Vol. 79 Tuesday, 

No. 32 February 18, 2014 

Part II 

Environmental Protection Agency 

40 CFR Part 51 

Promulgation of Air Quality Implementation Plans; Arizona; Regional Haze 

and Interstate Visibility Transport Federal Implementation Plan; Proposed 

Rule 

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9318 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 51 

[EPA–R09–OAR–2013–0588, FRL–9906–30– 

Region 9] 

Promulgation of Air Quality 

Implementation Plans; Arizona; 

Regional Haze and Interstate Visibility 

Transport Federal Implementation Plan 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Proposed rule. 

SUMMARY: This proposed Federal 

Implementation Plan (FIP) addresses the 

requirements of the Regional Haze Rule 

(RHR) and interstate visibility transport 

for the disapproved portions of 

Arizona’s Regional Haze (RH) State 

Implementation Plan (SIP) as described 

in our final rule published on July 30, 

2013. Our final rule on Arizona’s RH 

SIP partially approved and partially 

disapproved the State’s plan to 

implement the regional haze program 

for the first planning period. Today’s 

proposed rule addresses the RHR’s 

requirements for Best Available Retrofit 

Technology (BART), Reasonable 

Progress Goals (RPGs) and Long-term 

Strategy (LTS) as well as the interstate 

visibility transport requirements for 

pollutants that affect visibility in 

Arizona’s 12 Class I areas as well as 

areas in nearby states. The BART 

sources addressed in this proposed FIP 

are Tucson Electric Power (TEP) Sundt 

Generating Station Unit 4, Lhoist Nelson 

Lime Plant Kilns 1 and 2, ASARCO 

Incorporated Hayden Smelter, and 

Freeport-McMoran Inc. (FMMI) Miami 

Smelter. The sources with proposed 

controls for reasonable progress are the 

Phoenix Cement Clarkdale Plant and the 

CalPortland Cement Rillito Plant. 

DATES: Written comments must be 

submitted to the designated contact at 

the address in the General Information 

section of SUPPLEMENTARY INFORMATION

on or before March 31, 2014. 

ADDRESSES: See the General Information 

section of SUPPLEMENTARY INFORMATION

for further instructions on where and 

how to learn more about this proposal, 

attend a public hearing, or submit 

comments. 

FOR FURTHER INFORMATION CONTACT: 

Thomas Webb, U.S. EPA, Region 9, 

Planning Office, Air Division, Air, 75 

Hawthorne Street, San Francisco, CA 

94105. Thomas Webb may be reached at 

telephone number (415) 947–4139 and 

via electronic mail at r9azreghaze@

epa.gov. 

SUPPLEMENTARY INFORMATION: 

Table of Contents 

I. General Information 

A. Definitions 

B. Docket 

C. Instructions for Submitting Comments to 

EPA 

D. Submitting Confidential Business 

Information 

E. Tips for Preparing Your Comments 

F. Public Hearings 

II. Proposed Actions Background and 

Overview 

A. Background 

B. Regional Haze 

C. Interstate Transport of Pollutants That 

Affect Visibility 

III. Review of State and EPA Actions on 

Regional Haze 

A. EPA’s Schedule To Act on Arizona’s RH 

SIP 

B. History of State Submittals and EPA 

Actions 

C. EPA’s Authority To Promulgate a FIP 

IV. EPA’s BART Process 

A. BART Factors 

B. Visibility Analysis 

C. Explanation of Visibility Tables 

V. EPA’s Proposed BART Analyses and 

Determinations 

A. Sundt Generating Station Unit 4 

B. Nelson Lime Plant Kilns 1 and 2 

C. Hayden Smelter 

D. Miami Smelter 

VI. EPA’s Proposed Reasonable Progress 

Analyses and Determinations 

A. Reasonable Progress Analysis of Point 

Sources for NOX

B. Reasonable Progress Analysis of Area 

Sources for NOX and SO2

C. Reasonable Progress Goals 

D. Meeting the Uniform Rate of Progress 

VII. EPA’s Proposed Long-Term Strategy 

Supplement 

A. Emission Reductions for Out-of-State 

Class I Areas 

B. Emissions Limitations and Schedules for 

Compliance To Achieve RPGs 

C. Enforceability of Emissions Limitations 

and Control Measures 

D. Proposed Partial LTS FIP 

VIII. EPA’s Proposal for Interstate Transport 

IX. Summary of Proposed Actions 

A. Regional Haze 

B. Interstate Transport 

X. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review 

B. Paperwork Reduction Act 

C. Regulatory Flexibility Act 

D. Unfunded Mandates Reform Act 

E. Executive Order 13132: Federalism 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

H. Executive Order 13211: Actions That 

Significantly Affect Energy Supply, 

Distribution, or Use 

I. National Technology Transfer and 

Advancement Act 

J. Executive Order 12898: Federal Actions 

To Address Environmental Justice in 

Minority Populations and Low-Income 

Populations 

K. Congressional Review Act 

I. General Information 

A. Definitions 

(1) The words or initials Act or CAA 

mean or refer to the Clean Air Act, 

unless the context indicates otherwise. 

(2) The initials ADEQ mean or refer to 

the Arizona Department of 

Environmental Quality. 

(3) The words Arizona and State 

mean the State of Arizona. 

(4) The initials BACT mean or refer to 

Best Available Control Technology. 

(5) The initials BART mean or refer to 

Best Available Retrofit Technology. 

(6) The initials BOD mean or refer to 

boiler operating day. 

(7) The term Class I area refers to a 

mandatory Class I Federal area. 

