## Appendix E

Public Process(page intentionally blank)The Arizona Departm ent 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 th e 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 give n that the above-referenced meeting is open to the public. Materials distributed for the meeting are av ailable 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 acco mmodation, 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 ma ke the arrangements for the accommodation. This document is available in alternative formats by contacting ADEQ TDD phone number at (602) 771-4829.1 1

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29 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 W ashington in Phoenix, Arizona. My name is

Mark Lewandowski. I have been appointed by th e 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 f irst 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 f rom the Air Quality Planning

Section. Also out in the audience are other pe ople from ADEQ, includi ng Trevor Baggiore and

Corky Martinkovic, who’s just walking in.2 1

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31 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 W eb site regarding the proposed SIP.

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

comment, you should fill out a speaker slip, which is av ailable on the back table, and give it to m e.

Using speaker slips allows everyone an opportunity to be heard and allows us to m atch 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 com ment period on

the Proposed Regional Haze SIP closes at the comp letion 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 inform ation that may help you in making comments

on the Proposed Regional Haze SIP.

After the question and answer peri od, we will actually go into the form al 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 t oday' s hearing that you want the Department to

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

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

comment.

* * * * *

At this time, Lisa Tomczak will give a brief overview of the Proposed Regional Haze SIP.3 1

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31 Lisa Tomczak: Under Section 308 of the Federal Re gional Haze Rule in 40 CFR Part 51, states are

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

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

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 im prove 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 prim ary pollutants that impair

visibility at Arizona’s Class I areas are sulfat e, organic carbon, and coarse m aterial, and not

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

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

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

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

For this planning period, which ends in 2018, Ariz ona, like m any other states, will not meet the

uniform rate of progress, also known as the URP, towards achieving natural visibility conditio ns 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 th rough 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 cat egories, that began operation after August 7, 1962,

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

exceed 250 tons per year fo r any visibility im pairing 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 Po wer Cooperative (in Benson), Freeport McMoR an

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

the following steps to make its BART determinations:4 6

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31 o Identify existing controls already in use

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o Identify all available retrofit control options 2

o Eliminate technically infeasible control options 3

o Evaluate control effectiveness for control options 4

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

includes cost)

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

o Select BART 8

Reduction in visibility impairment caused by an thropogenic pollutants a nd anthropogenic activities

will also occur through many on-going pollution contro l p rograms such as Prevention of Significant

Deterioration, New Source Review, statewide rule s regarding Reasonably Attributable Visibility

Impairment, state and federal regulations regardi ng m obile 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 al so addressed through Arizona’s Enhanced S moke

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

ADEQ asserts that the modeled 2018 projections dem onstrate 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 Cla ss I areas and af fect the ability to meet the URP.

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

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

authority or the ability to control.

Mr. Lewandowski: We just finished the explana tion 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 explana tion period, and now we are m oving to a question

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

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

Again, the close of comment is toda y 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.

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

speak or turn in a speaker slip?

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

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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 2 nd . Thank you for attending, and the oral proceeding is closed.National Park Service Initial Comments Arizona Draft Section 308 Regiona l 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 Sec tion 308 regional haze State Impl ementation Plan (SIP). We appreciate the Arizona Departme nt of Environmental Quality (ADEQ)’s long-term commitment to visibility improvement through the Gra nd Canyon Visibility Transport Commission, the Western Regional Air Partnershi p (WRAP), the Section 309 mile stone process, and now the Section 308 SIP. We also appr eciate the opportunity to discuss our initia l comments with ADEQ on November 1, 2010.

ADEQ has provided a good summary of the WRAP technical analyses that address emissions,
source contributions to visibilit y 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 th e reasonable progress analysis.

Arizona is projecting degrada tion 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 supp ort ADEQ’s conclusion that the actions taken are
sufficient to demonstrate reasona ble progress in improving visibil ity in the Class I areas.

Our more detailed comments are presented below.

Specific Comments:

Chapter 7 Visibility Impa irment at Class I areas Organic Carbon (OC) is a dominate contributor to pollutants concentra tions 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 addr ess the relative contribut ions of natural and anthropogenic contributions to OC at the Class I areas. The WRAP Te chnical Support System provides daily time series of pollutant concentrations at th e IMPROVE monitors ( http://vista.cira.colostate. edu/tss/Results/HazePlanning.aspx v ; 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 secondar y natural carbon that vary seasonally and spatially.

1Chapter 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 (SO 2 ) and nitrogen oxides (NO

x ) for the BART sources. If there are
BART emissions reductions that were not included in the WR AP modeling inventory, these could be cited as evidence for greater than modeled visibility improvement.

The emissions table (Table 8.1) indicates that total SO 2 emissions from point sources will decrease by 2018. However, SO 2 emissions from the two copper smelters are projected to increase significantly (13,273 tons) by 2018. Pleas e discuss Arizona’s assumptions for future emissions from the smelters. These assumpti ons are critical to the source apportionment analyses in Chapter 9 that project that Arizona’s contribution to sulfate (SO 4 ) will increase at
several Class I areas.

Table 8.2 indicates that NO

x emissions from point sources will not change between 2002 and
2018. Is this consistent with ADE Q’s final BART determinations?

Tables 8.3-8.5 indicate that natu ral fire is the major source cate gory for Volatile Organic Carbon (VOC), Primary Organic Aerosols (POA), and Elemental Carbon (E C). Note that anthropogenic emissions from area sources, road dust, and fugitive dust are projec ted to increase.

Chapter 9 Visibility Modeling and Source Apportionment Please provide a brief summary of the mode l performance for the 2002 base year. Our confidence in the modeled responses to emission s changes is dependent on the model’s skill in representing atmospheric chemistry and transport. In general, model performance is better for
SO 4 and EC and less accu rate for nitrate (NO 3 ) and OC. Appendix C prov ides general references but does not give an overview of the model pe rformance as is required in the SIP.

Please briefly describe re lative 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, a nd Superstition. Since the natural sources are held constant, these increases ar e likely due to anthropogenic source s 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 po llutant concentrations is decreasing. PSA T indicates that the
contributions of Arizon a’s point sources to SO 4 concentrations will increase by 2018 at Chiricahua, Mazatzal, Petrified Forest, Saguaro, Superstition, Si erra Ancha, and Sycamore.
Please discuss the basis for this in crease. Projected increases in SO 2 emissions from the two copper smelters (assigned to Gila County) may expl ain the increases in SO 4 concentrations at the Class I areas. Note that in some instances (e .g., page 89-90 in the Oc tober 25 draft concerning

2PSAT modeling for Mazatal) the narra tive incorrectly refers to SO 4 emissions when SO 2 emissions were intended.

PSAT also projects that NO 3 concentrations due to NO

x emissions from AZ point sources will increase by 2018. Increases in SO 4 and NO 3 contributions from Ariz ona point sources are not consistent with ADEQ’s assertion that the stat e 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) proj ections indicate increases in Arizona’s
contributions to fine and coarse particulate matter and to organi c 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 re sults, we recommend that ADEQ consider measures to reduce anthropogenic particulate matter (PM) in the reasonable progress analysis.

Section 9.4.5 (page 114 of Octobe r 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 M odeling 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 stat es should use a conser vative interpretation of the CALPUFF outputs. Specifically, the states sh ould use either the maximum visibility impact with the annual average natural condition or the 98 th percentile visibility impact with the 20%
best natural conditions . ADEQ is reporting 98 th percentile visibility impa ct 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 evaluati on of performance and EPA Regional Office approval (Section 3.2, 40 CFR 51 Appendix W).

Most states have followed EPA st aff guidance to interpret the 98 th percentile impact as either the
maximum 8 th highest value in any single year or the 22 nd highest value for three years combined, whichever is more conservative. ADEQ used the 8 th highest value averaged over three years, which is a less conservative metric. Had ADEQ used the 8 th highest value in a single year,
Chemical Lime Nelson Plant would not have b een 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 subjec t 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 ut ilities. 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 P ublic Service’s Cholla Generating Station.

3Both analyses use very low winter values for ammonia based on early monitoring in the region. More recent ammonia monitoring 1

, 2 indicates higher ammonia va lues 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 El ectric 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 BA RT Comments, based on national experience, it appears that ADEQ and the companies have under es timated the efficiency of Selective Catalytic Reduction (SCR) to reduce NO

x emissions and have overestimated the costs of SCR installation and operation.

Please clarify how the costs were factored into the BART dete rminations. 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 BA RT Technical Support Docu ment indicates that ADEQ selected the least co st control option (low NO

x burners, existing PM and SO 2 controls)
even when more effective controls we re identified in the $1500-2000 range.

ADEQ presents the visibility benefit in $/dv for ju st the Class I area with the maximum impact.
If the cumulative benefits of cont rols 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 Cl ass 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 determin ations 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 NO
x , 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 NO

x emissions rate of 0.05 lb/mmBtu.

For SO 2 , we recommend that ADEQ require the exis ting scrubbers to achi eve at least 90% SO 2 removal with an annual average SO 2 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

2 Tombach and Paine, 2010, Report to Salt River Project, “Measurements of Background Ammonia on the Colorado Plateau and Visibility Implications”

4Arizona Public Service Cholla Units 2, 3, and 4
For NO
x , 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 NO

x emissions rate of 0.05 lb/mmBtu.

For SO 2 , we recommend that ADEQ require the exis ting scrubbers to achi eve at least 90% SO 2 removal with an annual average SO 2 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 we re underestimated. The visibility modeling needs
to be redone.

For NO
x , we concur with ADEQ’s estimated $1,021/ton fo r 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 SO 2 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 th e emissions limitation” “for similar emissions units with similar
emissions controls” is not cons istent with its Cholla BART analysis which concluded that replacement of the existing hot-s ide 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 NO

x emissions rate evaluated for control m easures and proposed by ADEQ as BART is twice as high as the uncontrolled NO

x emissions rate reported by CPSI and used in the cost
estimates. The costs of control are over estimate d by using a higher inte rest rate and shorter remaining useful life than recommended by the EPA Control Cost Manua l. The visibility benefits to multiple Class I areas have not been included. The BART analysis for NO

x is unacceptable and needs to be redone. The BART analysis for SO 2 is flawed with unsupported
costs and under estimated benef its. The BART analysis for SO 2 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 federall y enforceable, it will rema in BART-eligible. We disagree with the exemption of the source be cause the exemption criteria were incorrectly applied. We request the visibility impacts be ev aluated against the correc t exemption criteria.

5Chemical 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 appear s that CLC did not incl ude the 154 tpy of PM emissions modeled by WRAP into the compa ny’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 co rrected as discussed
above. We conclude that the Chemical Lime Co mpany – 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. Ou r interpretation is that Unit I4 needs to be
evaluated under BART.

