protocols that were uniformly applied to all Arizona sources 

and documented that the visibility impairment resulting from the facility is below the threshold of 0.5 dv. 

ADEQ has determined that it is not necessary to revisit the analysis.

(24) Comment: In the modeling to determine if a source is subject to BART, all emissions that are above 

the de minimis level should be included, even if those emissions are less than 250 tons. 

Response: The BART regulations in 40 CFR Part 51 do not establish these criteria. As specified in 40 CFR 

Part 51 Appendix Y Section I.F, the BART guidance codified in the Appendix is intended to serve as 

guidance for fossil-fuel fired plants with a capacity in excess of 750 MW. The guidance discusses how states 

may not establish de minimis levels lower than the applicable PSD significant thresholds. ADEQ’s position 

is that the guideline applies exclusively to the fossil fuel plants referenced above. In that regard, the 

Department has determined that there is no established regulatory de minimis threshold other than 250 tons 

per year for sources that do not belong to the fossil fuel category and consequently, has processed BART 

modeling documents and BART proposals consistent with that determination. 

(25) Comment: The Forest Service concurs with comments provided by the Department of Interior on 

Arizona’s BART exclusion process. Specifically, the WRAP developed CALMET meteorological fields 

using a nonstandard method that did not require the incorporation of upper atmospheric data. Additionally, 

previous EPA testing of CALPUFF Version 6.112, utilized by WRAP for its initial CALPUFF modeling, 

indicated several issues with default technical options that could bias model estimates low. The FLMs have 

typically only agreed to such an approach for CALPUFF modeling if the states use either the maximum 

visibility impact with the annual average natural condition or the 98th percentile impact with 20% best natural 

condition. In this SIP, Arizona has used the 98th percentile impact with the annual average natural condition. 

We require that sources that were determined to not be subject-to-BART be re-evaluated using the more 

rigorous criteria using the approach described above. 

Response: See response to comment 22. 

Ammonia Modeling Assumptions 

(26) Comment: The FLMs (NPS) reviewed the BART modeling reports submitted by the three electric 

utilities. We do not agree with the assumptions used for ammonia by AECOM for Salt River Project’s 

Coronado Generating Station and by CH2MHill for Arizona Public Service’s Cholla Generating Station. 

Both analyses use very low winter values for ammonia based on early monitoring in the region. More recent 

ammonia monitoring indicates higher ammonia values commonly occur in the region. We support the 

ammonia values of 1 ppm recommended in the WRAP BART Modeling Protocol and used by CH2MHill for 

Arizona Electric Power Cooperative’s Apache Generating Station. We recommend that the same levels be 

used for Comanche and Cholla Generating Stations. 

Response: ADEQ is not aware of any recent ammonia monitoring conducted in the area around either 

Coronado or Cholla Generating Stations that would support higher background ammonia inputs. In addition, 

NPS has not provided any specific details regarding any such monitoring as part of their comments. In the 

absence of such information, ADEQ has determined that the modeling assumptions that were made by the 

sources are appropriate.

7
BART Costs and Benefit Analyses 

(27) Comment: The FLMS and NPS have developed a national data base of costs and effectiveness of 

control technology installations. As documented in our General BART Comments, based on national 

experience, it appears that ADEQ and the companies have underestimated the efficiency of Selective 

Catalytic Reduction (SCR) to reduce NOx emissions and have overestimated the costs of SCR installation 

and operation. Although there are several methods for estimating SCR costs, our experience leads us to 

believe that no one method is perfect and that the costing methods need to be tempered by real-world data. 

Both OAQPS and EPA Region 8 have advised against the use of CUECost. Instead, the BART Guidelines 

recommend use of the OAQPS Control Cost Manual. We believe it is not appropriate to use the CUECost 

model, nor is it appropriate to escalate costs into the future and compare them against current cost thresholds. 

Response: ADEQ has determined that the cost computations presented by the facilities in support of their 

BART applications are reasonable. Many of the computations are based on vendor data and site-specific 

conditions. The Department does not agree that the computations over-estimate the costs of retrofit 

technologies and under-estimate the associated emission decreases and visibility improvement. 

(28) Comment: Please clarify how the costs were factored into the BART determinations. At the public 

stakeholder meeting on October 19, ADEQ indicated that a threshold of $1500 to $2000 per ton was used in 

the BART determinations. However, the BART Technical Support Document indicates that ADEQ selected 

the least cost control option (low NOx burners, existing PM and SO2 controls) even when more effective 

controls were identified in the $1500-2000 range. 

Response: The BART regulations codified under 40 CFR 51 Appendix Y reference the dollar per ton ($/ton) 

metric and specify its use in the BART evaluation process. ADEQ used both the dollar per deciview ($/dv) 

and $/ton metrics in its BART analyses. Using the $/ton metric solely would render the analysis to be a 

technology determination process like what is involved in the PSD/BACT determination. Since the goal of 

the regional haze program is to identify cost-effective technology solutions to address visibility degradation, 

the Department considers the $/dv metric to be an important step in the decision-making process. It should 

be noted that the Department does not use a “bright-line” threshold while evaluating $/ton or $/dv values. 

It should also be noted that BART determinations were based on all BART factors specified in 40 CFR Part 

51 taken together, not just costs

(29) Comment: ADEQ presents the visibility benefit in $/dv for only the Class I area with the maximum 

impact. If the cumulative benefits of controls were considered for all the Class I areas within 300 km of a 

source, the $/dv benefit would be much greater than reported. The BART Guidelines represent an attempt to 

create a workable approach to estimating visibility impairment. As such, they require several assumptions, 

simplifications, and shortcuts about when visibility is impaired in a Class I area, and how much impairment 

is occurring. The Guidelines do not attempt to address the geographic extent of the impairment, but assume 

that all Class I areas are created equal, and that there is no difference between widespread impacts in a large 

Class I area and isolated impacts in a small Class I area. To address the problem of geographic extent, we 

have been looking at the cumulative impacts of a source on all Class I areas affected, as well as the 

cumulative benefits from reducing emissions. While there are certainly more sophisticated approaches to 

this problem, we believe that this is the most practical, especially when considering the modeling techniques 

and information available. Please report the benefits of controls at all Class I areas, not just the benefit at the 

Class I area with maximum impact. (Comment received from FLMs and NPS.)

Response: ADEQ did not compute or consider cumulative dollar per deciview values in its evaluation. 

Maximum visibility impacts from a facility could be at different locations, under different meteorological 

8
conditions, and at different times within multiple Class I areas; adding up visibility improvements across the 

board would result in an erroneous depiction of the visibility improvement that can be expected. 

(30) Comment: Please provide a summary of the BART controls and expected emission reductions in 

Chapter 10 in addition to Appendix D. 

Response: Chapter 10 includes information regarding the BART process and the results of that process. 

ADEQ has made direct references to the summary provided in the introduction of the BART documentation 

allowing direct access to the more detailed analyses for each facility that directly follows. 

 

BART Recommendations 

Arizona Electric Power Cooperative (AEPCO) – Apache Generating Station Units 2 and 3

(31) Comment: For NOX, the FLMs and NPS recommend SCR for Apache Units 2 and 3 rather than Low 

NOX Burners with Over Fired Air as proposed by ADEQ. Our cost estimate for SCR is $1,500 - $1,700 per 

ton based on an annual average NOX emissions rate of 0.05 lb/mmBtu. 

Response: ADEQ respectfully disagrees with the recommended BART strategy. ADEQ conducted its 7-step 

BART analysis incorporating the 5-step process referenced in 40 CFR Part 51, using the best available 

information. As mentioned in the Department’s responses to other comments, the agency’s position is that 

dollar per ton cannot be considered as the sole metric in a BART evaluation. The BART process is not an 

emission reduction technology evaluation but is a program designed to address regional haze and therefore 

must also consider the costs relative to the expected visibility improvement. ADEQ is retaining its BART 

decision. 