(8) The initials CEMS refers to 

continuous emission monitoring system 

or systems. 

(9) The initials dv mean or refer to 

deciview, a measure of visual range. 

(10) The words EPA, we, us or our 

mean or refer to the United States 

Environmental Protection Agency. 

(11) The initials FGD mean or refer to 

flue gas desulfurization. 

(12) The initials FIP mean or refer to 

Federal Implementation Plan. 

(13) The initials FLM mean or refer to 

Federal Land Managers. 

(14) The initials IMPROVE mean or 

refer to Interagency Monitoring of 

Protected Visual Environments 

monitoring network. 

(15) The initials IPM mean or refer to 

Integrated Planning Model. 

(16) The initials lb/MMBtu mean or 

refer to pounds per one million British 

thermal units. 

(17) The initials LDSCR and HDSCR 

mean or refer to low and high dust 

Selective Catalytic Reduction, 

respectively. 

(18) The initials LNB mean or refer to 

low NOX burners. 

(19) The initials LTS mean or refer to 

Long-term Strategy. 

(20) The initials MACT mean or refer 

to Maximum Achievable Control 

Technology. 

(21) The initials MW mean or refer to 

megawatts. 

(22) The initials NAAQS mean or refer 

to National Ambient Air Quality 

Standards. 

(23) The initials NEI mean or refer to 

National Emissions Inventory. 

(24) The initials NESCAUM mean or 

refer to Northeast States for Coordinated 

Air Use Management. 

(25) The initials NM mean or refer to 

National Monument. 

(26) The initials NOX mean or refer to 

nitrogen oxides. 

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(27) The initials NP mean or refer to 

National Park. 

(28) The initials NPS mean or refer to 

the National Park Service. 

(29) The initials NSCR mean or refer 

to non-selective catalytic reduction. 

(30) The initials NSPS mean or refer 

to new source performance standards. 

(31) The initials PM mean or refer to 

particulate matter. 

(32) The initials PM2.5 mean or refer 

to fine particulate matter with an 

aerodynamic diameter of less than 2.5 

micrometers. 

(33) The initials PM10 mean or refer to 

particulate matter with an aerodynamic 

diameter of less than 10 micrometers. 

(34) The initials PSAT mean or refer 

to Particulate Source Apportionment 

Technology. 

(35) The initials PSD mean or refer to 

Prevention of Significant Deterioration. 

(36) The initials PTE mean or refer to 

potential to emit. 

(37) The initials RH mean or refer to 

regional haze. 

(38) The initials RHR mean or refer to 

the Regional Haze Rule, originally 

promulgated in 1999 and codified at 40 

CFR 51.301–309. 

(39) The initials RMC mean or refer to 

Regional Modeling Center. 

(40) The initials RP mean or refer to 

Reasonable Progress. 

(41) The initials RPG or RPGs mean or 

refer to Reasonable Progress Goal(s). 

(42) The initials SCR mean or refer to 

Selective Catalytic Reduction. 

(43) The initials SIP mean or refer to 

State Implementation Plan. 

(44) The initials SNCR mean or refer 

to Selective Non-catalytic Reduction. 

(45) The initials SO2 mean or refer to 

sulfur dioxide. 

(46) The initials SOFA mean or refer 

to Separated Overfire Air. 

(47) The initials SRP mean or refer to 

Salt River Project Agricultural 

Improvement and Power District. 

(48) The initials tpy mean tons per 

year. 

(49) The initials TSD mean or refer to 

Technical Support Document. 

(50) The initials TSF mean or refer to 

tons of stone feed. 

(51) The initials ULNB mean or refer 

to ultra-low NOX burners. 

(52) The initials URP mean or refer to 

Uniform Rate of Progress. 

(53) The initials VOC mean or refer to 

volatile organic compounds. 

(54) The initials WRAP mean or refer 

to the Western Regional Air Partnership. 

B. Docket 

This proposed action relies on 

documents, information and data that 

are listed in the index on http://

www.regulations.gov under docket 

number EPA–R09–OAR–2013–0588. 

Previous proposed and final actions 

regarding Arizona’s RH SIP are under 

docket number EPA–R09–OAR–2012– 

0904 and EPA–R09–OAR–2012–0021. 

Although listed in the index, some 

information is not publicly available 

(e.g., Confidential Business Information 

(CBI)). Certain other material, such as 

copyrighted material, is publicly 

available only in hard copy form. 

Publicly available docket materials are 

available either electronically at http:// 

www.regulations.gov or in hard copy at 

the Planning Office of the Air Division, 

AIR–2, EPA Region 9, 75 Hawthorne 

Street, San Francisco, CA 94105. EPA 

requests that you contact the individual 

listed in the FOR FURTHER INFORMATION

CONTACT section to view the hard copy 

of the docket. You may view the hard 

copy of the docket Monday through 

Friday, 9–5 PST, excluding Federal 

holidays. 

C. Instructions for Submitting 

Comments to EPA 

Written comments must be submitted 

on or before March 31, 2014. Submit 

your comments, identified by Docket ID 

No. EPA–R09–OAR–2013–0588, by one 

of the following methods: 

• Federal Rulemaking portal: http://

www.regulations.gov. Follow the on-line 

instructions for submitting comments. 

• Email: r9azreghaze@epa.gov. 

• Fax: 415–947–3579 (Attention: 

Thomas Webb). 