ASARCO Hayden Smelter We agree with ADEQ’s conclusion that the inst allation and operation of the double contact acid plant with the New Source Performance Sta ndard of 650 ppm constitutes BART for SO 2. 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 inst allation and operation of the double contact acid plant with the New Source Performance Sta ndard of 650 ppm constitutes BART for SO 2. 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 SI P 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 Wild erness, and Saguaro National Park). Uniform Rate of Progress is not met at any Class I area in Arizona on the 20% wors t 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 fr om 2000-2008 at the Chiricah ua and Saguaro monitors (http://vista.cira.colostat e.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 ar e expected under existing federa l and state requirements. We

6also agree that Arizona’s Enhanced Smoke Ma nagement Program addresses emissions from forestry and agricultural burning a nd that these source ca tegories do not need to be considered in the reasonable progress analysis.

We agree with ADEQ’s conclusion to focus on SO 2 and NO

x emissions in the reasonable progress analysis. We disagree with ADEQ’s decision not to c onsider particulate matter and organic carbon emissions since anthropogenic emi ssions 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 P OA from area source categories such as agricultural and construc tion practices and residential wood smoke.

In Section 11.3.2, there appears to be a discre pancy between the text and Table 11.1 in the percentage contributions fr om Arizona sources to SO 4 and NO 3 at Class I areas in Arizona. The
table indicates Arizona ’s contribution to SO 4 is 7-24% and to NO 3 is 7-53%.

ADEQ identifies major source categories for SO 2 and NO

x 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 Oct ober drafts of the SIP, ADEQ has removed the
tables in Section 11.3.3 that id entify specific sources and emissi ons that may be candidates for controls under reasonable progress. We found those tables ve ry informative and encourage ADEQ to reinstate them.

The four-factor analyses reporte d in Section 11.3.3 are incomple te. We recommend that ADEQ use the Four Factor Analysis reported by th e WRAP’s contractor EC/R to support ADEQ’s analyses. The EC/R report covers industria l boilers, cement manufacturing, lime kilns, and internal combustion engines that are major source categories identified by ADEQ.

We also recommend that point so urces that were BART-eligible but determined not to be subject to BART should be considered for reasonable progr ess. It is appropriat e to consider a lower visibility impact threshold than 0.5 dv in a reasonable progress analysis.

We recommend that ADEQ review the reasonab le progress analysis completed by Colorado http://www.cdphe.state.co.us/ap/regionalhaze.html for an example of a strong analysis of potential emissions contro l 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 guid ance 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 area s by 2018. We encourage ADEQ to make a more binding commitment to emissions controls to be imp lemented within the next five years.

Correction under Section 11.4.1, item 4: mobile sources are not the largest anthropogenic source
of SO 2

.

7ADEQ asserts that as yet undefined controls to be identified in the long te rm strategy will further improve visibility. There is no evidence presen ted 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 mon itoring in the future.

In Section 12.3 we disagree with ADEQ’s conclu sion that OC, EC, PM fine and coarse do not
need to be considered in the long term strategy. The anthropoge nic sources of these pollutants (e.g., area sources, road dust, fug itive dust) are projected to in crease with population and should be considered by ADEQ.

Section12.3 provides a good discussion of Arizona imp acts to Class I areas in neighboring states and neighboring states impacts to Class I areas in Arizona. Wh at percentage contribution does
Arizona have to Class I areas in Colorado?

We appreciate that in Secti on12.6.1 ADEQ discusses Arizona’s re quirements for Prevention of Significant Deterioration and New Source Review to evaluate ai r 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 PM 10 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 th e 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 a dd 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 rene wable fuels. Does Ar izona have state rules requiring implementation of renewabl e fuels? If so, it would be a ppropriate 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.

89 Section 12.8: It is not likely that WRAP will be able to fulfill the com mitment 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 B ART 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 inform ation we have obtained from our reviews of BART proposals across the nati on. Following are our general co mments on the five-step BART analyses conducted by ADEQ.

Step 1: “Identify All Availabl e Technologies” and Step 2: “Elim inate 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 th e effectiveness of SCR to reduce emissions. SCR is different from many other control tec hnologies 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 meas ures to prevent blindi ng 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 NO X 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 SO 2 and NO X Removal (effective coal clean-up has a higher–but known–price tag)” by Robert Peltier, “An excellent exampl e of the significant investment many utilities have made over the past decade is Amer ican Electric Power (AEP), one of the largest public utilities in the U.S. with 39,000 MW of installed ca pacity with 69% of that capacity coalfired. AEP is under a New Source Review (NSR) c onsent decree signed in 2007 that requires the utility install air quality control systems to reduce NO X by 90%...”

1 ADEQ has included this statement ta ken from the company BART analysis:
SCR can achieve NO

x control efficiencies as high as 90% with inlet concentrations in the range of 300 to 400 ppmvd. If inlet NO

x concentrations are less than 250 ppmvd, SCR can achieve NO

x 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 str eams 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, partic ularly 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 NO

x Emissions from Fossil Fuel-Fired Electric Power Pl ants” (published in May 2009), “By proper catalyst selection and system design, NO X removal efficiencies exceedin g 90 percent may be achieved.”

1We are aware of vendor gua rantees of 0.05 lb/mmBtu, 3 and understand that major vendors are designing SCR systems to achieve 0.02 lb/mmBtu 4 on coal-fired boilers.

Operational evidence from SCR retrofits on eas tern 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 operat ing at or below 0.05 lb/mmBtu
in 2009.

ADEQ has assumed that 24-hour and 30-day rolli ng 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 th at, 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 achie ve 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 i nvolve 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 i ndicate 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 costi ng 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 co ntrols, ammonia use is safe and routine.” WHITE PAPER SELECTIVE CATALYTIC REDUCTION (SCR) CONTROL OF NO X EMISSIONS FROM FOSSIL FUELFIRED ELECTRIC POWER PLANTS PREPARED BY: NOx CONTROL TECHNICAL DIVISION INSTITUTE OF CLEAN AIR COMPANIES, INC. May 2009 Copyright

2data. Both OAQPS and EPA Region 8 have advise d 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 sufficie nt 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 shou ld be preferred over CU ECost for developing cost analyses that are transparent and consis tent across the nation a nd 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 SO 2 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 co st methodology devised by EPRI. A TCR estimate includes Allowance for Funds Used During Construction (A FUDC), 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 commented 6 upon PSCo’s use of Present Value of Revenue Requirements (PVRR) model to calculate the le velized 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 cont rol 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 ra te 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.

3There 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 CU ECost model, nor is it appropriate to escalate costs into the future and compare th em against current cost thresholds.

Mr. Sorrels also provided 7 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, en gineering & supervision, etc.). The Marshall & Swift cost index is useful for industry-lev el cost estimation, but is not as acc urate at a disaggregated level when compared to the CEPCI. Thus, I recommend us e of the CEPCI as a cost index where possible.

I agree with including AFUDC in a cap ital 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 co sts can be found in a June 2009 article in “Power” magazine: 8

“One more current data set is the historic cap ital cos ts 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% NO X 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 su rvey results). Applying those annual increases to the 2004 estimates for three year s (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 majo rity of the systems, with only three reported inst allations exceeding $200/kW.”

Five industry studies conducted between 2002 a nd 2007 have reported the installed unit capital cost of SCRs, or the costs actu ally 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 fro m $106 to $213/kW, convert ed to 2007 dollars. 9 Costs are escalated through using the CEPCI.

7 7/21/10 e-mail to Don Shepherd

4The second survey of 40 installations at 24 st ations reported a cost range of $76 t o $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 st udy reported a cost rang e 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 applicati ons 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 slat ed for startup in 2009 at $300/kW. 13

EPA’s Region 8 Office has compiled a graphic pres entation 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 stud ies 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 ar ticle “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/i s_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-=-Supr emely-Complex-Retrofit/

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

5We have been working with an Excel work book we derived from the SCR cost estimation method presented by EPA’s Office of Air Qualit y Planning and Standard s 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 propo rtional to the DCC, a straightfo rward 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. Firs t, 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 Indi rect Installation and C ontingency costs to the DCC to estimate TCI. If the resulting TCI, expre ssed in $/kW is within the expected range, we carry that estimate through the remainder of the co st 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 pr ocess 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 stra ight-forward and shoul d 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 consis tent significant overestimation of DAC.

Step 5: Evaluate Visibility Results

We believe that it is appropriate to consider bot h the degree of visibility improvement in a given
Class I area as well as the cu mulative effects of improving visi bility 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 doe s not make sense to evaluate impacts at one Class I area, while ignoring others that are similarly significantly im paired. If we look at only the most-impacted Class I area, we ignore that th e other Class I areas are all suffering from impairment to visibility “caused” by the BART s ource. 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 as sumptions, 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 addr ess 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/sample updates/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 Gene rating Station and the Four Corners Power Plant.

67 large Class I area and isolated impacts in a sm all Class I area. To address the problem of geographic extent, we have been looking at the cumulative impact s of a source on all Class I areas affected, as well as the cumulative benefits from reducing emissions. While there are certainly more sophisticated appr oaches to this problem, we be lieve 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, ec onomic, energy, and environmen tal (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 aff ected. 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 Gu idelines to evaluate cost-effectiveness is cost/deciview. We believe that visibility improveme nt must be a critical factor in any program designed to improve visibility. Compared to the t ypical 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 a ppear extraordinarily expensive. However, our compilation 19 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 th e 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 Bridge r Unit #2 that “The incremental cost effectiveness for Scenario 1 compared with the baseline for the Bridger WA, fo r example, is reasonable at $580,000 per day and $18.5 million per deciview.”NPS Comments
Ari zona Electric Power Cooperative (AEPCO ) – Apache Generating Station BART Analysis and Determination

November 29, 2010

Process Description

The Apache Generating Station consis ts of seven electric generati ng units (two co al/natural gasfired steam electric units, a natural gas/fuel oi l-fired steam electric, combined cycle unit, and four natural gas/fuel oil-fired turbines) with a total generatin g 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 potentia lly subject-to-BART. Of 1,228 plants, EPA Clean Air Markets (CAM) da ta for 2008 rank the Apache facility #352 for
SO 2 and #141 for NO X

.

Steam Unit 1 (ST1)

Apache Steam Unit 1 is a wall-fired steam-electri c 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, SO 2 emissions have not exceeded one ton per year (tpy), and
NO X emissions have averaged 0.14 lb/ mmBtu and declined to 30 – 60 tpy.

NO
x BART Analysis

Step 1: Identify the Existing Contro l Technologies in Use at the Source

There is no NO

x emissions control equipment installed on ST1.

Step 2: Identify All Available Retrofit Control Options

The second step of the BART process is to evaluate NO

x control technologies with practical potential for application to ST 1, including those cont rol technologies identified as BACT or LAER by permitting agencies across the United States. ST1 NO

x emissions are currently controlled through the use of good combustion practices.

The following potential NO

x 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

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

Step 4: Evaluate Control Effec tiveness of Re maining Technologies ADEQ has estimated the installation of LNB with FGR can achieve a NO

x 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 Environm ental Impacts and Document Results- -Economic Impacts

ADEQ has estimated that LNB with FGR will have a Total Capita l 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 NO

x is the installation of LNB with FGR with
a NO
x 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.