(32) Comment: For SO2, the FLMs and NPS recommend that ADEQ require the existing scrubbers to 

achieve at least 90% SO2 removal with an annual average SO2 emissions limit not to exceed 0.12 lb/mmBtu. 

The FLMs and NPS concur with ADEQ’s BART determination for PM. 

Response: ADEQ acknowledges the comment for the PM BART, but respectfully disagrees with the 

recommended BART strategy for SO2. ADEQ conducted its 7-step BART analysis incorporating the 5-step 

process referenced in 40 CFR Part 51, using the best available information and is retaining its BART 

decision. Additionally, the Department has determined that the emission limits are appropriate in the pounds 

per million Btu form. The emission rates used in the visibility modeling correspond to specific pound per 

million Btu values and those values have been determined to be the BART limit, and will ensure that the 

modeling assumptions are truly enforceable. 

Arizona Public Service Cholla Units 2, 3, and 4

(33) Comment: For NOX, the FLMs and NPS recommend SCR for Cholla Units 2, 3, and 4 rather than Low 

NOX Burners with Separated Over Fired Air as proposed by ADEQ. Our cost estimate for SCR is $1,700 - 

$1,900 per ton based on an annual average NOX emissions rate of 0.05 lb/mmBtu. 

Response: ADEQ respectfully disagrees with the recommended BART strategy. The Department conducted 

its 7-step BART analysis incorporating the 5-step process referenced in 40 CFR Part 51, using the best 

available information. As mentioned in the Department’s responses to other comments, the agency’s 

position is that dollar per ton cannot be considered as the sole metric in a BART evaluation. The BART 

9
process is not an emission reduction technology evaluation but is a program designed to address regional 

haze and therefore must also consider the costs relative to the expected visibility improvement. 

(34) Comment: For SO2, the FLMs and NPS recommend that ADEQ require the existing scrubbers to 

achieve at least 90% SO2 removal with an annual average SO2 emissions limit not to exceed 0.12 lb/mmBtu. 

The FLMs and NPS concur with ADEQ’s BART determination for PM. 

Response: ADEQ acknowledges the comment for PM BART. The Department respectfully disagrees with 

the recommended BART strategy for sulfur dioxide. The Department conducted its BART analysis based on 

the 5-step process referenced in 40 CFR Part 51 using best available information. The Department is 

retaining its BART decision. Additionally, the Department has determined that the emission limits are 

appropriate in the pounds per million Btu form. The emission rates used in the visibility modeling 

correspond to specific pound per million Btu values and those values have been determined to be the BART 

limit, and will ensure that the modeling assumptions are truly enforceable. 

Salt River Project (SRP) Coronado Generating Station (CGS) Units 1 and 2

(35) Comment: The ammonia assumptions used to model visibility impacts are unacceptably low and 

therefore the visibility benefits of emissions controls were underestimated. The visibility modeling needs to 

be redone. 

Response: See response to comment 26. 

(36) Comment: For NOX, FLMs and NPS concur with ADEQ’s estimated $1,021/ton for combustion 

controls plus SCR. It is likely the corrected visibility benefits would support SCR as BART. 

Response: ADEQ respectfully disagrees with the recommended BART strategy. The Department conducted 

its 7-step BART analysis incorporating the 5-step process referenced in 40 CFR Part 51, using the best 

available information. The BART process is not an emission reduction technology evaluation but is a 

program designed to address regional haze and therefore must also consider the costs relative to the expected 

visibility improvement. ADEQ has determined the visibility modeling was done appropriately and is 

retaining its BART decision. 

(37) Comment: For SO2, the FLMs and NPS concur with Wet Flue Gas Desulfurization for both units with 

an associated SO2 emission rate of 0.08 lbs/MMBtu on 30-day rolling average basis. 

Response: ADEQ acknowledges the comment. 

(38) Comment: For PM, ADEQ’s conclusion that the proposed 0.03 lb/mmBtu BART limit “is already 

meeting or exceeding the stringency of the emissions limitation” and “for similar emissions units with similar 

emissions controls” is not consistent with its Cholla BART analysis which concluded that replacement of the 

existing hot-side ESP with fabric filters at 0.015 lb/mmBtu is BART. The FLMs and NPS recommend the 

BART determination for Coronado be re-evaluated. 

Response: PM emissions from both units are currently controlled with hot-side ESPs. Salt River Project 

(SRP) proposed a filterable PM/PM10 BART limit of 0.03 lb/MMBtu, achieved using ESP, as BART for 

CGS. This proposal was based on a Prevention of Significant Deterioration Best Available Control 

10
Technology analysis that was performed for Unit 2 at CGS as part of the significant revision application that 

was submitted in 2008. The analysis demonstrated that the replacement of the existing ESP with a new 

fabric filter baghouse was not cost effective. 

Since the use of ESPs was determined to be BACT for Unit 2 at CGS as part of a recent PSD permitting 

process, this technology and the associated BACT limit of 0.03 lb/MMBtu for filterable PM/PM10 constitutes 

BART for both units at CGS. ADEQ notes this finding is consistent with EPA BART guidance in 40 CFR 

Part 51, Appendix Y. 

Catalyst Paper (Snowflake) Inc. (CPSI) (formerly Abitibi)

(39) Comment: The NOX emissions rate evaluated for control measures and proposed by ADEQ as BART 

is twice as high as the uncontrolled NOX emissions rate reported by CPSI and used in the cost estimates. The 

costs of control are overestimated by using a higher interest rate and shorter remaining useful life than 

recommended by the EPA Control Cost Manual. The visibility benefits to multiple Class I areas have not 

been included. The BART analysis for NOX is unacceptable and needs to be redone. The BART analysis for 

SO2 is flawed with unsupported costs and underestimated benefits. The BART analysis for SO2 is 

unacceptable and needs to be redone. 

Response: ADEQ is revisiting the analysis conducted by CPSI and will respond to the above comment in a 

subsequent addendum to this plan submittal. Based on the threshold visibility impact from the facility, the 

revised analysis may not change the BART outcome for the facility. 

Arizona Public Service (APS) West Phoenix

(40) Comment: Please provide the revised air dispersion modeling analysis that was submitted on October 

7, 2007 and was the basis for exempting the source from BART. 

Response: The documents were posted to ADEQ’s Web site on January 6, 2011 at the following location: 

http://www.azdeq.gov/environ/air/haze/download/apswp1.pdf

Arizona Portland Cement Company

(41) Comment: Until the retirement of Kiln #4 is made federally enforceable, it will remain BART-eligible. 

We disagree with the exemption of the source because the exemption criteria were incorrectly applied. We 

request the visibility impacts be evaluated against the correct exemption criteria.

Response: ADEQ disagrees. The exemption criteria were correctly applied. Kiln 4 was determined to be 

BART-eligible, but not subject-to-BART. The visibility impacts evaluation was made following appropriate 

protocols that were uniformly applied to all Arizona sources. The Department’s determination is that APCC 

facility is not subject-to-BART based on the visibility impacts from the facility’s operation being below the 

threshold of 0.5 dv.

Chemical Lime Company – Nelson Lime Plant

(42) Comment: Please provide the September 21, 2007, letter from Chemical Lime Company (CLC) to 

ADEQ and the new modeling analysis by CLC. It appears that CLC did not include the 154 tpy of PM 

emissions modeled by WRAP in the company’s modeling. All emissions, not just those greater than 250 

11
tons need to be included in the modeling to determine if a source is subject to BART. The exemption criteria 

were incorrectly applied; please apply corrected as discussed above. The FLMs and NPS conclude that the 

Chemical Lime Company – Nelson Lime Plant is subject to BART. 

Response: The documents were posted to ADEQ’s Web site on January 6, 2011 at the following location: 

http://www.azdeq.gov/environ/air/haze/download/clcnelson1.pdf 

(43) Comment: It appears that CLC did not include the 154 tpy of PM emissions modeled by WRAP into the 

company’s modeling. All emissions, not just those greater than 250 tons, need to be included in the 

modeling to determine if a source is subject to BART. The exemption criteria were incorrectly applied; 

please apply corrected as discussed above. We conclude that the Chemical Lime Company – Nelson Lime 

Plant is subject to BART. 