• Mail, Hand Delivery or Courier: 

Thomas Webb, EPA Region 9, Air 

Division (AIR–2), 75 Hawthorne Street, 

San Francisco, California 94105. Hand 

and courier deliveries are only accepted 

Monday through Friday, 8:30 a.m. to 

4:30 p.m., excluding Federal holidays. 

Special arrangements should be made 

for deliveries of boxed information. 

EPA’s policy is to include all 

comments received in the public docket 

without change. 

We may make comments available 

online at http://www.regulations.gov, 

including any personal information 

provided, unless the comment includes 

information claimed to be CBI or other 

information for which disclosure is 

restricted by statute. Do not submit 

information that you consider to be CBI 

or that is otherwise protected through 

http://www.regulations.gov or email. 

The http://www.regulations.gov Web 

site is an ‘‘anonymous access’’ system, 

which means EPA will not know your 

identity or contact information unless 

you provide it in the body of your 

comment. If you send an email 

comment directly to EPA, without going 

through http://www.regulations.gov, we 

will include your email address as part 

of the comment that is placed in the 

public docket and made available on the 

Internet. If you submit an electronic 

comment, EPA recommends that you 

include your name and other contact 

information in the body of your 

comment and with any disk or CD–ROM 

you submit. If EPA cannot read your 

comment due to technical difficulties 

and cannot contact you for clarification, 

EPA may not be able to consider your 

comment. Electronic files should not 

include special characters or any form 

of encryption, and be free of any defects 

or viruses. 

D. Submitting Confidential Business 

Information 

Do not submit CBI to EPA through 

http://www.regulations.gov or email. 

Clearly mark the part or all of the 

information that you claim as CBI. For 

CBI information in a disk or CD ROM 

that you mail to EPA, mark the outside 

of the disk or CD ROM as CBI and 

identify electronically within the disk or 

CD ROM the specific information that is 

claimed as CBI. In addition to one 

complete version of the comment that 

includes information claimed as CBI, 

you must submit a copy of the comment 

that does not contain the information 

claimed as CBI for inclusion in the 

public docket. We will not disclose 

information so marked except in 

accordance with procedures set forth in 

40 CFR part 2. 

E. Tips for Preparing Comments 

When submitting comments, 

remember to: 

• Identify the rulemaking by docket 

number and other identifying 

information (e.g., subject heading, 

Federal Register date and page number). 

• Explain why you agree or disagree; 

suggest alternatives and substitute 

language for your requested changes. 

• Describe any assumptions and 

provide any technical information and/ 

or data that you used. 

• If you estimate potential costs or 

burdens, explain how you arrived at 

your estimate in sufficient detail to 

allow for it to be reproduced. 

• Provide specific examples to 

illustrate your concerns, and suggest 

alternatives. 

• Explain your views as clearly as 

possible, avoiding profanity or personal 

threats. 

• Make sure to submit your 

comments by the identified comment 

period deadline. 

To provide opportunities for 

questions and discussion, EPA will hold 

an open house prior to the public 

hearing. During the open house, EPA 

staff will be available informally to 

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9320 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules 

1 77 FR 75704, 75707–75702 (December 21, 2012). 

2 78 FR 46142. 

answer questions on our proposed rule. 

Any comments made to EPA staff 

during the open house must still be 

provided formally in writing or orally 

during a public hearing to be considered 

in the record. The open house and 

public hearing schedule is as follows. 

F. Public Hearings 

EPA will hold two public hearings at 

the dates, times and locations stated 

below to accept oral and written 

comments into the record. To request 

interpretation services or to request 

reasonable accommodation for a 

disability, please contact the person in 

the FOR FURTHER INFORMATION CONTACT

section by February 14, 2014. 

Public Hearing in Phoenix: 

Date: February 25, 2014. 

Open House: 4–5 p.m. 

Public Hearing: 6–8 p.m. 

Location: Phoenix Convention Center, 

Rooms 150–153, 33 South 3rd Street, 

Phoenix, Arizona 85004. 

Public Hearing in Tucson: 

Date: February 26, 2014. 

Open House: 4–5 p.m. 

Public Hearing: 6–8 p.m. 

Location: Tucson High Magnet 

School, Auditorium, 400 North 2nd 

Avenue, Tucson, Arizona 85705. 

The public hearing will provide the 

public with an opportunity to present 

views or information concerning the 

proposed RH FIP for Arizona. EPA may 

ask clarifying questions during the oral 

presentations, but will not respond to 

the presentations at that time. We will 

consider written statements and 

supporting information submitted 

during the comment period with the 

same weight as any oral comments and 

supporting information presented at the 

public hearing. Please consult section 

I.C, I.D and I.E of this preamble for 

guidance on how to submit written 

comments to EPA. We will include 

verbatim transcripts of the hearing in 

the docket for this action. The EPA 

Region 9 Web site for the rulemaking, 

which includes the proposal and 

information about the public hearing, is 

at http://www.epa.gov/region9/air/

actions. 

II. Proposed Actions Background and 

Overview 

A. Background 

The Clean Air Act (CAA) establishes 

as a national goal the prevention of any 

future, and the remedying of any 

existing man-made impairment of 

visibility in 156 national parks and 

wilderness areas designated as Class I 

areas. Arizona has a wealth of such 

areas. The sources addressed in this FIP 

affect many Class I areas in the State of 

Arizona and adjacent states. This FIP 

will ensure that progress is made toward 

natural visibility conditions at these 

national treasures, as Congress intended 

when it directed EPA to improve 

visibility in national parks and 

wilderness areas. Please refer to our 

previous rulemaking on the Arizona RH 

SIP for additional background regarding 

the CAA, regional haze and EPA’s 

RHR.1

B. Regional Haze 

We propose to promulgate a FIP as 

described in this notice and 

summarized in this section to address 

those portions of Arizona’s RH SIP that 

we disapproved on July 30, 2013.2 We 

disapproved in part Arizona’s BART 

control analyses and determinations for 

four sources, Reasonable Progress Goal 

(RPG) analyses and determinations, and 

Long-term Strategy (LTS) for making 

reasonable progress. The proposed FIP 

includes emission limits, compliance 

schedules and requirements for 

equipment maintenance, monitoring, 

testing, recordkeeping and reporting for 

all affected sources and units. The 

regulatory language for the proposed FIP 

requirements is under Part 52 at the end 

of this notice. 