PM 10 BART Analysis

The PM 10 BART analysis is only completed for the case when ST1 burns 100 percent No. 6 fuel oil. This was done for comparison only, as AEPC O has never combusted No. 6 fuel oil in the unit).

SO 2 BART Analysis

Emissions indicate that BART anal ysis is not required when ST1 burns PNG or fuel oil No. 2. ADEQ has determined that, for Unit 1, BART for SO 2 is the use of PNG or No. 2 fuel oil with an
SO 2 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 natura l 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 an d #823, respectively for SO 2 , and #344 and #261, respectively for NO X

. ADEQ modeling data show that Apache Units 2 and 3 have a combined maximum impact at
Chiricahua Wilderness Area and National Monu ment of 4.84 dv. The cumulative impacts of

2Apache Units 2 and 3 a cross the nine Class I areas modeled is 20.5 dv, which ranks these units among the highest 1 of any facility we have ev aluated under the BART program.

NO
x BART Analysis

Step 1: Identify the Existing Contro l Technologies in Use at the Source Both Units 2 and 3 currently use OFA and under-fired air systems to control NO

x 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 NO

x control technology options were considered:

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

 Rotating opposed fire air (ROFA)

 Selective non-catalytic reducti on system (Rotamix and SNCR)

 Selective catalytic reduction (SCR) system

 Neural Network Controls/Boiler Co mbustion 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 Effec tiveness of Re maining 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% reducti on by SCR from the emission rate to be achieved by LNB+OFA alone. It is generally assumed that SCR can achieve at least 90%
NO X reduction, and we have presen ted 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 NO X 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, Co ronado 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 decrea se 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.

3Step 5: Evaluate the Energy and Non-Air Qualit y 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 i nvolve 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 em ission rate of 0.03 lb/mmBtu in this cas e, as a conservative estimate, we
have assumed that SCR would achieve 0.05 lb/mmB tu (84% reduction) on an annual average
basis.

In generating our SCR cost estimate, we note th e following differences be tween 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. Maxi mum 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 actua l operating hours, maximu m actual annual heat input, and maximum actual annual average hourly h eat input. However, we also used the 2000 – 2009 average annual NO X emission rate (in lb/mmBtu), whic h was lower than used by AEPCO,
to estimate annual NO X emissions. In effect, we assumed th at the units would operate at their historic maxima for operating hour s and heat input, but emit at th eir historic average rate. The
result was an annual NO X 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 cata lyst reactor, and more reagent w ould be required to treat the greater quantity of NO X 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 I nvestment (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 es timates 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

4Cost m anual’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 comb ines the Direct Capital Cost (DCC) provided by the source and the ratios applied by the Cost Ma nual 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 rati os 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 Duri ng Construction (AFUDC) which may not be justified (Please see our Gene ral 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 th is 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 cel l F5 on the “Ann Cost” tab.

Annual Cost estimates are genera ted 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 diffe rent estimates of TCI) and the amount of NO X removed (due to our assumed high er SCR efficiency).

A summary of our analysis can be found on the far-right tab of our wo rkbook. We believe that our estimation method is more transparent and true r to the EPA Cost Manual approach than that provided by AEPCO, and that our $1500 - $1700/ton results are better s upported 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 fo r 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 Nationa l Monument. The results provided by AEPCO show a cumulative improvement of 1.68 – 1.82 dv acr oss the four Class I ar eas for which results were provided.

Step 7: BART Selection

ADEQ: After reviewing the company’s BART anal ysis, and based upon the information above, ADEQ has determined that, for Units 2 and 3 BART for NO

x is new LNBs with OFA system
with a NO

x emissions limit of 0.31 lb/MMBtu for both Units 2 and 3.

5NPS: ADEQ estim ates that all of the options it evaluated would cost less than $2,200/ton and $10 million/dv to implement, which is well be low the $14 - $18 million/dv average of BART proposals across the nation. BART, like BACT, is not necessarily the most-c ost-effective option. Instead, it is typically chosen based upon a comparison to options selected by other regulatory agencies in similar situations. For example, Or egon DEQ has established a cost/ton threshold of $7,300 based upon the premise that improving visibi lity 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 th at 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.

PM 10 BART Analysis

Step 1: Identify the Existing Contro l Technologies in Use at the Source

Both Steam Units 2 and 3 are current ly equipped with hot-sid e Electrostatic Precip itators (ESPs).

Step 2: Identify All Available Retrofit Control Options

ADEQ: Steam Units 2 and 3 are currently equipped w ith hot-side ESPs. Historically, outlet ESP particulate emissions on Units 2 and 3 ha ve 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 iden tified 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 Effec tiveness of Re maining Technologies

ADEQ Table 12 lists the various control tec hnologies and estimate d 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

6Control Technology Expected PM 10 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 Qualit y Environm ental 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 precip itator 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 PM 10 emissions is upgrades to the existing ESP and

a PM 10 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 fl ue gas conditioning system, improvements to the scrubber bypass damper system, and implementi ng programming optimization measures for ESP automatic voltage controls.

NPS: We concur.

SO 2 BART Analysis

Step 1: Identify the Existing Contro l Technologies in Use at the Source

Units 2 and 3 currently operate wet limestone scrubbers for SO 2 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 SO 2 control technology option considered

The EPA BART guidelines state that for existing units with SO 2 controls achieving at least 50 percent SO 2 removal, cost-effective scrubber upgr ades should be considered. EPA has recommended consideration of the following potential upgrades:

 Elimination of bypass reheat

 Installation of liqui d 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 identifi ed control technology upgr ades are technically
feasible.

Step 4: Evaluate Control Effec tiveness of Re maining Technologies

ADEQ: When evaluating the control effectiveness of SO 2 reduction technologies, each option can be compared against benchmarks of performance. In its BART analysis, AEPCO chose to compare its proposed technology upgrades to EP A’s presumptive BART emission limitations. According to EPA’s BART guidance documents, the presumptive limit for SO 2 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 pote ntial of the scrubber upgrades to achieve emission rates lower than the presumptive rate. The AEPCO reports indicate:

 For Unit #2, uncontrolled SO 2 emissions are 0.69 lb/mmBtu, and current controls reduce
SO 2 emissions by 73% down to 0.18 lb/mmBtu.

 For Unit #3, uncontrolled SO 2 emissions are 0.69 lb/mmBtu, and current controls reduce
SO 2 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 SO 2 controls with
new limestone forced-oxidation scrubbers. In 2005 PSNM agreed to u pgrade the scrubbers by 2009 such that the annual rolling average SO 2 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 scrubbe rs 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 Qualit y Environm ental Impacts and Document Results

Over the past several years AEPCO has completed several sc rubber upgrades to improve performance, including the following:

89  Elimination of flue gas bypass

 Splitting the limestone feed to both th e 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 SO 2 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 scrubb er 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 co st impacts attributable to upgraded scrubber operation.

Step 6: Evaluate Visibility Impacts

A Visibility Impact Analys is was not performed for SO 2 since the existing scrubbers are proposed as BART.

Step 7: BART Selection

ADEQ: After reviewing the company’s BART anal ysis, and based upon the information above, ADEQ has determined that BART for SO 2 emissions is no new contro ls 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 a nd 3 achieve at least
90% SO 2 removal across the scrubbers, not to exceed 0.12 lb/mmBtu.NPS Comments
APS Cholla Generating Station B ART 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 al ong Interstate 40 in Navajo C ounty, 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 stea m-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 Ma rkets (CAM) data for 2008 rank the Cholla facility #143 for SO 2 and #88 for NO X

.

Cholla Units 2, 3 and 4 are subjec t-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 SO 2 , and #302, #241, and #335, respectively
for NO X

.

Despite the improper modeling methods applied by APS and the resulting underestimations of impacts, the cumulative impacts of Cholla Unit s 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 (NO
x ) BART Analysis and Determination for Units 2, 3 and 4

Step 1: Identify the Existing Contro l Technologies in Use at the Source The Cholla BART Analysis was completed in la te 2007. At that time, the Units were equipped with Close-coupled Overfire Air (COFA) . Overfire air is used to reduce NO

x by reducing excess
air in the combustion zone. Low NO

x Burner (LNBs) and Separate d 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 NO

x reduction.

Step 2: Identify All Available Retrofit Control Options APS has identified the following availabl e retrofit control technologies for NO

x 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)

1NPS: W e 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 Effec tiveness of Re maining 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% reducti on by SCR from the emission rate to be achieved by LNB+OFA alone. It is generally assumed that SCR can achieve at least 90%
NO X reduction, and we have presen ted 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 NO X 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 Qualit y Environm ental 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 i nvolve 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 em ission rate of 0.02 lb/mmBtu in this cas e, as a conservative estimate, we
have assumed that SCR would achieve 0.05 lb/mmB tu (77% reduction) on an annual average
basis.

In generating our SCR cost estimate, we note th e following differences be tween 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 decrea se 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.

2Our review of pre-m odification 2000 – 2007 CAM da ta (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 actua l operating hours, maximu m actual annual heat input, and APS’ estimate for actual maximum hourly heat input. However, we also used the 2000 – 2007 average annual NO X emission rate (in lb/mmBtu), which was lower than used by APS, to
estimate annual NO X emissions. In effect, we assumed th at the units would operate at their historic maxima for operating hour s and heat input, but emit at th eir historic average rate. The
result was an annual NO X 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 NO X emissions and the costs associated w ith reducing them would be lower.

We used ADEQ’s estimates for costs associat ed with LNB+OFA, and APS’ unit costs for catalyst, reagent, and electricity.

A critical cost element is the Total Capital I nvestment (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 yiel ds $67 - $74/kW (Please see the “ICC” tab cell L18.), which appears too low for E GUs this size and thus prompted us to override the Cost manual’s TCI calculation. On th e other hand, the APS estimate of $249 - $258/kW (Please see the “ICC” tab cell P18.) is more e xpensive 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 comb ines the Direct Capital Cost (DCC) provided by the source and the ratios applied by the Cost Ma nual 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 rati os 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 Allowa nce for Funds During Construction (AFUDC) which may not be justified (Please see our General BA RT 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 va lues 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” ta b.) 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 th e Cost Manual estimates. The most significant

3differences were between the Indirect Annual Cost (due to the different es tim ates of TCI) and the
amount of NO X 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 re al-world industry experience.