Response: CLC did account for particulate matter in its modeling to document that its BART-eligible units 

do not contribute to visibility impairment above the threshold of 0.5 dv. The 154 tons per year referenced in 

the comment was information submitted to WRAP by ADEQ for the initial modeling of the facility. The 

company used PM emission rates based on source-test data. The revised dispersion modeling was conducted 

in accordance with the modeling protocols that were uniformly applied to all Arizona sources. 

Tucson Electric Power (TEP) – Irvington Generating Station

(44) Comment: The clear intent of EPA's BART Guidelines is to exempt a source that has gone through 

New Source Review (NSR) from a second review under BART. Because TEP Irvington Unit I4 did not go 

through NSR, the exemption does not apply. Our interpretation is that Unit I4 needs to be evaluated under 

BART. 

Response: Neither EPA rules in 40 CFR Part 51 nor BART guidance documents require a source to have 

gone through NSR to be exempt from BART eligibility. ADEQ’s determination is that Unit I4 was 

reconstructed after August 7, 1977, and therefore is not “BART-eligible”. 

ASARCO Hayden Smelter

(45) Comment: The FLMs and NPS agree with ADEQ’s conclusion that the installation and operation of 

the double contact acid plant with the New Source Performance Standard of 650 ppm constitutes BART for 

SO2. The FLMs and NPS disagree with exempting the PM10 emissions from BART; in the BART guidelines 

the PM10 level for exemption is 15 tons per year (tpy), not 250 tpy. 

Response: ADEQ acknowledges the comment about SO2 BART. With regard to the comment about PM 

emissions, please refer to ADEQ’s response to comment 24. 

Freeport-McMoRan Miami Smelter

(46) Comment: The FLMs and NPS agree with ADEQ’s conclusion that the installation and operation of 

the double contact acid plant with the New Source Performance Standard of 650 ppm constitutes BART for 

SO2. The FLMs and NPS also agree that the NESHAP for Primary Copper Smelting constitutes BART for 

PM. 

Response: ADEQ acknowledges the comment. 

12
General Comments Regarding the Steps in ADEQ’s BART Analysis 

(47) Comment: ADEQ has assumed that 24-hour and 30-day rolling average SCR emissions would be the 

same as the corresponding annual average emission rate. However, the FLMs and NPS looked at monthly 

data for 28 EGUs with SCRs operating at or below 0.05 lb/mmBtu on an annual average (see Appendix 2009 

monthly emissions) and found that, of the 228 months of data, 214 were at or below 0.06 lb/mmBtu. For 

tangentially-fired EGUs, we found that 84 of 89 were at or below 0.06 lb/mmBtu. The FLMs and NPS 

conclude that SCR can achieve 0.05 lb/mmBtu on an annual basis and 0.06 lb/mmBtu on a 30-day rolling 

average basis. 

Response: ADEQ’s BART evaluations were based on site-specific information provided by the applicants. 

It is the Department’s understanding that such information was based partially on feedback received from 

vendors and plant personnel who are intimately familiar with the specific equipment that is being considered. 

In that regard, the Department based its BART computations on the emission rates proposed by the applicant 

for the different control technology options. 

(48) Comment: ADEQ has stated that SNCR and SCR installation could impact the salability and disposal 

of fly ash due to ammonia levels. Other environmental impacts involve the potential public and employee 

safety hazard associated with the storage of ammonia, especially anhydrous ammonia, and the transportation 

of the ammonia to the power plant site. The FLMS and NPS disagree with this statement. According to the 

Institute for Clean Air Companies, ammonia can be handled safely. FLMs and NPS discussions with SNCR 

vendors indicate that the concern about ash salability is likely unfounded. 

Response: ADEQ agrees that ammonia can be transported safely but acknowledges there is added risk in its 

transport and handling. Based on the comment regarding the fly ash salability, the Department is revisiting 

this issue for Catalyst Paper which is the only Arizona facility that made the claim.

General BART Comments 

(49) Comment: For NOX on AEPCO’s ST2 and ST3, ADEQ has determined that BART is the new lowNOX burners (LNB) with overfire air (OFA) system with a NOx emission limit of 0.31 lb/MMBtu for both 

ST2 and ST3. AEPCO would like to clarify that new LNBs would be installed, but the fully functional, 

existing OFA would be utilized. 

Response: ADEQ appreciates AEPCO’s clarification and has made the appropriate changes to the BART 

TSD. 

(50) Comment: In response to a concern brought to our attention by ADEQ, AEPCO offers the following 

explanation: the AEPCO ST1 PM10 emission limit 0.0015 lb/MMBtu listed for fuel oil combustion 

anticipated the installation of LNB. The PM10 emission limit of 0.0076 lb/MMBtu listed for pipeline natural 

gas (PNG) combustion assumes good combustion practices without LNB. 

Response: ADEQ acknowledges the comment. Based on subsequent communication with AEPCO 

personnel, ADEQ is eliminating fuel oil as a fuel choice for Steam Turbine 1 and will limit the fuel to natural 

gas. 

(51) Comment: For NOX on AEPCO’s ST1, ADEQ has determined that BART is the installation of LNB 

with flue gas recirculation with an emissions limit of 0.056 lb/MMBtu. Since the normal operation of this 

13
unit is combined cycle with gas turbine 1 (GT1), AEPCO would like to propose combustion with PNG only, 

in combined cycle operation with all exhaust gas from GT1 recirculated into ST1 (the combined cycle 

operating configuration represents FGR), and installation of LNB as BART. 

Response: ADEQ acknowledges the comment. Based on subsequent communication with AEPCO 

personnel, ADEQ is eliminating fuel oil as a fuel choice for Steam Turbine 1 and will limit the fuel to natural 

gas. 

(52) Comment: APS supports the conclusions made in the proposed SIP and believes that all of the 

requirements of 40 CFR 51.308 have been satisfied. 

Response: ADEQ acknowledges the comment. 

(53) Comment: Train v. Natural Resources Defense Council, 421 U.S. 60(1975) and court decisions in the 

35 years following have consistently upheld the fundamental premise that EPA may not tell the states what 

specific controls to include in their SIPs; this a function reserved exclusively to the states. 

Response: ADEQ acknowledges the comment. 

(54) Comment: ADEQ’s BART determination for Cholla is consistent wit the Clean Air Act and the BART 

rules. EPA cannot substitute its BART preferences for Cholla in lieu of ADEQ’s determination. Under the 

CAA, the states have primary responsibility for assuring air quality within their boundaries. The CAA and 

the BART rules similarly assign to the states the responsibility for making BART determinations. EPA 

cannot overrule ADEQ’s determination for Cholla and substitute its own conclusion. 

Response: ADEQ acknowledges the comment. 

(55) Comment: APS agrees with ADEQ’s determination that the Combined Cycle Units CC1, CC2, and 

CC3 at the West Phoenix Generating Station are not subject to BART. ADEQ informed APS on June 13, 

2007, that CC1, CC2, and CC3 were potentially subject to BART for NOX. APS reviewed ADEQ’s letter 

and recognized that the information used in determining BART eligibility for West Phoenix was flawed and 

not updated. On September 30, 2007, APS submitted a letter to ADEQ detailing the flawed assumptions and 

errors set forth in the June 13, 2007 letter. APS committed to fix the errors and resubmit an air dispersion 

modeling analysis with the adjusted values. Results from the modeling analysis using the corrected values 

were submitted to ADEQ on October 7, 2007. ADEQ agreed with the revised visibility analysis and 

concluded that, because the deciview impact on the nearest Class I areas was less than 0.5 dv, West Phoenix, 

CC1, CC2, and CC3 Units did not cause or contribute to impairment of visibility at a Class I area. APS fully 

supports ADEQ’s final assessment of the visibility impacts and concurs that these units are not subject to 

BART. 