1. Proposed BART Determinations 

EPA conducted BART analyses and 

determinations for four sources: Sundt 

Generating Station Unit 4, Nelson Lime 

Plant Kilns 1 and 2, Hayden Smelter 

and Miami Smelter. The results of our 

BART evaluations are summarized here 

for each source and are shown in Table 

1. We are seeking comments on our 

proposals. 

Sundt: We propose that Sundt Unit 4 

is BART-eligible and subject to BART 

for sulfur dioxide (SO2), nitrogen oxides 

(NOX) and particulate matter with 

aerodynamic diameter less than 10 

micrometers (PM10). For NOX, we 

propose an emission limit of 0.36 lb/

MMBtu as BART based upon an annual 

capacity factor of 0.49, which is 

consistent with the use of Selective 

Non-Catalytic Reduction (SNCR) as a 

control technology. For SO2, we propose 

an emission limit of 0.23 lb/MMBtu as 

BART on a 30-day boiler operating day 

(BOD) rolling basis, which is consistent 

with dry sorbent injection (DSI) as a 

control technology. For PM10, we 

propose a filterable PM10 emission limit 

of 0.030 lb/MMBtu as BART based on 

the use of the existing fabric filter 

baghouse. We also are proposing a 

switch to natural gas as a better-thanBART alternative to the other proposed 

controls for all three pollutants. 

Nelson Lime Plant: We propose that 

Nelson Lime Kilns 1 and 2 are subject 

to BART for NOX, SO2 and PM10. For 

NOX, we propose a BART emission limit 

at Kiln 1 of 3.80 lb/ton lime and at Kiln 

2 of 2.61 lb/ton lime on a 30-day rolling 

basis as verified by continuous emission 

monitoring systems (CEMS). This 

emission limit is consistent with the use 

of low-NOX burners (LNB) and SNCR as 

control technologies. We propose that 

BART for SO2 is an emission limit of 

9.32 lb/ton for Kiln 1 and 9.73 lb/ton for 

Kiln 2 on a 30-day rolling basis, which 

is consistent with the use of a lower 

sulfur fuel blend. For PM10, we propose 

a BART emission limit of 0.12 lb/tons of 

stone feed (TSF) to control PM10 at Kilns 

1 and 2 based on the use of the existing 

fabric filter baghouses. This level of 

control is commensurate with the 

MACT standard that applies to this 

source. 

Hayden Smelter: We propose that the 

Hayden Smelter is subject to BART for 

NOX, and propose BART emission 

limits for NOX and SO2. EPA previously 

approved the State’s determination that 

the Hayden Smelter is subject to BART 

for SO2. For NOX, we propose to find 

that controlling emissions from the 

converters and anode furnaces is costeffective, but would not result in 

sufficient visibility improvement to 

warrant the cost. Therefore, we are 

proposing an annual emission limit of 

40 tpy NOX emissions from the BARTeligible units, which is consistent with 

current emissions from these units. For 

SO2 from the converters, we propose a 

BART control efficiency of 99.8 percent 

on a 30-day rolling basis on all SO2

captured by primary and secondary 

control systems, which can be achieved 

with a new double contact acid plant. 

For SO2 from the anode furnaces, we 

propose to find that controlling the 37 

tons per year (tpy) of SO2 emissions 

from these furnaces, while costeffective, is not warranted as BART 

given the potential for only minimal 

visibility improvement. We propose as 

an emission limitation for the anode 

furnace a work practice standard 

requiring that the furnaces only be 

charged with blister copper or higher 

purity copper. We previously approved 

Arizona’s determination that BART for 

PM10 at the Hayden Smelter is no 

additional controls. In order to ensure 

the enforceability of this determination, 

we are proposing to incorporate 

emission limitations and associated 

compliance requirements from the 

National Emission Standard for 

Hazardous Air Pollutants (NESHAP) for 

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3 40 CFR 51.308(d)(1)(ii). 

Primary Copper Smelting at 40 CFR Part 

63, Subpart QQQ, as part of the LTS. 

Miami Smelter: EPA proposes that the 

Miami Smelter is subject to BART for 

NOX, and proposes BART emission 

limits for NOX and SO2. EPA previously 

approved the State’s determination that 

the Miami Smelter is subject to BART 

for SO2. For NOX, we propose to find 

that controlling the small amount of 

emissions from the converters and 

electric furnace is cost-effective, but 

would not result in sufficient visibility 

improvement to warrant the cost. 