Step 6: Evaluate Visibility Impacts ADEQ: CALPUFF modeling was performed at 13 Cl ass I areas that are located within 300 kilometers of Cholla Power Plant. The impacts are modeled for different NO

x control scenarios,
combined with SO 2 and PM 10 technologies at Petrif ied 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 ar e 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 NO

x control scenarios are less than 0.5 dV. For example, in the case of Unit 3, the dV cha nges range from 0.126 dV for the LNB with SOFA (Scenario 1) to 0.230 dV for LNB w ith SOFA and SCR (Scenario 5). T he change in dV between the least expensive and most expensive NO

x 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 fi ve-factor analysis discussed above, ADEQ has concluded that
LNB with SOFA constitute BART for NO

x 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 visib ility 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 opti ons 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 aff ected. 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 Wi sconsin 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

4PM 10 BART Analysis

Step 1: Identify the Existing Contro l Technologies in Use at the Source

Unit 2 currently has a mechanical dust collector for control of PM 10 emissions. Additional particulate matter control is provid ed by a Venturi scrubber. Cholla 2 is currently ab le 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 PM 10 . The facility completed installati on of a fabric filter in May 2009. With the installation of the fabric filter, the faci lity expects to consistently achieve an emission
rate of 0.015 lb/MMBtu for PM 10

.

Unit 4 was previously equipped with a hot-side ESP and was able to achieve an emission rate of
0.024 lb/MMBtu of PM 10 . The facility completed installati on of a fabric filter in May 2008. With the installation of the fabric filter, the faci lity expects to consistently achieve an emission
rate of 0.015 lb/MMBtu for PM 10

.

Step 2: Identify All Available Retrofit Control Options

Since Units 3 and 4 will be equipped with fabric f ilters, 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 cons idered 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 ar e technically feasible.

Step 4: Evaluate Control Effec tiveness of Re maining Technologies

Fabric filters are proven to be highly effec tive and provide a consis tent particulate matter
reduction. The emissions at the outlet of fabric fi lter are expected to be less than 0.015
lb/MMBtu.

Step 5: Evaluate the Energy and Non-Air Qualit y Environm ental 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-effectivene ss 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

5Step 6: Evaluate Visibility Impacts

The installation of a fabric filt er is the only option c onsidered for BART for all the 3 units.

Step 7: BART Selection

Based upon its review of the comp any’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 PM 10 for Units 2, 3 and 4.

NPS: We concur.

SO 2 BART Analysis

Step 1: Identify the Existing Contro l Technologies in Use at the Source

According to ADEQ:

Unit 2 . This unit is equipped with four Ventur i flooded disc scrubbers /absorber with lime reagent for SO 2 control. Currently, APS Cholla is able to achieve 0.14 lb/MMBtu to 0.25
lb/MMBtu of SO 2 on Unit 2.

Unit 3. This unit did not have any SO 2 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 performan ce 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 follo wing available retrofit control technologies
for SO 2 control in Unit 3:

 Dry Flue Gas Desulfurization (FGD) System

 Dry Sodium Sorbent Injection

 Wet Lime Scrubber

6Subsequently, Cholla installed a new W et Lime Scrubber on Unit 3 in May 2009. Therefore, the new wet lime scrubber, as described above, is th e only retrofit control te chnology 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 identifi ed control technology upgr ades are technically
feasible.

Step 4: Evaluate Control Effec tiveness of Re maining 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 SO 2 emissions are 1.00 lb/mmBtu, and the ADEQ proposal would reduce SO 2 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 SO 2 controls with
new limestone forced-oxidation scrubbers. In 2005 PSNM agreed to u pgrade the scrubbers by 2009 such that the annual rolling average SO 2 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 scrubbe rs can achieve better removal effi ciency and lower emission rates than the 85% and 0.15 lb/mmBtu proposed by ADE Q. ADEQ must evaluate those options.

Step 5: Evaluate the Energy and Non-Air Qualit y Environm ental 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
- - - -

78 Wet Lime
scrubber 0.15 1,655 9,378 $8.80 936 $936

Step 6: Evaluate Visibility Impacts

A Visibility Impact Analys is was not performed for SO 2 since the existing scrubbers are proposed as BART.

Step 7: BART Selection

ADEQ: Based upon its review of the BART anal ysis 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/MMB tu is the BART for control of SO 2 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% SO 2 removal across the scrubbers, not to exceed 0.12 lb/mmBtu.NPS Comments Salt River Project (SRP)’s Coronado Ge nerating Station BART Ana lysis and
Determination

November 29, 2010

Process Description

Salt River Project (SRP) Coronado Generating Stati on (CGS) is located near St. Johns in Apache County and is comprised of two dry-turbo-fired Units 1 and 2 with a ne t rated output of 395 MW and 390 MW, respectively. Presumptive BART app lies to these two units with total capacity greater than 750 MW. Of 1,228 plants, EPA Clean Air Markets (CAM) da ta for 2008 rank the Coronado facility #146 for SO 2 and #59 for NO X . Of 3,558 EGUs, 2008 CAM data rank Coronado Units 1 and 2 at #298 and #300, respectively for SO 2 , and #76 and #85 respectively for

NO X

.

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 in to a Consent Decree which requires the implementation of the following pollution control projects for SO 2 and NO

x at SRP’s CGS facility.

 Addition of Low-NO X Burners (LNB) to Units 1 and 2 to reduce NO

x emissions to 0.32 lb/mmBtu by June 2011. Coupled with the bur ner 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 NO

x emissions from Unit 2 to 0.08 lb/mmBtu.

 Replacement of the existing wet limestone Fl ue Gas Desulfurization (WFGD) systems on Unit 1 and Unit 2 with new WFGD systems by January 2012 to reduce SO 2 emissions by
95% or to 0.08 lb/mmBtu.

BART for NO
x

Step 1: Identify the Existing Contro l Technologies in Use at the Source ADEQ: NO

x emissions from both Units 1 and 2 are currently controlled by good combustion practices and overfire air. The resulting emission rate ra nges 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 NO

x control technologies for limiting NO

x emissions from Unit 1 and
Unit 2 are listed as follows:

1 Advanced Com bustion Control-Low NO

x 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 Effec tiveness of Re maining 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 NO

x control efficiencies as high as 90% with inlet concentrations in the range of 300 to 400 ppmvd. If inlet NO

x concentrations are less than 250 ppmvd, SCR can achieve NO

x 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 ADE Q 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 pr imarily a function of catalyst temperature, volume, type, and area. It is unlikely that the NO X concentration proposed as BART by ADEQ would present such a low concentration as to significantly reduce SCR re moval efficiency. We request that ADEQ provide support for its contention.

Because SCR will be applied to Unit 2 as a resu lt 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% reducti on by SCR from the emission rate to be achieved by LNB+OFA alone. It is generally assumed that SCR can achieve at least 90%

NO X reduction, and we conclude that ADEQ has unde restimated the ability of a modern SCR
retrofit to reduce NO X emissions. Because such an underestimate adversely affects the costbenefit analysis, we conducted our analysis as disc ussed 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, par ticularly 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 decrea se 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.

2Step 5: Evaluate the Energy and Non-Air Qualit y 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 i nvolve 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 Commen ts, 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 estimat e of $167/kW appears reasonable.

Annual Cost estimates are genera ted by a direct application of the Cost Manual method to the new TCI and other interim values. We applie d the Cost Manual method and found that SRP’s
Annual Cost estimates are also reasonable.

We concur with ADEQ’s estimated $1,021/t on for combustion controls plus SCR.

Step 6: Evaluate Visibility Impacts

NPS: Because SRP used background ammonia leve ls 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 pr ovided by the company, and based upon the information above, ADEQ has determined that BART control at CGS for NO

x is ACC (Low NO

x burners with OFA) with an associated NO

x emission rate of 0.32 lbs/ MMBtu on 30-day rolling average basis.

NPS: Because of the improper visibility m odeling 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 vi sibility 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

3agencies in sim ilar situations. For example, Or egon DEQ has established a cost/ton threshold of $7,300 based upon the premise that improving visibi lity 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 th at meets the selection criteria, SCR
should be selected as BART due to the r easonable cost/ton and lower-than-average
cost/deciview.

PM 10 BART

Step 1: Identify the Existing Contro l Technologies in Use at the Source

PM 10 emissions from the facility are currently contro lled through the use of a hot-side ESP.

Steps 2-6: Streamlined Review

ADEQ: SRP’s BART analysis for PM 10 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, PM 10 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 lim itation, further analysis was determined to be

unnecessary.

NPS: ADEQ’s contention that its proposed 0.03 lb/m mBtu BART limit “is already meeting or exceeding the stringency of the emissions limitati on” “for similar emissions units with similar
emissions controls” is not cons istent with its Cholla BART analysis which concluded that replacement of the existing hot -side ESPs with fabric filte rs at 0.015 lb/mmBtu is BART.

Step 7: Select BART

ADEQ: After reviewing the analys is provided by SRP, and the information presented above, ADEQ has determined that BART for PM 10 from Units 1 and 2 is no further control, and an
emissions limitation of 0.03 lb/MMBtu.

NPS: ADEQ did not conduct the necessa ry five-step BART anaysis.

SO 2 BART

Step 1: Identify the Existing Contro l 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

4SO 2 emissions are currently controlled with the us e of low-sulfur coal and partial wet flue gas desulfurization. The resulting emission ra te 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 SO 2.

 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 ar e technically feasible.

Step 4: Evaluate Control Effec tiveness of Re maining Technologies

ADEQ: SRP and EPA’s consent decree stipulates th e installation of WFGDs for both the units.
WFGD is the most effective control technology available for controlling SO 2 emissions. Since SRP is committing to the WFGD technology, other control technologies ar e not evaluated from this point forward in the BART analysis.

Step 5: Evaluate the Energy and Non-Air Qualit y Environm ental Impacts and Document Results

Costs of Compliance

ADEQ: Based on the vendor data on the capital co st 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 Annu al Costs associated with SO 2 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 esti mated emission numbers for SO 2 and cost figures relating to the implementation of WFGDs.

Table 10: Total Annual Emissions of SO 2 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

56 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 mode led for each meteorological year (2001- 2003) and for all 17 Class I areas within 300 km. The modeling resu lt indicates that the installation of a WFGD will provide for significan t visibility benefit. The highest visibility improvement will occur at the Petrified Na tional Forest where an improvement of 1.38 ∆ dv is expected.

Table 11 provides information on annualized cost a nd the cost in dollars per deciview average improvement in visibility achieved by implementing the control option.

Table 11: Summary for SO 2 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 SO 2 emission rate of 0.08 lbs/MMBtu on 30-day rolling average basis.

NPS: We concur and note that ADEQ has ac cepted the WFGD option at $1,722/ton and $32.1
million/dv.NPS comments on the Catalyst Pa per (Snowfla ke) Inc. BART Analys is 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 Snow flake, Arizona, which produces newsprint and newsprint-like grades at a capacity of a pproximately 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 visi bility 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 visibili ty at a Class I area and is subject-to-BART for
NO
x and SO 2

.

NPS: Agreed.

NO
x BART Analysis and Determination

Step 1: Identify the Existing Contro l Technologies in Use at the Source

CPSI currently does not operate any NO

x control technology on Po wer Boiler #2 although there is a permit limit of 0.7 lb/MMBtu. There is an ex isting over fire air syst em (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 NO

x 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 selec tive 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.