Response: ADEQ acknowledges the comment. 

(56) Comment: APS supports ADEQ’s BART determinations for SO2, NOX, and PM on Cholla Units 2, 3, 

and 4. It is important to note that visibility improvements resulting from all NOX control scenarios are less 

than 0.5 dv. The difference between the application of NOX combustion controls (LNB and SOFA) and the 

application of Selective Catalytic Reduction (SCR) technology is a visibility improvement of only 0.2 dv. 

The cost of SCR is eight to ten times the cost of LNB and SOFA – for a 0.2 dv improvement. APS agrees 

that the added cost of retrofitting Cholla Steam Units 2, 3, and 4 with SCR, for a 0.2 dv improvement, is not 

14
justified. Therefore, APS agrees with ADEQ’s decision to establish NOX BART for Cholla Steam Unit 2, 3, 

and 4 as LNB and SOFA. 

Response: ADEQ acknowledges the comment. 

(57) Comment: ADEQ should recognize current discussions involving changes to the CALPUFF model that 

ADEQ used to assess the visibility impacts of its proposed BART determination. Recent developments 

shows that the version of CALPUFF used by ADEQ in its SIP process (Version 5.8) over-predicts the 

contribution of nitrate formation in colder months and the newer version of the model (Version 6.4) corrects 

this issue. 

Response: ADEQ acknowledges APS’s input regarding the matter. In light of the determination that the 

CALPUFF version used in the modeling analysis over-predicts nitrate formation and consequently likely 

overstates the associated visibility degradation, the Department is taking the conservative position of using 

the prior modeling results. 

(58) Comment: SRP agrees with ADEQ’s proposed BART emission limits for CGS. In addition, SRP 

supports the approach taken by ADEQ in developing the BART emissions limits proposed in the SIP for 

stationary sources. In the case of nitrogen oxide emissions from CGS, this approach recognizes that a BART 

emission limit that requires the implementation of Selective Catalytic Reduction (SCR) cannot be justified 

due to the significantly higher cost of this technology and the small visibility improvements that is expected 

to be achieved. In addition, ADEQ properly recognizes that the “reasonable progress” provisions of the 

Federal Regional Haze Rule will allow additional opportunities to evaluate whether still more NOX emissions 

reductions are needed in future periods to meet the long-term program goals. 

Response: ADEQ acknowledges the comment. 

(59) Comment: SRP strongly encourages ADEQ to reject any comment received during this comment 

period that advocates for the installation of the most stringent control available as BART without an 

appropriate technical and/or regulatory basis. As noted in the Federal Regional Haze Rule, states have broad 

discretion in establishing BART for stationary sources using an approach that the state deems to be most 

appropriate. Under the Clean Air Act, states are given the primary responsibility for assuring air quality 

within their boundaries (42 U.S.C. 7407(a)). Similarly, the Clean Air Act and BART rules assign to the 

states the responsibility for making BART determinations and “designing and implementing regional haze 

programs.” EPA acknowledged the states’ roles when it promulgated the BART rules: “Congress evinced a 

special concern when ensuring that states would be the decision makers” with respect to “which sources are 

subject to BART” or “how States make BART determinations.” EPA also conceded that it cannot prescribe 

“specific control measures a state must implement in its initial SIP for regional haze. That determination can 

only be made by a state once it has conducted the necessary technical analysis of emission, air quality, and 

the other factors that go into determining BART.” In light of this clear guidance, and because ADEQ’s 

proposed Regional Haze SIP is consistent with the BART rules, ADEQ should reject any suggestions of an 

alternate BART determination for CGS. 

Response: ADEQ acknowledges the comment. 

(60) Comment: SRP notes that the version of CALPUFF that was used to evaluate visibility improvement 

attributable to BART has been updated. SRP agrees with the assessment made by other sources that the 

updated model provides for more accurate treatment of nitrate chemistry. SRP encourages ADEQ to adopt 

15
and use the most up-to-date version of the CALPUFF model in future modeling conducted to support 

regional haze planning. It is critical for states, as well as EPA and the Federal Land Managers, to make 

planning decisions using those tools demonstrated to provide the most accurate information. It is clear that 

CALPUFF model development has advanced, and it is logical to expect additional enhancements as modelers 

continue to apply the model in various applications. It is important for ADEQ to follow such modeling 

advancements and adopt those changes that enhance the quality of SIP development efforts. 

Response: ADEQ acknowledges SRP’s input regarding the matter. In light of the determination that the 

CALPUFF version used in the modeling analysis over-predicts nitrate formation and consequently likely 

overstates the associated visibility degradation, the Department is taking the conservative position of using 

the prior modeling results. 

(61) Comment: SRP would like to propose to revise what appears to be a typographical error in the 

proposed SIP. In Section XIV of Appendix D, Table 3, baseline NOX emissions from both Units 1 and 2 at 

CGS are listed as 0.433 lb/MMBtu. Baseline NOX emissions from Unit 2 should be 0.466 lb/MMBtu. SRP 

believes that the modeling results presented in the appendix are based on the correct baseline emission rate of 

0.466 lb/MMBtu from Unit 2, and that the reference to 0.433 lb/MMBtu is simply a typographical error. 

Response: ADEQ has made the appropriate corrections. 

(62) Comment: So long as all five BART factors are considered, the Regional Haze Rule allows Arizona to 

compare tradeoffs between the benefits and costs associated with various control technology alternatives in 

setting BART requirements, and gives Arizona “great leeway to make the BART determinations required by 

the Clean Air Act.” Am. Corn Growers Ass’n v. EPA, 2901 F.3d 1, 21 (D.C. Cir. 2002). 

Response: ADEQ acknowledges the comment. 

(63) Comment: Some of the controls that Arizona proposes to require as BART do not represent costeffective control options. Arizona should clarify that the $160,747 per ton cost for the fabric filter at Cholla 

Generating Station does not represent a cost-effective BART control option, since it would be unreasonable 

to impose such a high cost on sources that have not already decided to install the controls for other reasons. 

As an alternative, Arizona could consider planned controls as part of the baseline for considering other 

control options, given that the controls will be installed regardless of the outcome of the BART analysis. 

Arizona could also simply omit the cost-effectiveness calculation altogether where the source does not seek 

to rule out a control option on the basis of cost-effectiveness, similar to the approach taken for controls that 

have already been installed (e.g., the scrubbers at the Cholla Generating Station). 

Response: ADEQ agrees with the comment. Language has been added to the technical support document to 

clarify that the $160,747 per ton value would not be considered a cost-effective number in a BART 

evaluation. 

(64) Comment: Peabody supports Arizona’s proposed Long Term Strategy in that it provides an appropriate 

means for developing additional information that will help the state determine whether additional controls 

may be imposed on non-BART eligible sources. Even though the availability of additional controls, and the 

benefits associated with those controls, cannot be determined at this time, Arizona’s commitment to 

researching additional control opportunities will help ensure that Arizona not only meets but exceeds its 

established RPGs. As noted in the proposed Regional Haze SIP, additional control alternatives that Arizona 

expects to identify in the next few years will help achieve even greater emission reductions and greater 

visibility improvements than currently expected. Such a holistic review of the potential control options fully 

16
complies with the requirement to develop state-wide strategies to address regional haze and update the SIP as 

needed to ensure all reasonable control options are considered and implemented as appropriate. 

Response: ADEQ acknowledges the comment. 

(65) Comment: BART determinations should identify the compliance methods or the averaging times for 

proposed control limits. EPA recommends the use of continuous emissions monitors for NOX and SO2, and 

no longer than a 30-day rolling average for an emission limit. 

Response: ADEQ agrees with the comment and language has been added regarding the compliance and 

averaging methods. 

(66) Comment: To determine the feasibility of emission controls, the analysis must rely on dollars per ton 

($/ton) as the primary metric for a BART determination. Dollars per deciview ($/dv) may be used as a 

supplementary metric; however, the $/dv metric should be applied to visibility improvement in all Class I 

areas within a 300 km radius of the source. 