Therefore, we are proposing an annual 

emission limit of 40 tpy NOX emissions 

from the BART-eligible units, which is 

consistent with current emissions. For 

SO2 from the converters, we propose a 

BART control efficiency of 99.7 percent 

on a 30-day rolling basis on all SO2

emissions captured by the primary and 

secondary control systems as verified by 

CEMS. This control efficiency could be 

met through improvements to the 

primary capture system, construction of 

a secondary capture system, and 

application of the MACT QQQ 

standards to the capture systems. For 

SO2 emissions from the electric furnace, 

we propose as BART the work practice 

standard to prohibit active aeration. We 

previously approved Arizona’s 

determination that BART for PM10 at the 

Miami Smelter is the NESHAP for 

Primary Copper Smelting. We now 

propose to find that the federally 

enforceable provisions of the NESHAP, 

which apply to the Miami Smelter and 

are incorporated into its Title V Permit, 

are sufficient to ensure the 

enforceability of this determination. 

TABLE 1—PROPOSED EMISSION LIMITS ON BART SOURCES

Source Units Pollutants Limit Measure Corresponding control technology 

Sundt Generating Station.Unit 4 ........................ NOX .........

SO2 .........

PM10 ........

0.36 

0.23 

0.030 

lb/MMBtu .................. Selective Non-Catalytic Reduction. 

Dry Sorbent Injection. 

Fabric filter baghouse (existing). 

Unit 4 (Alternative) ... NOX .........

SO2 .........

PM10 ........

0.25 

0.00064 

0.010 

lb/MMBtu .................. Switch to natural gas. 

Chemical Lime Nelson Kiln 1 ........................ NOX .........

SO2 .........

PM10 ........

3.80 

9.32 

0.12 

lb/ton feed ................. Selective Non-Catalytic Reduction. 

Lower sulfur fuel. 

Fabric filter baghouse (existing). 

Kiln 2 ........................ NOX .........

SO2 .........

PM10 ........

2.61 

9.73 

0.12 

................................... Selective Non-Catalytic Reduction. 

Lower sulfur fuel. 

Fabric filter baghouse (existing). 

Hayden Smelter ......... Converters 1, 3–5 ..... NOX .........

SO2 .........

40 

99.8 

tpy .............................

Control efficiency ......

None. 

New double contact acid plant. 

Anode Furnaces 1, 2 SO2 ......... None None ......................... Work practice standard. 

Miami Smelter ............ Converters 2–5 ......... NOX .........

SO2 .........

40 

99.7 

tpy .............................

Control efficiency ......

None. 

Improve primary and new secondary capture systems. 

Electric Furnace ....... SO2 ......... None None ......................... Work practice standard. 

2. Proposed RP Determinations 

Point Sources of NOX: EPA conducted 

an extensive RP analysis of NOX point 

sources that resulted in proposed 

determinations for nine sources and 

proposed controls on two sources as 

shown in Table 2. We are proposing an 

emissions limit of 2.12 lb/ton on Kiln 4 

of the Phoenix Cement Clarkdale Plant 

based on a 30-day rolling average, 

which is consistent with SNCR as a 

control technology. We are proposing an 

emissions limit of 2.67 lb/ton on Kiln 4 

of the CalPortland Cement Rillito Plant 

based on a 30-day rolling average, 

which also is consistent with SNCR 

control technology. We are also taking 

comment on the possibility of requiring 

a rolling 12-month cap on NOX

emissions in lieu of a lb/ton emission 

limit. For Phoenix Cement, this cap 

would be 947 tpy and apply to Kiln 4. 

For CalPortland, this cap would be 

2,082 tpy and apply to Kilns 1–4. 

TABLE 2—PROPOSED EMISSION LIMITS ON RP SOURCES

Source Units Pollutants Limit Measure Corresponding control technology 

Phoenix Cement .......................... Kiln 4 ................. NOX .................. 2.12 lb/ton ................. Selective Non-Catalytic Reduction. 

CalPortland Cement .................... Kiln 4 ................. NOX .................. 2.67 lb/ton ................. Selective Non-Catalytic Reduction. 

Area Sources of NOX and SO2: We 

propose to find that it is reasonable not 

to require additional controls on these 

sources at this time. Primarily, these 

area source categories are distillate fuel 

oil combustion in industrial and 

commercial boilers and in internal 

combustion engines, and residential 

natural gas combustion. The State’s area 

sources, which currently contribute a 

relatively small percentage of the 

visibility impairment at impacted Class 

I areas, would benefit from better 

emission inventories and an improved 

RP analysis in the next planning period. 

Reasonable Progress Goals: EPA is 

proposing RPGs consistent with a 

combination of control measures that 

include those in the approved Arizona 

RH SIP as well as the approved and 

proposed Arizona RH FIP. While not 

quantifying a new set of RPGs based on 

these control measures, we propose that 

it is reasonable to assume improved 

levels of visibility at Arizona’s 12 Class 

I areas by 2018 since the measures in 

the FIP are significantly beyond what 

was in the State’s plan. 

Demonstration of Reasonable 

Progress: EPA proposes to find that it is 

not reasonable to provide for rates of 

progress at the 12 Class I areas 

consistent with the uniform rate of 

progress (URP) in this planning period.3

Given the variety and location of 

sources contributing to visibility 

impairment in Arizona, EPA considers 

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9322 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules 

4See proposed actions at 77 FR 75727–75730, 78 

FR 29297–292300 and final action at 78 FR 46172. 

5 40 CFR 51.308(d)(1)(ii). 

6See 77 FR 75728 for a discussion on sources of 

organic carbon and elemental carbon (fires), and 78 

FR 29297–29299 for a discussion of coarse mass 

and fine soil. 

7 78 FR 46172. 

8 77 FR 75512–72580, December 5, 2012. 

9See 78 FR 46173 (codified at 40 CFR 

52.145(e)(ii)). 

10 62 FR 38856, July 18, 1997. 