1Step 4: Evaluate Control Effec tiveness of Re maining Technologies

According to the analysis performed by Catalyst Paper, the technically feasible control options were identified as being able to ach ieve 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 NO

x emission rate of
0.192 lb/mmBtu and a desired outlet emission ra te of 0.148 lb/mmBtu. Because the uncontrolled
emission rate is lower than the “Achievabl e Emission Rates” evaluated by ADEQ, the ADEQ analyses are invalid.

In its SCR cost analyses, CPSI has assume d a boiler outlet NOx emission rate of 0.265
lb/mmBtu. We have shown in our General BA RT 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 Qualit y Environm ental Impacts and Document Results

Cost of Compliance

ADEQ: During the course of Catalyst Paper’s review of the technically f easible control options, the company identified the expected amount of emissions reduced by th e application of each control option, as well as the annua lized cost, and the average cost effectiveness of the controls.
That information is summarized in Table 5 below.

2Table 5: Cost of Compliance of Control Options

Control Option Expected
emissions
reduction (tpy) Annualized Cost Average Cost
Effectiveness ($/ton NO

x )

OFA 868 $3,221,359 2 $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 NO

x at the permit limit of 0.7 lb/MMBtu. That is the
rate at which CPSI modeled vi sibility impacts and therefore must be held constant for any analysis based on emission

rates. 2. There is a large annualized cost to this existing equipmen t because it has been assumed that its operation would make the fly ash fr om 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 OF A) that provides greater annual reduction at a lower annualized cost. ADEQ has eliminated thos e 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 an d used by ADEQ were actually based upon the
lower NO

x 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 ma nual. 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 th at its operation would make the fly ash from the boiler unsellable.” Neither CPSI nor ADEQ have provided any concre te justification to support its speculation. On the contrary, our conver sations with SNCR vendors indicate that this claim is probably invalid.

Energy Impacts

ADEQ: According to the analysis provided by C PSI, there are adverse energy impacts that require consideration for several of the technicall y 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

3ADEQ: Acc ording to CPSI’s analysis, non-air qualit y 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 car bon, the installation of LNB and OFA may have the potential of rendering the fly ash unsellable. If the fly ash we re rendered unsellable, the fly ash would increase the amount of solid waste gene rated at the facility, ultimately increasing the
amount sent to the landfill.

In addition to the LNB and OFA technologies, S CR 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 NO

x . Most SCR and SNCR vendors reco mmend that the operator inject
more than the stoichiometric amount of ammoni a 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 exhaus t 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 ha s indicated that the facility will be shut down in the near future. For the purposes of it s 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 li fe for SNCR and SCR. The Cost Manual recommends a 20-year life. As a result, ADEQ ha s 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 on e of the technically-fea sible and cost-effective control options be applied. Based upon that info rmation, ADEQ was also ab le to calculate the average cost effectiveness in te rms 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 bene fits to the other Class I areas.

4Step 7: Select BART

ADEQ: Based upon its review of CPSI’s analysis, and in particular the marginal visibility impact from the current facility operati ons and the magnitude of the dolla r per deciview costs in Table 7, ADEQ has determined that BART for control of NO

x from Power Boiler #2 is the current
emission limit of 0.7 lb/MMBtu.

NPS: ADEQ is proposing that BART be an emission ra te more than double th at 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 pr oposed or accepted by other sources and states. ADEQ has incorrectly evaluated the effectiveness and cost of the contro l options, and ignored the visibility benefits to multiple Class I areas. ADEQ’s BART analysis for Catalyst Paper is not acceptable.

SO
x BART Analysis and Determination

Step 1: Identify the Existing Contro l Technologies in Use at the Source

ADEQ: Power Boiler #2 has a SO 2 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 op tions 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 comp lete much of the upgraded scrubbe r 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 co nsider upgrading the scrubber to be an additional control option.

Add a second scrubber. A second scrubber could be added in order to cap ture 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 Effectiv eness of Re maining Technologies.

5According to the analysis perform ed 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 Qualit y Environm ental Impacts and Document Results

Cost of Compliance

During the course of CPSI’s review of the t echnically feasible control options, the company identified the expected amount of emissions redu ced by the application of each control option, as
well as the annualized cost and th e 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 SO 2 )

Upgrade Current
Scrubber /
Baseline Control 0 0 N/A

Add second

scrubber 3,743 $4,769,365 $1,274

1. This analysis assumes th e facility is current emitting SO 2 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 s how that addition of a
second wet scrubber would reduce SO 2 emissions by 10,764 tpy at $901/ton at the same annual cost that ADEQ assumes to remove 3,743 t py 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 withou t 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

67 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 th e additional use of 38 million gallons of water

per year.

Step 6: Evaluate Visibility Impacts

As part of its analysis of potential BART opti on, CPSI estimated the total visibility improvement that is projected to occur should one of the tec hnically-feasible and cost-e ffective control options be applied. Based upon that info rmation, 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 2 nd 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 bene fits to the other Class I areas.

Step 7: Select BART

ADEQ: Based upon its review of CPSI’s analysis, a nd the all of the considerations listed above, ADEQ has determined that BART for control of SO 2 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 su bmitted a second letter to ADEQ. In that letter, APS West Phoeni x 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 disper sion modeling analysis using the assumptions identified above, the 98 th percentile visibility impacts that ADEQ had predicted in the Superstition Wilderness and the Mazatzal Wildernerss area s dropped from 0.69 dv and 0.64 dv, to 0.24 dv and 0.31dv respectively.

Based on the revised air dispersion modeling an alysis that was submitted on October 7, 2007,
APS West Phoenix stated that it did not cause or contribute to regional ha ze 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 mode ling 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 T itle V permit that would have provided APCC with the flexibility to choose betwee n 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 modificati ons 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 avoide d New Source Review when comple ting modifications to Kiln 4 in 1998. EPA also objected to the issuance of th e proposed Title V permit, but later lifted its objection after ADEQ removed the a lternative operating scenarios that would have allowed for further modification of the facility. A consen t decree is being finalized between APCC and EPA
to resolve the issue.

In 2008, ADEQ issued a new permit to APCC whic h would have allowed the facility to stop operations at all four existing kilns and cons truct and operate a new Kiln 6. The 18 month
construction window ended in June 2010 and APCC ha s since reapplied for a permit for the Kiln 6 expansion.

Based upon the consideration of the history of this facility, and the maximum 98 th percentile three-year average impact from all pollutants is less than 0.5. dv, ADE Q concurs that APCC is not subject-to-BART.

1NPS: W e disagree with the exemption based on "the maximum 98 th percentile three-year average impact from all pollutants is less than 0.5 dv". The BART exemption criteria should be that any
98 th percentile impact from all po llutants in any of the three modeled years is less than 0.5 dv. Further, as discussed in our technical commen ts, 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 8 th 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 8 th 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 f acility did not cause or contribute to visibi lity 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 visi bility impairment within the Grand Canyon National Park. As a result, CLC determined that the results of the anal ysis indicated that the 3-year average of the 8 th
highest visibility change was less than 0.5 dv in all Class I area s within 300 km of the facility,
and concluded that its Nelson f acility was not-subject-to-BART.

The company also recognized, however, that the predicted impacts w ithin the Grand Canyon were marginally below 0.5 dv. As a result, th e company stated that “[a]lthough the maximum visibility change obtained in the screening modeli ng analysis is not equal to or greater than the 0.5 dv contribution threshold, a refi ned analysis was performed in which light extinction in the Grand Canyon National Park was calculated us ing the CALPOST-IMPROVE implementation of the revised light extinction algorithm...” Based upon the refined analysis, the 98 th percentile (8 th
highest) Visibility Change in the Gra nd Canyon was calculated to be as follows:

98 th Percentile (8 th highest) Visibility Change (dv) Class I Area

2001 2002 2003 Average
Grand Canyon NP 0.417 0.375 0.585 0.46

Based upon the consideration of th e analysis performed for this facility, CLC’s conservative approach for estimating emissions impacts duri ng the meteorological period, and the maximum
98 th percentile three-year average impact from all pollutants is less than 0.5. dv, ADEQ concurs that the Chemical Lime Company’s Nels on Lime Plant is not subject-to-BART.

2NPS: Please provide the Septem ber 21, 2007, CL C 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 SO 2 emissions

(lb/hr) NO X emissions

(lb/hr)

Kiln 1 215.59 122.14

Kiln 2 484.27 182.78

Why were the PM emissions not included? A ll 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 98 th percentile impact from all polluta nts in any year is greater than
0.5. dv. The 98 th percentile impact at Grand Canyon NP in 2003 exceeded 0.5 dv. Further, the
FLM recommended that because the WRAP mode ling did not use upper air observations, the maximum impact, rather than the 98 th percentile impact, should be used with the annual average natural background visib ility conditions.

We conclude that the Chemical Lime Compa ny – Nelson Lime Plant is subject to BART.

TEP – Irvington Generating Station

ADEQ states : Regarding Unit I4, TEP stat ed that during the 1980s, Un it I4 was converted to burn coal in accordance with a prohi bition 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 Regi ster Vol. 46, p. 37960. In its January 2, 2007, letter, TEP stated that complian ce 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 co st 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 reconstr ucted 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 mo difying TEP Irvington’s Unit I4 is greater than 50 percent of the fixed capital cost of a compar able, entirely new source, and that Unit I4 was reconstructed in
the 1980s.

3In Federal Register, Vol. 70, No. 128, W ednesday, July 6, 2005, pages 39110-39112, EPA discusses Step 2 in determining whether a f acility is BART-eligible. According to the background statement in the guidance:

“Step 2 also addresses the treatment of ‘rec onstruction’ and ‘modifications.’ Under the definition of BART-eligible facility, sour ces which were in operation before 1962 but reconstructed during the 1962 to 1977 time period ar e 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, wh ich 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 ex isting 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 fac ility (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 exis tence’ tests apply to reconstruc ted sources. If an emissions
unit was reconstructed and be gan actual operation before A ugust 7, 1962, it is not BARTeligible. Similarly, any emissions unit for whic h a reconstruction ‘comme nced’ 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 reconstruc ted after August 7, 1977, but was exempt ed 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 re construction. As a resu lt, ADEQ concurs that the reconstructed Unit I4 at TEP’s Irvington Genera ting Station was not “i n existence” prior to August 7, 1977. Therefore, ADEQ has determined that there are no BART-eligible emissions units at TEP’s Irvingt on 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.

45 ASARCO Hayden Smelter

For SO 2 , we participated in the WRAP group that repo rted that “[a] double c ontact acid plant is considered the appropriate retrofit control equi pment” 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 SO 2.

For PM10, ADEQ concluded that the PM10 emissions from the BART-eligible units are lessthan 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 determin ation of BART for SO2 or for NOx if a BART-eligible source has the potential to emit less th an 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 em issions units at the AS ARCO smelter are not BART-eligible for PM 10 emissions."

Freeport-McMoRan Miami Smelter

We concur with ADEQ’s conclusion that the NESHAP for Primary C opper Smelting constitutes
BART for PM emissions.