Response: The BART regulations codified under 40 CFR 51 Appendix Y reference the dollar per ton ($/ton) 

metric in the BART evaluation process. ADEQ used both the dollar per deciview ($/dv) and $/ton metrics in 

its BART analyses. In addition, the Department also gave consideration to the threshold visibility impact 

from the emission units with current controls and the incremental deciview impact from retrofitting with 

other controls. Using the $/ton metric solely would render the analysis to be a technology determination 

process like what is involved in the PSD/BACT determination. Since the goal of the regional haze program 

is to identify cost-effective technology solutions to address visibility degradation, the Department considers 

the $/dv metric to be an important step in the decision-making process. ADEQ did not compute or consider 

cumulative dollar per deciview values in its evaluation. Maximum visibility impacts from a facility could be 

at different locations, under different meteorological conditions, and at different times within multiple Class I 

areas; adding up visibility improvements across the board would result in an erroneous depiction of the 

visibility improvement that can be expected. 

(67) Comment: The analysis must clearly state how each factor is weighted in arriving at the conclusion on 

BART. For example, both $/ton and $/dv appear reasonable for the most stringent control at AEPCO (Units 

2 and 3) and at APS Cholla (Units 2, 3, and 4), but lesser controls were selected as BART. 

Response: ADEQ disagrees with the premise that the relative weights of the different factors being 

considered need to be justified to substantiate the BART technology and associated emission limit that is 

being chosen. As stated in the Department’s response to comment 67, the Department’s 7-step process 

incorporated the EPA recommended 5-factors and evaluated figures for dollar per ton, dollar per deciview, 

and incremental visibility improvement to make its BART determinations. The Department did not apply 

any pre-determined weighting for these factors. The general concept driving the decision-making process 

was to identify cost-effective control strategies that would meaningfully contribute to visibility improvement 

at the Class I areas. 

For AEPCO Units 2 and 3 and APS Cholla Units 2, 3, and 4, the Department evaluated all BART factors and 

determined that low-NOX burners with over-fired air constitute BART. ADEQ did not solely rely on $/ton 

and $/dv, but considered all of the factors together. It should be noted that the determination of whether or 

not a cost metric is reasonable is a discretionary state decision and will likely vary from state to state. 

17
(68) Comment: In analyzing sources that burn various coal types with different levels of SO2, an efficiency 

limit is a more effective control. EPA suggests ADEQ provide an efficiency limit. 

Response: ADEQ has determined that the emission limits are appropriate in the pounds per million Btu 

form. The emission rates used in the visibility modeling correspond to specific pound per million Btu values 

and those values have been determined to be the BART limit, and they will ensure that the modeling 

assumptions are truly enforceable. 

(69) Comment: The analysis of the two smelters should clarify the fugitive emissions numbers, fugitive 

emission control techniques, and the basis for the SO2 BART decision. 

Response: ADEQ has provided a brief discussion about the emission capture techniques at the two smelters 

below: 

ASARCO 

ASARCO Hayden smelter operates the following control technologies on the equipment subject-to-BART: 

Emissions Units Subject-to-BART Current Control 

Flash furnace, converter process gases Primary capture system, double contact acid plant 

Captured fugitive emissions (converter 

secondary hood, flash furnace, slag tapping & 

matte tapping hoods) and dryers 

Secondary capture system, baghouse 

ASARCO has implemented a number of changes to the company’s process and control equipment over time. 

Prior to 1971, all smelting operation process gases from the facility were emitted into the atmosphere after 

electrostatic precipitators removed the particulate matter from the gases. In 1971, ASARCO installed an acid 

plant as an SO2 control for primary converter gases to reduce SO2 emissions from the facility. In 1983, 

ASARCO replaced twelve multiple-hearth roasters and two reverberatory furnaces with an INCO Flash 

smelting furnace. At the same time, ASARCO installed a 650 ton per day oxygen plant that would enrich the 

smelting process gases. Based upon this addition, the company was able to replace the existing single 

contact acid plant with a new double-contact acid plant. The emissions reductions resulting from these 

projects were estimated to be 63,584 tons per year of SO2. According to ASARCO’s calculations, the 

double-absorption acid plant recovers 99.81 percent of the SO2 emissions that are vented to it. In 1992, 

ASARCO made a modification to the smelter’s existing gas handling system, and installed a wet gas 

handling system. This modification decreased the flash furnace off gas temperature by 400° F. Due to the 

lower temperatures, the volume of gas being vented from the flash furnace was reduced, enabling the 

converters to vent additional gases to the acid plant. This additional ventilation allowed the secondary hoods 

to capture more SO2 emissions from the converter building. In 1999/2000, ASARCO redesigned the 

converter primary hood doors and installed flexible seals to minimize the escape of fugitive emissions to the 

secondary hooding system. 

SO2 emissions based on 2006 permit renewal application are as below: 

Emission unit/activity SO2 Emissions, tpy 

Main stack (Flash furnace, converter primary, Acid Plant) 397 

Annulus stack (Converter secondary hood, flash furnace, slag 

tapping & matte tapping hoods, and dryers) 15,164 

18
Emission unit/activity SO2 Emissions, tpy 

Flash furnace fugitives 1,078 

Converter fugitives 2,257 

In anticipation of the new 1-hour SO2 primary National Ambient Air Quality Standards (NAAQS), the 

company continues to evaluate additional SO2 capture and control options. 

FMMI 

Current Air Pollution Control Equipment for Equipment subject-to-BART at the FMMI Smelter is listed in 

the table below: 

Emissions Units 

Subject-to-BART Current Control 

Electric Furnace (Process Gases) Acid plant tail gas system 

Electric Furnace (Captured Fugitive Emissions) Wet scrubber and wet electrostatic precipitator

Hoboken Converters (Process Gases) Acid plant tail gas system 

Hoboken Converters (Fugitive Emissions) Copper converter capture system 

Remelt/Mold Pouring Vessel (similar to Anode Vessel) Natural gas and steam injection 

The FMMI smelter is a major source of Hazardous Air Pollutants (HAPs), and is therefore subject to the 

requirements of 40 CFR 63 Subpart QQQ, National Emissions Standards for Hazardous Air Pollutants 

(NESHAP) for Primary Copper Smelting. The NESHAP identifies several operating and maintenance 

practices that will have the effect of optimal capture of emissions released and as applicable, optimal 

performance of control technologies to minimize emissions released to the atmosphere. In anticipation of the 

new 1-hour SO2 primary National Ambient Air Quality Standards (NAAQS), the company continues to 

evaluate additional SO2 capture and control options. 

SO2 emissions based on 2010 permit renewal application are listed in the table below: 

Emission Unit/Activity SO2 Emissions, tpy 

Acid Plant tail gas stack 3,515 

Vent Fume Stack 1,336 

Smelter fugitives 5,517 

Chapter 11 – Reasonable Progress Determination

(70) Comment: The eleven step analysis undertaken by Arizona to determine appropriate and attainable 

Reasonable Progress Goals (RPGs) for the 2008 to 2018 planning period comports with discretion Arizona is 

granted in the statute. Although the RPGs established provide for a slower rate of visibility improvement 

than a mathematically-calculated Uniform Rate of Progress (URP), the RPGs are realistic and properly take 

into account both the significant reductions expected in Arizona’s anthropogenic emissions and the 

challenges associated with natural or international emission sources that Arizona cannot control. Point 

sources in Mexico, the highest source of SO2 in the region, are expected to increase by 150,000 tons per year 

(tpy) by 2018. 