11 62 FR 38652, July 18, 1997. 

12 ‘‘Revision to the Arizona State Implementation 

Plan Under Clean Air Act Section 110(a)(2)(D)(i)— 

Regional Transport,’’ submitted by ADEQ on May 

24, 2007. 

13 71 FR 61144, October 17, 2006. 

14 ‘‘Arizona State Implementation Plan Revision 

under Clean Air Act Section 110(a)(1) and (2); 2006 

PM2.5 NAAQS, 1997 PM2.5 NAAQS, and 1997 8- 

hour Ozone NAAQS,’’ submitted by ADEQ on 

October 14, 2009, which addressed the 

requirements of section 110(a)(2)(D)(i) with respect 

to the 2006 PM2.5 NAAQS in Section 2.4 and 

Appendix B of the submittal. 

15This concept is also presented in EPA’s 2006 

guidance memo on interstate transport, which 

recommended that states make a submission 

indicating that it was premature, at that time, to 

determine whether there would be any interference 

with other states’ required measures to protect 

visibility until the submission and approval of 

regional haze SIPs. See ‘‘Guidance for State 

Implementation Plan (SIP) Submissions to Meet 

Current Outstanding Obligations Under Section 

110(a)(2)(D)(i) for the [1997] 8-Hour Ozone and 

PM2.5 National Ambient Air Quality Standards,’’ 

August 15, 2006. 

16 78 FR 46142, July 30, 2013. 

17National Parks Conservation Association v. 

Jackson (D.D.C. Case 1:11–cv–01548). 

18National Parks Conservation Association v. 

Jackson (D.D.C. Case 1:11–cv–01548), 

Memorandum Order and Opinion (May 25, 2012), 

Minute Order (July 2, 2012), Minute Order 

(November 13, 2012) and Minute Order (February 

15, 2013). 

19 Id. 

it unlikely that Arizona’s Class I areas 

will meet the URP in 2018. We propose 

to find that the RP analyses underlying 

our actions on the Arizona SIP 4 and in 

this proposal are sufficient to 

demonstrate that it is not reasonable to 

provide for rates of progress in this 

planning period that would attain 

natural conditions by 2064.5 This is 

consistent with our proposed and final 

rules on the Arizona RH SIP in which 

we approved Arizona’s determinations 

that it is not reasonable to require 

additional controls to address organic 

carbon, elemental carbon, coarse mass 

and fine soil during this planning 

period.6 We also approved the State’s 

decision not to require additional 

controls (i.e., controls beyond what the 

State or we determine to be BART) on 

point sources of SO2.7

3. Long-Term Strategy Proposal 

EPA proposes to find that provisions 

in today’s proposal in combination with 

provisions in the approved Arizona SIP 

and FIP 8 fulfill the requirements of 40 

CFR 51.308(d)(3)(ii), (v)(C) and (v)(F). 

These requirements are to include in the 

LTS measures needed to achieve 

emission reductions for out-of-state 

Class I areas, emissions limitations and 

schedules for compliance to achieve the 

reasonable progress goals, and 

enforceability of emissions limitations 

and control measures.9 In today’s notice 

we propose to promulgate emission 

limits, compliance schedules and other 

requirements for four BART sources and 

two RP sources to complete the actions 

taken in our previous final rule to 

address these requirements. 

C. Interstate Transport of Pollutants 

That Affect Visibility 

We propose that a combination of SIP 

and FIP measures will satisfy the FIP 

obligation for the visibility requirement 

of CAA section 110(a)(2)(D)(i)(II) for the 

1997 8-hour ozone, 1997 PM2.5, and 

2006 PM2.5 NAAQS. CAA section 

110(a)(2)(D)(i)(II) requires that all SIPs 

contain adequate provisions to prohibit 

emissions that will interfere with other 

states’ required measures to protect 

visibility. We refer to this requirement 

herein as the interstate transport 

visibility requirement. ADEQ submitted 

SIP revisions to address this 

requirement in 2007 for the 1997 8-hour 

ozone NAAQS 10 and 1997 PM2.5

NAAQS 11 (2007 Transport SIP) 12 and 

in 2009 for the 2006 PM2.5 NAAQS 13

(2009 Transport SIP).14 Each of these 

SIP revisions indicated that it is 

appropriate to assess Arizona’s 

interference with other states’ measures 

to protect visibility in conjunction with 

the State’s RH SIP.15 In our final rule 

published on July 30, 2013, EPA 

disapproved these SIP submittals with 

respect to the interstate transport 

visibility requirement, triggering the 

obligation for EPA to promulgate a FIP 

to address this requirement.16

Accordingly, today’s notice describes 

our proposed FIP for the interstate 

transport visibility requirement for the 

1997 8-hour ozone, 1997 PM2.5, and 

2006 PM2.5 NAAQS. 

III. Review of State and EPA Actions on 

Regional Haze 

A. EPA’s Schedule To Act on Arizona’s 

RH SIP 

EPA received a notice of intent to sue 

in January 2011 stating that we had not 

met the statutory deadline for 

promulgating RH FIPs and/or approving 

RH SIPs for dozens of states, including 

Arizona. This notice was followed by a 

lawsuit filed by several advocacy groups 

(Plaintiffs) in August 2011.17 In order to 

resolve this lawsuit and avoid litigation, 

EPA entered into a Consent Decree with 

the Plaintiffs, which sets deadlines for 

action for all of the states covered by the 

lawsuit, including Arizona. This decree 

was entered and later amended by the 

United States District Court for the 

District of Columbia over the opposition 

of Arizona.18 Under the terms of the 

Consent Decree, as amended, EPA is 

currently subject to three sets of 

deadlines for taking action on Arizona’s 

RH SIP as listed in Table 3.19

TABLE 3—CONSENT DECREE DEADLINES FOR EPA TO ACT ON ARIZONA’S RH SIP 

EPA actions Proposed rule Final rule 

Phase 1—BART determinations for Apache, Cholla and Coronado .............................................. July 2, 2012 1 ............. November 15, 2012.2

Phase 2—All remaining elements of the Arizona RH SIP .............................................................. December 8, 2012 3 .. July 15, 2013.4

Phase 3—FIP for disapproved elements of the Arizona RH SIP ................................................... January 27, 2014 ...... June 27, 2014. 