We participated in the WRAP group that repor ted that “[a] double c ontact acid plant is considered the appropriate retrofit control equi pment” 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 SO 2.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 an ticipated to meet milestone required under the original 51.309 submittal. ADEQ must reconcile the inventory diffe rences between original milestone reductions
under 51.309 and those that would be realized as a result of SO 2 BART reductions now required under the 51.308 portion of the Regional Haze Rule.

The statewide SO 2 emissions inventory presented in Ta ble 8-1 do not comport with the PSAT modeling results presented in Chapter 9. Accord ing to Table 8-1, Ariz ona anticipates a 28.81% decrease in point source SO 2 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 docum ent the technical basi s 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 Partners hip (WRAP) Technical Suppor t System (TSS) and emission inventory data. Chapter 9 describes the air qu ality 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 A pportionment Technique (PSAT) or the Weighted Emissions Potential (WEP) processes, which ar e crucial to understandi ng the utility of the various assessment methodologies the state relies upon to set its reasonable progress goals. WEP
and PSAT use different emission inve ntories which should be clarifie d to aid the interpretation of visibility projections. Additional information re garding the methodologies should be included in this chapter.

Additionally, Chapter 9 does not provide perf ormance evaluations of either prognostic meteorological model data or the base case resu lts from the WRAP Base02d inventory used in the regional air quality models, CMAQ or CAMx. Without an unde rstanding of model performance, we cannot conclude that the state’s model is r easonably reliable nor understand
inherent model nuances that can aid in our understanding of the model results.

Chapter 10: Best Available Retr ofit Technology (BART) Evaluation

The Forest Service concurs with the initial comments provided by the Department of Interior on Arizona’s BART exclusion process. Sp ecifically, 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 init ial 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 st ates use either the maximum visibility impactwith the annual average natural condition or the 98 th percentile impact w ith 20% best natural conditions. In this SIP, Arizona has used the 98 th percentile impact with the annual average natural condition. We request that so urces 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 demo nstrate reasonable progress in visibility improvement by 2018 for the 20% worst days and to protect visibility on th e 20% best days. In mandatory Class I areas in Arizona, the plan go als 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 suppo rting 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 incr emental increases in anthropogenic impacts at most Arizona Class I areas, and also allow for de gradation in the least im paired 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 anthropoge nic emissions at a
number of Arizona Class I areas.

1. Section 9.3.1 – Chiricahua NM, Chiricahua WA, and Galiuro WA: PSAT results for SO 4 and NO 3 (Figure 9-11 and 9-12) show incr eases in the AZ point category.

2. Section 9.3.2 – Grand Canyon NP: PSAT results for SO 4 and NO 3 (Figure 9-13 and 9- 14) also show an increase in the AZ poi nt category over the baseline period.

3. Section 9.3.3 – Mazatzal WA and Pine Mountain WA: PSAT results for SO 4 and NO 3 (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 SO 4 (Figure 9-17) shows nearly steady SO 4 impacts from AZ point and NO 3 (Figure 9-18) shows an increase from AZ point category.

5. Section 9.3.5 – Petrified Forest NP: PSAT results for SO 4 and NO 3 (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 SO 4 and NO 3 (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 SO 4 and NO 3 (Figure 9-23 and Figure 9-24) show an increase from AZ point sources.8. Section 9.3.7 – Sierra Ancha WA: Fi gure 9-25 shows an increase in SO 4 impact from AZ point category.

9. Section 9.3.8 – Superstition WA: PSAT results for SO 4 and NO 3 (Figure 9-27 and 9-28)
show increases in th e AZ point category.

10. Section 9.3.10 – Sycamore Canyon WA: PSAT results for SO 4 and NO 3 (Figure 9-29 and 9-30) show increases in the AZ point category.

In Section 11.3.3 – Non-BART Sour ces, the Forest Service strongly disagrees with the adequacy of the Arizona reasonable progress analysis, especial ly in lieu of the reality that the uniform rate of progress is not being met for either SO 4 or NO 3 at any of the Arizona Class I areas. The SIP identifies a several source categories for whic h no attempt was made to complete a reasonable progress analysis. This is also problematic inasmu ch as the PSAT results indicate increases in point source impacts from Ar izona sources between 2002 and 2018.

Chapter 12: Long Term Strategy

Section 12.4 – Other States’ Cl ass I Areas Affected by Ariz ona Emissions discusses the contribution of Arizona to neighboring states’ Cl ass 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 n ecessary to achieve the re asonable 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 orde r 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 ob ligations agreed upon through that process.

First, the State must demonstrate that it has includ ed all measures necessary to get its share of the emissions reductions needed to meet the progre ss goal for the area. The discussion in Section 12.4.1 is presented in terms of the state level cont ribution for aggregate visi bility 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 examina tion of the reasonable progress of specific Class I areas. Second, we do not believe th at Arizona’s emission reduction measures aresufficient to meet this requirement given that in cremental 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.RESPONSI VENESS SUMMARY Comments Taken at the Public Hearing a nd 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 Recommendation s, 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 co ntinued 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 ADE Q recognize the role Rayleigh scattering by air molecules. APS suggest that ADEQ include a paragr aph 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 f unding and maintenance of IMPROVE.

Chapter 6 – Arizona Class I Area Baseline, Na tur al Conditions, and Uniform Rate of Progress

(4) Comment: Section 6.3, Monitoring Data. APS sugg ests 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” w ith “Table 6 -3” in the fourth paragraph, because there is no such figure include. Furthermore, since Ta ble 6 – 2 appears on page 39 (and Table 6-3 is on page 40), APS recommends the order of Ta bles 6-2 and 6-3 be reversed.

Response: ADEQ has revised the narrative and clarified the reference to Table 6.3.

1Chapter 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 specifi c dates of elevated OC and compare to Arizona fire activity data, because the contributions are more co mplicated 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 regardin g 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 Ariz ona’s BART sources and compare those modeling assumptions to the final emissions limits for sulfur dioxide (SO 2 ) and nitrogen oxides (NO X ) 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 PRP 18b 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 SO 2 emissions from point sources will decrease by 2018; however, SO 2 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 a pportionment analyses in Chapter 9 that project that Arizona’s contribution to sulfate (SO 4 ) will increase at several Class I areas.

Response: ADEQ has researched the matter regarding c opper smelters and has determined that the projected emission increase of 13,273 tons per year from the 2 smelte rs 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 decr ease 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 S0 2 primary standard.

The emissions inventories in the SIP (Chapter 8) are plan02d and PRP18b. Th e 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 curre nt inventories (plan02d and PRP18b). The base18b inventory shows an increase in SO 2 emissions from Arizona point sources. The PRP18b inventory shows a
decrease in SO 2 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 SO 4 from point sources.

(8) Comment: Table 8.2 indicates that NO X 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 agains t the actual emissions from 2002 does not reflect that

2co mpanies 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 fi re is the major source category for volatile organic carbon (VOC), primary organic aerosols (POA), and elemental carbon (EC). Em issions 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 WR AP 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 c onsented 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 SO 2 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 effo rt from the emissions inventory that was conducted by those states participating in the original 30 9 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 SO 2 emissions inventory compared to BART.

(11) Comment: The statewide SO 2 emissions inventory does not comport with the PSAT modeling results. The emissions inventory shows a decrease in SO 2 emissions from Arizona, yet PSAT modeling shows
increases in SO 4 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 SO 2 emissions from Arizona point sour ces. The PRP18b inventory shows
decreases in SO 2 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 SO 4 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 cha nges is dependent on the model’s skill in representing atmospheric chemistry and transport. In general, model performance is better for SO 4 and EC and less accurate for nitrate (NO 3 ) and OC.

3Response: ADEQ has add ed 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 Emissi ons Potential (WEP) processes. WEP and PSAT use different emissions inventories, which should be clarified to aid the interp retation of visibility projections. Additional information regarding the methodol ogies 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 performan ce 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 informa tion 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 co mment 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 project ed to increase by 2018 at every Class I area and organic carbon is projected to increase at Chirica hua (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 proj ected 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 Poten tial (WEP) indicates these increases are due to area sources and sources of fugitive dust. The WEP modeli ng 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 CH IR1 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 reasona ble progress is whether the PSAT modeling supports that

4Arizona’s contributi on to pollutant co ncentrations is decreasing. PSAT indicates that the contributions of Arizona’s point sources to SO 4 concentrations will increase by 2018 at Chiricahua, Mazatzal, Petrified Forest, Saguaro, Superstition, Sierra Ancha, and Sycamor e. Please discuss the ba sis for this increase. Projected increases in SO 2 emissions from the two copper smelters (assigned to Gila County) may explain
the increases in SO 4 concentrations at the Class I areas.

Response: The 2018 inventory (PRP18b) is the mo st 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 SO 2 standard proposed by EPA and reductions associated with implementation and compliance with the new standard. The emissions i nventories in the SIP (Chapter 8) are plan02d and PRP18b. The PSAT results were modeled by WRAP using the plan02c and base 18b emissions inventory, which were developed in December 2005, and were not re-modeled using the current inventories. The base18b inventory showed an increase in SO 2 emissions from Arizona point sources. The PRP18b inventory
shows decreases in SO 2 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 SO 4 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 SO 2 emissions will decrease significantly from baseline
levels as a result of the efforts of the tw o facilities to comply with the new 1-hour SO 2 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 SO 4 emissions when SO 2 emissions were intended.

Response: ADEQ has made the appropriate corrections.

(19) Comment: PSAT modeling shows that NO 3 concentrations due to NO X emissions from Arizona point sources will increase by 2018. Increases in SO 4 and NO 3 contributions from Arizona point sources are not consistent with ADEQ’s assertion that the state has ma de reasonable progress toward improving visibility in
Class I areas in Arizona.

Response: The emissions inventories in the SIP (Cha pter 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 Decem ber 2005, and were not re-modeled using the current inventories. The base18b inventory showed an increase in SO 2 and NO X emissions from Arizona point sources. The PRP18b inventory shows decreases in both SO 2 and NO X from point sources in Arizona. ADEQ expects that if PSAT was run using the current inventory (PRP18b), there would be reduced
contribution to SO 4 or NO 3 from point sources. ADEQ notes that vi sibility 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 suppor t ADEQ’s conclusions that PM is largely due to
natural sources and therefore does not need to be cons idered in the reasonable progress analysis. It is recommended that ADEQ consider measures to re duce anthropogenic PM in the reasonable progress analysis.

Response: ADEQ addresses measures to reduce anth ropogenic PM in the l ong-term strategy. The
nonattainment and maintenance areas for PM 10 in Arizona contain measures to control PM 10 from human

5activities. ADEQ addressed the anthro pogenic 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 draf t) 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 WR AP BART Modeling Protocol, the Federal Land Managers (FLM) recommended that the WRAP BA RT 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 98 th percentile visibility impact with the 20% best natural conditions. ADEQ is reporting
98 th percentile visibility impact with annual average natu ral conditions, which is not consistent with good modeling practices as identified by 40 CFR 51 Appe ndix W or EPA’s Model Clearing House memorandum. Use of a non-guideline modeling approach requires a dditional evaluation of pe rformance 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 CA LMET diagnostic wind model that produces unphysical meteorological fields. The use of upper-air observa tions 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 th e 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 98 th percentile impact as
either the maximum 8 th highest value in any single year or the 22 nd highest value for three years combined, whichever is more conservative. ADEQ used the 8 th highest value averaged over three years, which is a less conservative metric. Had ADEQ used the 8 th highest value in a single year, Chemical Lime Nelson Plant would not have been exempted from BART. We requ est that ADEQ re-evaluate the BART determination and use the more rigorous criteria.