19
Arizona’s decision to take a pragmatic, realistic approach to establishing attainable goals for visibility 

improvements in spite of these challenges is commendable. Despite the inability to regulate natural 

emissions sources or emissions sources in other jurisdictions, Arizona’s Regional Haze SIP will ensure 

meaningful visibility improvements at many Class I areas as a result of emissions reductions, primarily from 

motor vehicles and stationary sources. Arizona’s plan also comports with EPA regulations and guidance by 

following the four-factor structure for determining whether even greater visibility improvements are possible 

with additional control requirements. Arizona’s commitment to continue investigating possible emissions 

control technologies before the next SIP revision will help ensure continued progress toward the natural 

visibility conditions goal. Arizona’s proposed Regional Haze SIP represents an appropriate exercise of its 

discretion to establish RPGs by balancing the benefits of improved visibility with the cost of regulation, 

considering all information currently available. 

Response: ADEQ acknowledges the comment. 

Degradation on Best Days

(71) Comment: Section 11.3.1 on page 153 of the October draft SIP incorrectly reports that visibility is 

maintained on the 20% best days for all the Class I areas in Arizona and in most cases are under the 2018 

Uniform Rate of Progress. In fact, visibility on the 20% best days is projected to degrade at two IMPROVE 

monitors representing four Class I areas (Chiricahua National Monument, Chiricahua Wilderness, Galiuro 

Wilderness, and Saguaro National Park). Uniform Rate of Progress is not met at any Class I area in Arizona 

on the 20% worst days. These results do not support ADEQ’s assertion that Arizona is doing all that is 

needed to demonstrate reasonable progress by 2018. 

Response: Section 308(d)(1) of the Regional Haze Rule requires that states ensure no degradation in 

visibility for the least impaired days. Visibility projections however, show degradation at two IMPROVE 

monitors, CHIR1 and SAGU1. The degradation at CHIR1 and SAGU1 amounts to 0.03 dv and 0.1 dv, 

respectively, above the projected visibility conditions on best days in 2018. According to established 

literature, the change in deciview that is perceptible to the human eye is 0.5 dv. Even though the amount of 

degradation is very small, ADEQ agrees that it needs to be addressed. The primary pollutants contributing to 

visibility impairment on best days at CHIR1 and SAGU1 are sulfate, organic carbon, and coarse mass. It is 

important to note that coarse mass deciview is not modeled for 2018 due to model performance issues. 

Sulfate 

PSAT modeling of sulfate at CHIR1 on best days in 2018 indicates that the Outside Domain and Mexico 

contribute 43% and 23.1% towards sulfate concentrations, respectively. Arizona sources are projected to 

contribute 15.1%. At SAGU1, the Outside Domain and Mexico are also the highest contributors at 47% and 

17.9%, respectively. Arizona sources are projected to contribute 13.7% towards sulfate in 2018 on best days 

at SAGU1. Emissions of SO2 from point sources in Mexico are projected to increase by approximately 

150,000 tpy by 2018. CMAQ modeling projections show that SO2 will have the highest light extinction on 

best days at both CHIR1 and SAGU1. 

Organic Carbon 

On best days, WEP analysis for 2018 shows that Arizona sources of primary organic aerosol (POA) 

emissions have a total potential of 77% to contribute at CHIR1 and a 95% potential to contribute at SAGU1. 

The primary anthropogenic source of POA emissions are area sources. The potential for area sources within 

Arizona to contribute to POA emissions is projected to be 7.6% and 9.5% at CHIR1 and SAGU1 in 2018, 

respectively, which is an increase of 2% and SAGU1 and 1.8% at CHIR1. WEP analysis also shows that the 

20
potential for sources of natural fire to impact visibility on best days is approximately 62% and 76% at CHIR1 

and SAGU1, respectively, which is a much larger potential than from area sources. 

Coarse PM 

The primary components of coarse PM are road dust, fugitive dust, and windblown dust. The potential for 

coarse PM from Arizona sources of road dust and fugitive dust in 2018 is projected to be 6% (increase of 

1%) and 17% (increase of 7%), respectively, at CHIR1 on best days. The potential for Arizona sources of 

windblown dust to contribute to coarse PM at CHIR1 in 2018 is about 8%. It should be noted that sources of 

windblown dust from New Mexico have a 43% potential to contribute to coarse PM on best days at CHIR1. 

At SAGU1, the potential for coarse PM from Arizona sources of road dust and fugitive dust is about 20% 

(increase of 7%) and 89% (increase of 52%), respectively. The impact of windblown dust from Arizona 

sources to coarse PM at SAGU1 is about 10%. The potential to contribute to windblown dust from sources 

in Mexico is projected to be 11% in 2018. 

Source apportionment analysis shows that global and international contribution has a significant effect on 

visibility on best days at CHIR1 and SAGU1. It is reasonable to assert that the increase in SO2 from Mexico 

coupled with the contribution from the Outside Domain is one of the reasons why there is degradation in 

visibility on best days at these monitors. Another factor contributing to degradation is the impact of natural 

sources of organic carbon, which is approximately six times the contribution from area sources of organic 

carbon at CHIR1 and SAGU1. While the contribution from natural sources is large, ADEQ recognizes that 

the anthropogenic contribution of area sources must be addressed. The WEP analysis shows that the 

contribution to coarse PM at CHIR1 from Arizona sources of road dust and fugitive dust is high; however, it 

also shows that windblown dust from New Mexico has a greater potential to contribute to visibility 

impairment. It is reasonable to assert that the contribution from New Mexico has a greater effect on visibility 

than that from Arizona. 

All of the factors mentioned above are likely the primary reasons why there is a slight degradation in 

visibility at CHIR1 and SAGU1. ADEQ acknowledges the anthropogenic contribution from Arizona sources 

and will further address these emissions from anthropogenic sources in the next planning period. Changes 

being considered by EPA regarding the primary standards may reduce the contribution from anthropogenic 

sources and have a collateral benefit to the secondary visibility standard. ADEQ expects that these changes 

will further reduce the impact of visibility impairing pollutants in addition to other control measures 

implemented by ADEQ. 

(72) Comment: The plan must explain what is causing projected degradation on the best days at two Class I 

areas: Chiricahua/Galiuro and Saguaro East. In Saguaro East, Arizona’s projected share of nitrates in 2018 is 

53.57 percent. Ensuring there is no degradation on best days is a statutory requirement. 

Response: See response to comment 71. ADEQ’s calculation shows that Arizona’s contribution to nitrate is 

32.7% at SAGU1 on best days in 2018. ADEQ is unable to determine the basis for EPA’s calculated 

percentage. 

(73) Comment: As additional weight of evidence that visibility on the 20% Best Days is being protected, 

ADEQ should include the trends from 2000-2008 at the Chiricahua and Saguaro monitors 

(http://vista.cira.colostate.edu/dev/web/AnnualSummaryDev/Trends.aspx). 

Response: ADEQ acknowledges the suggestion and has decided to not include the information. The 

Visibility Information Exchange Web System (VIEWS) trend analysis is not capable of providing a revised 

deciview for 2018 projections; however, the analysis does point out that for SAGU1 and CHIR1 (the 

21
monitors showing degradation on best days), the visibility impairment on best days shows incremental 

decreases between 2000 and 2008. 

(74) Comment: Because Arizona will not meet the uniform rate of progress (URP) by 2018, the Regional 

Haze Rule requires ADEQ to project the year that natural background visibility will be achieved at the 

Arizona Class I areas under the lower rate of progress. 

Response: ADEQ has calculated revised URPs using the RPGs and projected natural visibility conditions at 

each Class I area in Arizona. This information is included in Section 11.5 of this SIP submittal. 

(75) Comment: The FLMs and NPS agree that mobile sources do not need to be considered under 

reasonable progress because significant emissions reductions are expected under existing federal and state 

requirements. The FLMs and NPS also agree that Arizona’s Enhanced Smoke Management Program 

addresses emissions from forestry and agricultural burning and that these source categories do not need to be 

considered in the reasonable progress analysis. 

Response: ADEQ acknowledges the comment. 

(76) Comment: The FLMs agree with ADEQ’s conclusion to focus on SO2 and NOX emissions in the 

reasonable progress analysis. The FLMs disagree with ADEQ’s conclusion not to consider PM and OC 

emissions in the reasonable progress analysis because large fractions of these emissions are from 

nonanthropogenic sources. ADEQ should consider what controls may be feasible to reduce anthropogenic 

emissions of dust, VOC, and POA from area source categories such as agricultural and construction practices 

and residential wood smoke. 