1Published in the Federal Register on July 20, 2012, 77 FR 42834. 2Published in the Federal Register on December 5, 2012, 77 FR 72512. 3Published in the Federal Register on December 21, 2012, 77 FR 75704. 4Published in the Federal Register on July 30, 2013, 78 FR 46142. 

B. History of State Submittals and EPA 

Actions 

Because four of Arizona’s 12 

mandatory Class I Federal areas are on 

the Colorado Plateau, the State had the 

option of submitting a RH SIP under 

CAA section 309 of the RHR. A SIP that 

is approved by EPA as meeting all of the 

requirements of section 309 is ‘‘deemed 

to comply with the requirements for 

reasonable progress with respect to the 

16 Class I areas [on the Colorado 

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20 40 CFR 51.309(a). 

21 71 FR 28270 and 72 FR 25973. 

22Center for Energy and Economic Development 

v. EPA, 398 F.3d 653 (D.C. Circuit 2005). 

23 71 FR 60612. 

24Letter from Stephen A. Owens, ADEQ, to 

Wayne Nastri, EPA, dated December 24, 2008. 

25 74 FR 2392. 

26 78 FR 8083. 

27 78 FR 48326. 

28CAA section 110(k)(1)(B). 

29 ‘‘Arizona State Implementation Plan, Regional 

Haze under Section 308 of the Federal Regional 

Haze Rule,’’ February 28, 2011. 

30See July 6, 2005 BART Guidelines, 40 CFR 51, 

Regional Haze Regulations and Guidelines for Best 

Available Retrofit Technology Determinations. 

Plateau] for the period from approval of 

the plan through 2018.’’ 20 When these 

regulations were first promulgated, 309 

SIPs were due no later than December 

31, 2003. Accordingly, ADEQ submitted 

to EPA on December 23, 2003, a 309 SIP 

for Arizona’s four Class I Areas on the 

Colorado Plateau. ADEQ submitted a 

revision to its 309 SIP, consisting of 

rules on emissions trading and smoke 

management, and a correction to the 

State’s regional haze statutes, on 

December 31, 2004. EPA approved the 

smoke management rules submitted as 

part of the revisions in 2004,21 but did 

not propose or take final action on any 

other portion of the 309 SIP. 

In response to a court decision,22 EPA 

revised 40 CFR 51.309 on October 13, 

2006, making a number of substantive 

changes and requiring states to submit 

revised 309 SIPs by December 17, 

2007.23 Subsequently, ADEQ sent a 

letter to EPA dated December 24, 2008, 

acknowledging that it had not submitted 

a SIP revision to address the 

requirements of 40 CFR 51.309(d)(4) 

related to stationary sources and 40 CFR 

51.309(g), which governs reasonable 

progress requirements for Arizona’s 

eight mandatory Class I areas outside of 

the Colorado Plateau.24

EPA made a finding on January 15, 

2009, that 37 states, including Arizona, 

had failed to make all or part of the 

required SIP submissions to address 

regional haze.25 Specifically, EPA found 

that Arizona failed to submit the plan 

elements required by 40 CFR 

51.309(d)(4) and (g). EPA sent a letter to 

ADEQ on January 14, 2009, notifying 

the State of this failure to submit a 

complete SIP. ADEQ decided to submit 

a SIP under CAA section 308, instead of 

under section 309. EPA proposed on 

February 5, 2013,26 to disapprove 

Arizona’s 309 SIP except for the smoke 

management rules that we had 

previously approved. Our final rule 

partially disapproving Arizona’s 309 SIP 

was published on August 8, 2013.27

ADEQ adopted and transmitted its 

2011 RH SIP under section 308 of the 

RHR to EPA Region 9 in a letter dated 

February 28, 2011. The SIP was 

determined complete by operation of 

law on August 28, 2011.28 The SIP was 

properly noticed by the State and 

available for public comment for 30 

days prior to one public hearing held in 

Phoenix, Arizona, on December 2, 2010. 

Arizona included in its SIP responses to 

written comments from EPA Region 9, 

the National Park Service, the U.S. 

Forest Service, and other stakeholders 

including regulated industries and 

environmental organizations. The 2011 

RH SIP is available to review in the 

docket for this proposed rule.29

As shown in Table 3, the first phase 

of EPA’s action on the 2011 RH SIP 

addressed three BART sources. The 

final rule for the first phase (a partial 

approval and partial disapproval of the 

State’s plan and a partial FIP) was 

signed by the Administrator on 

November 15, 2012, and published in 

the Federal Register on December 5, 

2012. The emission limits on the three 

sources will improve visibility by 

reducing NOX emissions by about 

22,700 tons per year. In the second 

phase of our action, we proposed on 

December 21, 2012, to approve in part 

and disapprove in part the remainder of 

the 2011 RH SIP. ADEQ submitted an 

Arizona RH SIP Supplement on May 3, 

2013, to correct certain deficiencies 

identified in that proposal. We then 

proposed on May 20, 2013, to approve 

in part and disapprove in part the 

Supplement. Our final rule approving in 

part and disapproving in part Arizona’s 

RH SIP was published on July 30, 2013. 