6Response: 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 th ere is no established regulatory de mi nimis 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 cons istent with that determination.

(25) Comment: The Forest Service concurs with comme nts 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 in corporation of upper atmos pheric 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 98 th percentile impact with 20% best natural condition. In this SIP, Arizona has used the 98 th percentile impact with the annual average natural condition. We require that sources that were determined to no t 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 Servi ce’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 BA RT Modeling Protocol and used by CH2MHill for Arizona Electric Power Cooperative’s Apache Generating Station. We r ecommend that the same levels be
used for Comanche and C holla Generating Stations.

Response: ADEQ is not aware of any recent ammonia monitoring conducted in the area around either
Coronado or Cholla Genera ting Stations that would support higher b ackground ammonia inputs. In addition, NPS has not provided any specific details regarding any su ch monitoring as part of their comments. In the absence of such information, ADEQ has determined th at the modeling assumptions that were made by the sources are appropriate.

7BART Costs and Benefit Analyses

(27) Comment: The FLMS and NPS have developed a na tional data base of cost s 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 NO

x emissions and have overestimated the costs of SCR installation and operation. Although there are several methods fo r 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 th e 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 fu ture and compare them against current cost thresholds.

Response: ADEQ has determined that the cost comput ations presented by the facilities in support of their BART applications are reasonable. Many of the co mputations 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 factor ed 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 Tec hnical Support Document indicates that ADEQ selected the least cost control option (low NO

x burners, existing PM and SO 2 controls) even when more effective controls were identified in the $1500-2000 range.

Response: The BART regulations codified under 40 CF R 51 Appendix Y reference the dollar per ton ($/ton) metric and specify its use in the BART evaluation pr ocess. ADEQ used both the dollar per deciview ($/dv) and $/ton metrics in its BART analyses. Using the $ /ton metric solely would re nder 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 impor tant 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 we re 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 re ported. The BART Guidelines represent an attempt to create a workable approach to estimating visibility im pairment. 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 ther e 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 c ontrols 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 cumula tive dollar per deciview values in its evaluation. Maximum visibility impacts from a facility could be at different locations, under different meteorological

8conditions, and at different tim es w ithin 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 pr ovided in the introduction of the BART documentation allowing direct access to the more detailed an alyses for each facility that directly follows.

BART Recommendations

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

(31) Comment: For NO X , the FLMs and NPS recommend SCR for Apache Units 2 and 3 rather than Low

NO X Burners with Over Fired Air as proposed by ADE Q. Our cost estimate for SCR is $1,500 - $1,700 per ton based on an annual average NO X emissions rate of 0.05 lb/mmBtu.

Response: ADEQ respectfully disagrees with the r ecommended BART strategy. ADEQ conducted its 7-step BART analysis incorporating the 5-step process refere nced in 40 CFR Part 51, using the best available information. As mentioned in the Department’s resp onses 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 relativ e to the expected visibility improvement. ADEQ is retaining its BART
decision.

(32) Comment: For SO 2 , the FLMs and NPS recommend that ADEQ require the existing scrubbers to
achieve at least 90% SO 2 removal with an annual average SO 2 emissions limit not to exceed 0.12 lb/mmBtu.
The FLMs and NPS concur with ADE Q’s BART determination for PM.

Response: ADEQ acknowledges the comment for the PM BART, but respectfully disagrees with the recommended BART strategy for SO 2 . 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 NO X , the FLMs and NPS recommend SCR for Cholla Units 2, 3, and 4 rather than Low

NO X 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 NO X emissions rate of 0.05 lb/mmBtu.

Response: ADEQ respectfully disagrees with the r ecommended BART strategy. The Department conducted its 7-step BART analysis incorporating the 5-step pr ocess referenced in 40 CFR Part 51, using the best available information. As mentioned in the Depa rtment’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

9process is not an em ission reduction technology eval uation 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 SO 2 , the FLMs and NPS recommend that ADEQ require the existing scrubbers to
achieve at least 90% SO 2 removal with an annual average SO 2 emissions limit not to exceed 0.12 lb/mmBtu.
The FLMs and NPS concur with ADE Q’s BART determination for PM.

Response: ADEQ acknowledges the comment for PM BART. The Department r espectfully 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 usi ng best available information. The Department is retaining its BART decision. Additionally, the Depart ment 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 tho se 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 NO X , 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 r ecommended BART strategy. The Department conducted its 7-step BART analysis incorporating the 5-step pr ocess 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 SO 2 , the FLMs and NPS concur with Wet Flue Gas Desulfurization for both units with
an associated SO 2 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 th e proposed 0.03 lb/mmBtu BART limit “is already meeting or exceeding the stringency of the emissions limit ation” and “for similar emissions units with similar
emissions controls” is not consistent with its Cholla BART analysis whic h 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 Co ronado be re-evaluated.

Response: PM emissions from both units are currently controlled with hot-side ESPs. Salt River Project (SRP) proposed a filterable PM/PM 10 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

10Technolog y analysis that was performed for Unit 2 at CGS as part of the significant revision application that was submitted in 2008. The analysis demonstrated th at 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 fo r 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/PM 10 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 NO X emissions rate evaluated for control measures and proposed by ADEQ as BART is twice as high as the uncontrolled NO X 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 visi bility benefits to multiple Class I areas have not been included. The BART analysis for NO X is unacceptable and needs to be redone. The BART analysis for

SO 2 is flawed with unsupported costs and underest imated benefits. The BART analysis for SO 2 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 s ubmittal. 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 s ite 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 th e exemption criteria were incorrectly applied. We request the visibility impacts be evaluate d 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 visibili ty impacts evaluation was made following appropriate protocols that were uniformly applie d 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

11tons 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 s ite 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 Guid elines 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 interp retation is that Unit I4 needs to be evaluated under

BART.

Response: Neither EPA rules in 40 CFR Part 51 no r BART guidance documents require a source to have gone through NSR to be exempt from BART eligibilit y. ADEQ’s determination is that Unit I4 was reconstructed after August 7, 1977, an d 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 Perfo rmance Standard of 650 ppm constitutes BART for

SO 2. The FLMs and NPS disagree with exempting the PM 10 emissions from BART; in the BART guidelines
the PM 10 level for exemption is 15 tons per year (tpy), not 250 tpy.

Response: ADEQ acknowledges the comment about SO 2 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 Perfo rmance Standard of 650 ppm constitutes BART for

SO 2. The FLMs and NPS also agree that the NESHAP for Primary Copper Smelting constitutes BART for

PM.

Response: ADEQ acknowledges the comment.

12Gene ral 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 th at 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 informa tion provided by the applicants. It is the Department’s understanding that such info rmation was based partially on feedback received from vendors and plant personnel who are intimately familiar w ith the specific equipment that is being considered. In that regard, the Department based its BART comput ations 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 environmen tal 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 transpor ted safely but acknowledges there is added risk in its transport and handling. Based on the comment regardi ng 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 NO X on AEPCO’s ST2 and ST3, ADEQ has dete rmined that BART is the new lowNO X burners (LNB) with overfire air (OFA) system w ith a NOx emission limit of 0.31 lb/MMBtu for both ST2 and ST3. AEPCO would like to clarify that new LN Bs would be installed, but the fully functional, existing OFA would be utilized.

Response: ADEQ appreciates AEPCO’s clarification a nd 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 PM 10 emission limit 0.0015 lb/MMBtu listed for fuel oil combustion anticipated the installation of LNB. The PM 10 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. B ased 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 NO X on AEPCO’s ST1, ADEQ has determined th at 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

13unit is com bined cycle with gas turbine 1 (GT1), AE PCO would like to propose combustion with PNG only, in combined cycle operation with all exhaust gas fro m GT1 recirculated into ST1 (the combined cycle operating configuration represents FGR), and installation of LNB as BART.

Response: ADEQ acknowledges the comment. B ased 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 fund amental 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 C holla 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 NO X . APS reviewed ADEQ’s letter and recognized that the information used in determin ing BART eligibility for West Phoenix was flawed and not updated. On September 30, 20 07, APS submitted a letter to ADEQ detailing the flawed assumptions and errors set forth in the June 13, 2007 letter. APS comm itted 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 im pairment 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 SO 2 , NO X , and PM on Cholla Units 2, 3, and 4. It is important to note that visibility improvements resulting from all NO X control scenarios are less than 0.5 dv. The difference between the application of NO X combustion controls (LNB and SOFA) and the application of Selective Catalytic Reduction (SCR) t echnology 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

14justified. Therefore, APS agrees with ADEQ’s decision to establish NO X BART for Cholla Steam Unit 2, 3,
and 4 as LNB and SOFA.

Response: ADEQ acknowledges the comment.

(57) Comment: ADEQ should recognize current discussi ons involving changes to the CALPUFF model that ADEQ used to assess the visibility impacts of its propo sed 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-pre dicts nitrate formation and consequently likely overstates the associated visibility degradation, the De partment 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 emis sions from CGS, this approach recognizes that a BART emission limit that requires the implementation of Se lective Catalytic Reduction (SCR) cannot be justified due to the significantly higher cost of this technolog y and the small visibility improvements that is expected to be achieved. In addition, ADEQ properly reco gnizes that the “reasonable progress” provisions of the Federal Regional Haze Rule will allow additional opportunities to evaluate whether still more NO X 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 re ject 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 regulator y basis. As noted in the Federal Regional Haze Rule, states have broad discretion in establishing BART for stationary sources us ing 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)). Similarl y, the Clean Air Act and BART rules assign to the states the responsibility for making BART determina tions 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 th e decision makers” with respect to “which sources are subject to BART” or “how States make BART determin ations.” EPA also conceded that it cannot prescribe “specific control measures a st ate must implement in its initial SIP for regional haze. That determination can only be made by a state once it has conducted the necess ary 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 th at 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

15and 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 enha nce 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-pre dicts nitrate formation and consequently likely overstates the associated visibility degradation, the De partment is taking the conservative position of using the prior modeling results.