Response: ADEQ acknowledges the suggestion. EPA rules and guidance do not specifically state which key 

pollutants and source categories should be selected for the four-factor analyses in the first planning period. 

As a result, ADEQ has not provided additional analysis. 

(77) Comment: In Section 11.3.2, there appears to be a discrepancy between the text and Table 11.1 in the 

percentage contributions from Arizona sources to SO4 and NO3 at Class I areas in Arizona. The table 

indicates Arizona’s contribution to SO4 is 7-24% and to NO3 is 7-53%. 

Response: ADEQ has corrected the discrepancy in the percentages reported in the table. 

(78) Comment: ADEQ identifies major source categories for SO2 and NOX emissions (Table 11.2). The 

FLMs and NPS disagree with ADEQ’s assumption that visibility benefits from emissions reductions from 

these sources will be minimal. If the sources are located near Class I areas, the visibility benefits of controls 

could be substantial. 

Response: ADEQ did not evaluate the visibility impacts from non-BART sources as this is not a requirement 

under EPA rules for reasonable progress analyses. While the original draft submitted to and reviewed by the 

Federal Land Managers contained a statement that visibility impacts were expected to be minimal, without a 

more comprehensive analysis, such a statement cannot be supported and ADEQ removed it from the SIP 

prior to public comment. 

22
For reasonable progress towards long-term visibility improvement goals ADEQ included its analysis of nonBART sources in Chapter 11. This analysis included all sources that had actual emissions over 40 tons per 

year of NOX and SO2. In analyzing the inventory of sources, ADEQ determined that the evaluation could be 

meaningfully conducted by categorizing the inventory based on the significant emission units involved. 

Once the sources were categorized, ADEQ analyzed the viability of add-on controls. For some categories, 

the Department was unable to conduct a comprehensive 4-factor analysis and elected to conduct an 

evaluation for the feasibility of new controls as well as analyze the broad spectrum of new regulations that 

will apply to the facilities. Where possible, the Department did conduct a 4-factor analysis for exploring 

additional controls for visibility improvement. 

(79) Comment: Between the September and October drafts of the SIP provided to the FLMs, ADEQ has 

removed the tables in Section 11.3.3 that identify specific sources and emissions that may be candidates for 

controls under reasonable progress. The FLMs and NPS found those tables very informative and encourage 

ADEQ to reinstate them. 

Response: ADEQ’s approach to identifying specific sources and emissions that may be candidates for 

controls under reasonable progress has changed. As a result, the tables were no longer representative of the 

narrative and were removed. 

(80) Comment: EC/R developed a Four-Factor Analysis Report for WRAP covering industrial boilers, 

cement manufacturing, lime kilns, and internal combustion engines, which are major source categories 

identified by ADEQ. It appears that ADEQ did not use the information provided within the report and the 

FLMs and NPS recommend ADEQ use this report in the reasonable progress analysis. 

Response: As part of the assessment for non-BART sources, ADEQ reviewed the information in the report 

titled “Supplementary Information for Four Factor Analyses by WRAP States” dated May 4, 2009. In 

review of the document, the Department determined that the information presented was too broad, lacked 

critical information and could not be meaningfully adapted for the purposes of Arizona’s categorical 

analysis. The cost computations for the various technology options appeared to be derived from a generic 

costing tool called AIRControlNet. Additionally, several assumptions in the EC/R report do not appear to be 

substantiated by specific site and vendor data. In this regard, the Department decided not to utilize the 

above-mentioned report for its analyses. 

(81) Comment: The FLMs recommend that BART-eligible point sources that were determined not to be 

subject to BART should be considered for reasonable progress. ADEQ should consider a lower visibility 

impact threshold than 0.5 dv in a reasonable progress analysis. 

Response: ADEQ does not concur with using a lower visibility threshold. EPA BART guidance uses a 0.5 

dv as the visibility threshold and it is the state’s authority to select the threshold used for reasonable progress. 

There is no rationale provided for selecting a lower threshold. Using a lower visibility threshold would 

potentially subject non-BART sources to a more rigorous and more onerous process than sources subject-toBART without providing visibility benefit. The changes proposed by EPA to the primary NAAQS and other 

regulatory changes being considered by EPA will result in enforceable reductions that will likely contribute 

to visibility improvements. 

(82) Comment: The FLMs recommend that ADEQ review the reasonable progress analysis completed by 

Colorado as an example of a strong analysis of potential emissions control costs and benefits. 

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Response: ADEQ acknowledges the comment. 

(83) Comment: In Section 11.3.4, ADEQ concludes that no controls on non-BART sources are reasonable at 

this time and indicates that ADEQ will develop guidance for a more comprehensive review of individual 

sources over the next five years to identify any additional emission reductions that could improve visibility in 

the Class I areas by 2018. ADEQ should make a more binding commitment to emissions controls to be 

defined within the next five years and implemented by 2018. 

Response: The efficacy of current control measures are under continuing review for the purposes of ongoing 

planning as well as planning for areas within Arizona recently classified as nonattainment for PM. NonBART sources will most likely be controlled at or beyond the expectations of current NOX, PM, and SOX

measures based on current and future revisions to the NAAQS for 8-hour ozone (lower standard to be 

announced June 2011); SO2 (new standard announced June 2010); NO2 (new standard announced January 

2010); secondary NO2 and SO2 (new standard proposed July 2011); and PM (new standard proposed 

February 2011). All of these revised standards have implementation and attainment demonstration dated 

prior to 2018. 

(84) Comment: Correction under Section 11.4.1, item 4, mobile sources are not the largest anthropogenic 

source of SO2. (Comment received from FLMs and NPS.) 

Response: ADEQ has corrected the error. 

(85) Comment: ADEQ asserts that as yet undefined controls to be identified in the long term strategy will 

further improve visibility. There is no evidence presented in the long term strategy to support this statement. 

Response: ADEQ has revised the long-term strategy in Chapter 12 to support this assertion. 

(86) Comment: There is not a sufficient level of information and analysis to demonstrate whether additional 

controls are needed on non-BART sources in order to achieve reasonable progress. It would be helpful to 

know whether there are specific sources near Class I areas with emissions that may significantly affect 

visibility. 

Response: In its analysis of non-BART sources for reasonable progress towards long-term visibility 

improvement goals, ADEQ included all sources that had actual emissions over 40 tons per year of NOX and 

SO2. In analyzing the inventory of sources, ADEQ determined that the evaluation could be meaningfully 

conducted by categorizing the inventory based on the significant emission units involved. Once the sources 

were categorized, ADEQ analyzed the viability of add-on controls. For some categories, the Department was 

unable to conduct a comprehensive 4-factor analysis and elected to conduct an evaluation for the feasibility 

of new controls as well as analyze the broad spectrum of new regulations that will apply to the facilities. 

Where possible, the Department did conduct a 4-factor analysis for exploring additional controls for visibility 

improvement. Due to a lack of any detailed rule requirement or additional information in guidance outlining 

a procedure for analyzing the visibility impact of non-BART sources, a review of these sources will be 

conducted along with the adequacy of the entire plan as required by 40 CFR 51.308(h). This adequacy 

check-in is currently scheduled to occur before the end of the first planning period. 

(87) Comment: The plan must include an assessment of the number of years it would take to reach natural 

conditions if visibility improvement continues at the rate of progress that the state selected as reasonable. 

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Response: ADEQ has provided an assessment in Chapter 11 of the number of years it would take to reach 

natural conditions using the rate of progress as established by the 2018 visibility projections. 

Chapter 12 – Long Term Strategy

(88) Comment: In Section 12.3 the FLMs and NPS disagree with ADEQ’s conclusion that OC, EC, PM fine 

and coarse do not need to be considered in the long term strategy. The anthropogenic sources of these 

pollutants (e.g., area sources, road dust, and fugitive dust) are projected to increase with population and 

should be considered by ADEQ. 