(61) Comment: SRP would like to propose to revise wh at appears to be a typographical error in the proposed SIP. In Section XIV of Appendix D, Table 3, baseline NO X emissions from both Units 1 and 2 at
CGS are listed as 0.433 lb/MMBtu. Baseline NO X emissions from Unit 2 should be 0.466 lb/MMBtu. SRP believes that the modeling results presented in the appendi x 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 l eeway 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 Arizonaproposes to require as BART do not represent costeffective control options. Arizona should clarify that th e $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 installe d regardless of the outcome of the BART analysis. Arizona could also simply omit the cost-effectiveness ca lculation altogether where the source does not seek to rule out a control option on the basis of cost-effectiv eness, similar to the approach taken for controls that have already been installed (e.g., the scrubbe rs 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 he lp the state determine whether additional controls may be imposed on non-BART eligible sources. Even th ough 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 en sure that Arizona not only meets but exceeds its established RPGs. As noted in the proposed Regional Haze SIP, additiona l 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 pote ntial control options fully

16co mplies 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 NO X and SO 2 , and no longer than a 30-day rolling average for an emission limit.

Response: ADEQ agrees with the comment and langua ge has been added regarding the compliance and averaging methods.

(66) Comment: To determine the feasibility of emission c ontrols, 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 CF R 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 th e 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 determin ation. Since the goal of the regional haze program is to identify cost-effective technology solutions to ad dress 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 c onditions, and at different times within multiple Class I areas; adding up visibility improvements across the board would result in an err oneous depiction of the visibility improvement that can be expected.

(67) Comment: The analysis must clearly state how each f actor is weighted in arriving at the conclusion on BART. For example, both $/ton and $/dv appear reasona ble 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 res ponse to comment 67, the Depa rtment’s 7-step process incorporated the EPA recommended 5-factors and evalua ted figures for dollar per ton, dollar per deciview, and incremental visibility improvement to make its BA RT determinations. The Department did not apply any pre-determined weighting for these factors. Th e general concept driving the decision-making process was to identify cost-effective control strategies that w ould 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-NO X 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) Comme nt: In analyzing sources that burn various coal types with different levels of SO 2 , 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 specifi c pound per million Btu values
and those values have been determined to be the BA RT limit, and they will ensure that the modeling assumptions are truly enforceable.

(69) Comment: The analysis of the two smelters s hould clarify the fugitive emissions numbers, fugitive emission control techniques, and the basis for the SO 2 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 SO 2 control for primary converter gases to reduce SO 2 emissions from the facility. In 1983, ASARCO replaced twelve multiple-hearth roasters a nd 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 th is addition, the company was able to replace the existing single contact acid plant with a new double-contact acid plan t. The emissions reductions resulting from these projects were estimated to be 63,584 tons per year of SO 2 . According to ASARCO’s calculations, the double-absorption acid plant recovers 99.81 percent of the SO 2 emissions that are vented to it. In 1992,
ASARCO made a modification to the smelter’s exis ting 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 vent ed 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 SO 2 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.

SO 2 emissions based on 2006 permit renewal application are as below:

Emission unit/activity SO 2 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

18Emission unit/activity SO 2 Emissions, tpy

Flash furnace fugitives 1,078

Converter fugitives 2,257

In anticipation of the new 1-hour SO 2 primary National Ambient Air Quality Standards (NAAQS), the company continues to evaluate additional SO 2 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) We t 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 Em issions Standards for Hazardous Air Pollutants (NESHAP) for Primary Copper Smelting. The NES HAP identifies several operating and maintenance practices that will have the effect of optimal captu re 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 SO 2 primary National Ambient Air Quality Standards (NAAQS), the company continues to
evaluate additional SO 2 capture and control options.

SO 2 emissions based on 2010 permit renewal application are listed in the table below:

Emission Unit/Activity SO 2 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 analys is undertaken by Arizona to dete rmine appropriate and attainable Reasonable Progress Goals (RPGs) for the 2008 to 2018 pl anning 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 Pr ogress (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.

19Arizona’s decision to take a prag matic, realistic approach to establishing attainable goals for visibility improvements in spite of these challenges is commendable. Despite the inab ility to regulate natural emissions sources or emissions sources in other ju risdictions, 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 whet her even greater visibility improvements are possible with additional control requirements. Arizona’s commi tment to continue investigating possible emissions control technologies before the next SIP revision w ill help ensure continued progress toward the natural visibility conditions goal. Arizona’s proposed Regional Ha ze SIP represents an appr opriate 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 Ru le requires that states ensure no degradation in visibility for the least impaired days. Visibility pr ojections however, show de gradation 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 condition s 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 mo deled 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 concentrati ons, 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 SO 2 from point sources in Mexico are projected to increase by approximately 150,000 tpy by 2018. CMAQ modeling projections show that SO 2 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 ar e 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

20potential for sources of natural fire to i mpact visibility on best days is approximately 62% and 76% at CHIR1 and SAGU1, respectively, which is a much la rger 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 fug itive 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 s ources of road dust and fugitive dust is about 20% (increase of 7%) and 89% (increase of 52%), respec tively. 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 SO 2 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 monito rs. Another factor contributing to de gradation is the impact of natural sources of organic carbon, which is approximately si x times the contribution from area sources of organic
carbon at CHIR1 and SAGU1. While the contribution fro m 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 h as 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 prim ary 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 anthropogeni c 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 pr ojected 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 calcula tion 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/we b/AnnualSummaryDev/Trends.aspx).

Response: ADEQ acknowledges the suggestion and has decided to not include the information. The Visibility Information Exchange Web System (VIEWS) tr end analysis is not capable of providing a revised deciview for 2018 projections; however, the analysis does point out that for SAGU1 and CHIR1 (the

21m onitors showing degradation on best days), the vi sibility 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 na tural background visibility will be achieved at the Arizona Class I areas under the lower rate of progress.

Response: ADEQ has calculated revised URPs using th e 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 Sm oke 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 SO 2 and NO X 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 cate gories such as agricultural and construction practices
and residential wood smoke.

Response: ADEQ acknowledges the suggestion. EPA rul es 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 SO 4 and NO 3 at Class I areas in Arizona. The table
indicates Arizona’s contribution to SO 4 is 7-24% and to NO 3 is 7-53%.

Response: ADEQ has corrected the discrepanc y in the percentages reported in the table.

(78) Comment: ADEQ identifies major source categories for SO 2 and NO X emissions (Table 11.2). The FLMs and NPS disagree with ADEQ’s assumption that vi sibility benefits from emissions reductions from
these sources will be minimal. If the sources are located n ear Class I areas, the visibility benefits of controls
could be substantial.

Response: ADEQ did not evaluate the visibility impact s 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 visib ility impacts were expected to be minimal, without a more comprehensive analysis, such a statement ca nnot be supported and ADEQ removed it from the SIP prior to public comment.

22For reasonable progress to wards long-term visibility im provement goals ADEQ include d its analysis of nonBART sources in Chapter 11. This analysis included all sources that had actual emissions over 40 tons per year of NO X and SO 2 . In analyzing the inventory of sources, ADEQ determined that the evaluation could be meaningfully conducted by categoriz ing 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 comprehensiv e 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 Depa rtment 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 id entifying specific sources and emissions that may be candidates for controls under reasonable progress has changed. As a r esult, the tables were no longer representative of the
narrative and were removed.

(80) Comment: EC/R developed a Four-Factor Analys is Report for WRAP c overing industrial boilers, cement manufacturing, lime kilns, and internal co mbustion 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 in formation in the report titled “Supplementary Information for Four Factor An alyses 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 tec hnology options appeared to be derived from a generic costing tool called AIRControlNet. Additionally, severa l 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 reasonabl e 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 authorit y to select the threshold used for reasonable progress. There is no rationale provided for selecting a lower th reshold. Using a lower visibility threshold wouldpotentially subject non-BART sources to a more rigorous and more onerous process than sources subject-toBART without providing visibility benefit. The cha nges 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.

23Response: ADEQ acknowledges the comment.

(83) Comm ent: 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 guidan ce for a more comprehensive review of individual sources over the next five years to identify any additiona l emission reductions that c ould 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 measur es are under continuing review for the purposes of ongoingplanning 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 NO X , PM, and SO X measures based on current and future revisions to the NAAQS for 8-hour ozone (lower standard to be announced June 2011); SO 2 (new standard announced June 2010); NO 2 (new standard announced January 2010); secondary NO 2 and SO 2 (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 SO 2 . (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 inform ation and analysis to demonstrate whether additional
controls are needed on non-BART sources in order to ach ieve 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 al l sources that had actual emissi ons over 40 tons per year of NO X and

SO 2 . In analyzing the inventory of sources, ADEQ dete rmined that the evaluation could be meaningfully conducted by categorizing the inventory based on the si gnificant 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 a nd 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 an alysis for exploring additi onal controls for visibility improvement. Due to a lack of any detailed rule requi rement 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 befo re 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 ra te of progress that the state selected as reasonable.

24Response: A DEQ 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 cu rrently or formerly nonattainment areas under the PM 10 National Ambient Air Quality Standard (NAAQS). These areas are required to have control measures in place to reduce PM from anthropogenic activities. Th e 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 ex isting 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 al so 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 pa rt 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 emissi ons 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 pr esenting the percentage contribution from Arizona to other Class I areas as well as tables presenting the percenta ge contribution from other states and regions to
Arizona’s Class I areas.

(90) Comment: The FLMs appreciate that ADEQ discu sses Arizona’s requirements for Prevention of Significant Deterioration (PSD) and New Source Revi ew (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 PM 10 nonattainment areas in Section 12.6 is very helpful. Do the PM 10 monitoring data demonstrate the effectiveness of these controls?

Response: There is evidence to support that mon itoring data demonstrates the effectiveness of PM 10 control
measures. EPA has made clean data findings for a number of PM 10 moderate planning areas in Arizona due to the implementation and enforcement of various R easonably Available Control Measures (RACM) as well as Best Available Control Measures (BACM) and Most Stringent Measures (MSM) in the serious

25metropolitan planning area. The annual average concentr ations at five monitoring stations in the greater Phoenix area show from 1990 to 2009, concentrations of PM 10 have decreased ten micrograms per cubic meter, or 24%. Expanding to 11 monitors, the concentr ations 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. re duced 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 sch edules 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 avoidi ng 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, Cl ass I areas are identified as sensitive receptors, and mitigating smoke impact to Class I areas is consid ered 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, th ey should be discussed in this section.

Response: Authority to develop and implement renewabl e or alternative fuels rest s predominantly with the federal government (e.g., CAFE standards for fuel efficien cy, boutique fuels, etc.). Under the authority of the Arizona Corporation Commission (ACC), rules th at 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 gene rate 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 th e 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 encourag e utilities to use solar, wind, biomass, biogas, geothermal and other similar tec hnologies 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 cons iderably 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 m onoxide SIPs, can be found on the Ar izona Department of Weights and
Measures Website at http://azdwm.gov/ . Emission reductions for mobile sources, however, have already

2627 been captured by the WRAP and are reflected in th e emission inventories and projections already cited throughout this SIP. (95) Comment: Section 12.7.3 is inte nded 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-te rm strategies for the November version of the SIP.

(96) Comment: Section 12.8 discusses the WRAP commitm ent 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 emissi ons reductions that were not included in the WRAP 2018 PRPb emissions inventory.

Response: As stated in the response to Comme nt #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 refere nces 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.