Response: ADEQ discusses strategies to mitigate the contribution from anthropogenic sources of PM in 

Section 12.7. There are ten areas that are either currently or formerly nonattainment areas under the PM10

National Ambient Air Quality Standard (NAAQS). These areas are required to have control measures in 

place to reduce PM from anthropogenic activities. The anthropogenic contribution to OC and EC from 

prescribed fire is discussed in Section 12.7.5. Arizona has a certified Enhanced Smoke Management 

Program to reduce the impact of smoke from prescribed fire. ADEQ is considering revisions to the permit 

program for open burning to ensure efficient tracking of the potential contribution to OC and EC from area 

sources. Regarding population growth specifically, all existing PM plans are required to periodically update 

emissions inventory data for changes in population, commuting patterns, transportation projects, and any 

other new or changing source of particulates. This also includes a review and update of the related control 

measures for each plan. Changes to the NAAQS also require an analysis of population trends as will be the 

case for the anticipated revision to the PM NAAQS in 2011, and was the case for the newly established PM 

planning areas for the State of Arizona. In the case of OC and EC emissions, changes in population would 

most likely not result in an increase in anthropogenic fire but rather possible increases in mobile source 

emissions which would be tracked and mitigated as part of PM or ozone plans or transportation plans 

required for state and national parks. For those CIAs not covered by current or future SIPs, or transport 

requirements under Section 110(a)(2)(D) of the Clean Air Act, it is doubtful any population increase would 

cause a significant increase in emissions of any of these pollutants. 

(89) Comment: Section 12.3 provides a good discussion of Arizona impacts to Class I areas in neighboring 

states and neighboring states impacts to Class I areas in Arizona. What percentage contribution does Arizona 

have to Class I areas in Colorado? 

Response: ADEQ has included tables in Section 12.3 presenting the percentage contribution from Arizona to 

other Class I areas as well as tables presenting the percentage contribution from other states and regions to 

Arizona’s Class I areas. 

(90) Comment: The FLMs appreciate that ADEQ discusses Arizona’s requirements for Prevention of 

Significant Deterioration (PSD) and New Source Review (NSR) to evaluate air quality related values, 

specifically visibility. 

Response: ADEQ acknowledges the comment. 

(91) Comment: The discussion of measures to control dust and area sources in PM10 nonattainment areas in 

Section 12.6 is very helpful. Do the PM10 monitoring data demonstrate the effectiveness of these controls? 

Response: There is evidence to support that monitoring data demonstrates the effectiveness of PM10 control 

measures. EPA has made clean data findings for a number of PM10 moderate planning areas in Arizona due 

to the implementation and enforcement of various Reasonably Available Control Measures (RACM) as well 

as Best Available Control Measures (BACM) and Most Stringent Measures (MSM) in the serious 

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metropolitan planning area. The annual average concentrations at five monitoring stations in the greater 

Phoenix area show from 1990 to 2009, concentrations of PM10 have decreased ten micrograms per cubic 

meter, or 24%. Expanding to 11 monitors, the concentrations have decreased 15 micrograms per cubic meter 

or 25%. For moderate areas under maintenance plans, emission reductions due to the type of measures more 

commonly found in and around Class I areas (e.g. reduced track-out from unpaved roads, paving or 

stabilization of unpaved roads, retrofit or replacement of wood-burning stoves, anchoring of mining tailings, 

etc.) continue to show ongoing emission management. 

(92) Comment: Section 12.6.3 refers to compliance schedules for BART sources that install controls or 

accept federally enforceable permit limitations. Which BART source(s) accepted permit limits to exempt 

from BART? 

Response: No Arizona sources accepted permit limits to be exempt from BART. 

(93) Comment: In Section 12.6.5, ADEQ discusses the Enhanced Smoke Management Program (ESMP). 

Does the ESMP address whether the smoke management measures are voluntary or mandatory, specifically 

identify the Class I areas as sensitive receptors, and specify that avoiding impacts to Class I areas be 

considered in the smoke management decisions? 

Response: Arizona’s ESMP addresses each of these points. ADEQ has expanded the discussion of the 

ESMP in the long-term strategy in Section 12.6.5. The rules for Arizona’s Enhanced Smoke Management 

Program indicate that the measures are mandatory, Class I areas are identified as sensitive receptors, and 

mitigating smoke impact to Class I areas is considered in the smoke management decision process. 

(94) Comment: Section 12.7 discusses federal requirements for renewable fuels. If Arizona has state rules 

requiring implementation of renewable fuels, they should be discussed in this section. 

Response: Authority to develop and implement renewable or alternative fuels rests predominantly with the 

federal government (e.g., CAFE standards for fuel efficiency, boutique fuels, etc.). Under the authority of 

the Arizona Corporation Commission (ACC), rules that govern energy generation and use fall under the 

state’s “portfolio standards” requirement. As stated by the Arizona Corporation Commission’s Website at 

http://www.azcc.gov/divisions/utilities/electric/environmental.asp: 

“In 2006, the Commission approved the Renewable Energy Standard and Tariff (REST). These rules 

require that regulated electric utilities must generate 15 percent of their energy from renewable 

resources by 2025. Each year, Arizona's utility companies are required to file annual implementation 

plans describing how they will comply with the REST rules. The proposals include incentives for 

customers who install solar energy technologies for their own homes and businesses. The 

Commission’s Renewable Energy Standards encourage utilities to use solar, wind, biomass, biogas, 

geothermal and other similar technologies to generate “clean” energy to power Arizona’s future.” 

The actual emission reductions from the implementation of the state’s portfolio standards is not information 

currently available for this SIP. The increased percentage of energy from renewables does show a positive 

trend in Arizona as the renewable standard was considerably lower at the time of the 2003 Regional Haze 

SIP submission under Section 309 but was still deemed reasonable progress at that time. 

Local authority regarding fuels for mobile sources, including ultra-low diesel fuels and other alternative fuels 

cited in Arizona ozone and carbon monoxide SIPs, can be found on the Arizona Department of Weights and 

Measures Website at http://azdwm.gov/. Emission reductions for mobile sources, however, have already 

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been captured by the WRAP and are reflected in the emission inventories and projections already cited 

throughout this SIP. 

(95) Comment: Section 12.7.3 is intended to describe the long term control strategies for BART facilities 

but is incomplete in the October 25 draft. 

Response: ADEQ has completed the discussion of long-term strategies for the November version of the SIP. 

(96) Comment: Section 12.8 discusses the WRAP commitment to provide final regional modeling once the 

BART determinations are complete. It is not likely that WRAP will be able to fulfill this commitment; 

therefore ADEQ should delete this commitment. (Comment received from FLMs and NPS.) 

Response: ADEQ agrees with this statement and has removed the commitment. 

(97) Comment: As evidence of reasonable progress beyond the existing WRAP modeling, it is important for 

ADEQ to identify any additional BART or other emissions reductions that were not included in the WRAP 

2018 PRPb emissions inventory. 

Response: As stated in the response to Comment #6, ADEQ has reviewed the WRAP 2018 PRP18b 

emission inventory and is unable to accurately attribute facility emissions on a unit-specific basis. In that 

regard, ADEQ is unable to identify BART measures or emission reductions that were not taken into account 

in the WRAP 2018 PRP18b emissions inventory.

Chapter 13 – Consultation

(98) Comment: Please correct references to Oregon. 

Response: ADEQ has removed references to the Oregon Regional Haze SIP. 

(99) Comment: APS notes that ADEQ should correct the reference to Oregon in the third paragraph of 

Section 13.1, Federal Land Manager Consultation, Page 184, and replace with Arizona. APS also requests 

that ADEQ correct the typographical error on pages 141 and page 20 of Appendix D from “Arizona Power 

Service Company” to “Arizona Public Service Company.” 

Response: ADEQ has corrected the typographical error and removed incorrect references.