C. EPA’s Authority To Promulgate a FIP 

Under CAA section 110(c), EPA is 

required to promulgate a FIP within 2 

years of the effective date of a finding 

that a state has failed to make a required 

SIP submission. The FIP requirement is 

terminated if a state submits a regional 

haze SIP, and EPA approves that SIP 

before promulgating a FIP. See 74 FR 

2392. Specifically, CAA section 110(c) 

provides: 

(1) The Administrator shall promulgate a 

Federal implementation plan at any time 

within 2 years after the Administrator— 

(A) finds that a State has failed to make a 

required submission or finds that the plan or 

plan revision submitted by the State does not 

satisfy the minimum criteria established 

under [CAA section 110(k)(1)(A)], or 

(B) disapproves a State implementation 

plan submission in whole or in part, unless 

the State corrects the deficiency, and the 

Administrator approves the plan or plan 

revision, before the Administrator 

promulgates such Federal implementation 

plan. 

Section 302(y) defines the term ‘‘Federal 

implementation plan’’ in pertinent part, 

as: 

[A] plan (or portion thereof) promulgated 

by the Administrator to fill all or a portion 

of a gap or otherwise correct all or a portion 

of an inadequacy in a State implementation 

plan, and which includes enforceable 

emission limitations or other control 

measures, means or techniques (including 

economic incentives, such as marketable 

permits or auctions or emissions allowances) 

. . . 

Thus, because we determined that 

Arizona failed to timely submit a 

Regional Haze SIP, we are required to 

promulgate a Regional Haze FIP for 

Arizona, unless we first approve a SIP 

that corrects the non-submittal 

deficiencies identified in our finding of 

January 15, 2009. For the reasons 

explained below, we approved in part 

and disapproved in part the Arizona 

Regional Haze SIP on July 30, 2013. 

Therefore, we are proposing a FIP to 

address those portions of the SIP that 

we disapproved. 

IV. EPA’s BART Process 

A. BART Factors 

The purpose of the BART analysis is 

to identify and evaluate the best system 

of continuous emission reduction based 

on the BART Guidelines 30 as 

summarized below. Steps 1 through 3 

address the availability, feasibility and 

effectiveness of retrofit control options. 

In our analysis of control technology 

options, we expressly include the 

emission baseline calculation that is a 

key factor in determining control 

effectiveness. Step 4 is the five-factor 

BART analysis that results in selecting 

the emission limit that represents BART 

in Step 5. Following the process steps 

is a short description of each BART 

factor. 

Step 1—Identify all available retrofit 

control technologies. 

Step 2—Eliminate technically 

infeasible options. 

Step 3—Evaluate control effectiveness 

of remaining control technologies. 

Step 4—Evaluate impacts and 

document the results. 

• Factor 1: Cost of compliance. 

• Factor 2: Energy and non-air quality 

environmental impacts of compliance. 

• Factor 3: Pollution control 

equipment in use at the source. 

• Factor 4: Remaining useful life of 

the facility. 

• Factor 5: Visibility impacts. 

Step 5—Select BART. 

Factor 1: Costs of Compliance: The 

evaluation of costs is an important part 

of a five-factor analysis because it 

influences the cost-effectiveness that is 

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31 40 CFR Part 51, Appendix Y, section IV.D.4.k. 

32EPA relied on version 5.8 of CALPUFF because 

it is the EPA-approved version promulgated in the 

Guideline on Air Quality Models (40 CFR part 51, 

Appendix W, section 6.2.1.e; 68 FR 18440, April 15, 

2003). EPA updated the specific version to be used 

for regulatory purposes on June 29, 2007, including 

minor revisions as of that date; the approved 

CALPUFF modeling system includes CALPUFF 

version 5.8, level 070623, and CALMET version 5.8 

level 070623. At this time, any other version of the 

CALPUFF modeling system would be considered an 

‘‘alternative model’’, subject to the provisions of 

Guideline on Air Quality Models section 3.2.2(b), 

requiring a full theoretical and performance 

evaluation. 

33For each modeled day, the CALPUFF model 

provides the highest impact from among the 

receptor locations for a given Class I area. The 

baseline impact in the tables is the 98th percentile 

among these daily values. The improvement in the 

tables is the difference between that baseline impact 

and the 98th percentile impact after applying 

controls. The 98th percentile is represented by the 

22nd high over the 2001–2003 period modeled. The 

TSD includes an alternative, the average of each of 

the three years’ 8th highs, which yields slightly 

different values. 

34The distances given are from the facility to the 

nearest model receptor location; distances to the 

actual Class I area boundary may be slightly less. 

Receptor locations are defined for all Class I areas 

by the National Park Service. See ‘‘Class I 

Receptors’’ Web site, http://www2.nature.nps.gov/

air/maps/Receptors/. 

compared to the visibility benefits. 

Estimating the cost of compliance 

primarily depends on the cost estimates 

and control effectiveness of each 

technically feasible BART control 

option. For each of the four BART 

facilities evaluated in this section, we 

state the source of the cost-related 

information and how it was used in our 

analysis. While EPA relies primarily on 

the cost methods in our Control Cost 

Manual, we also rely on verified cost 

estimates from the companies and cost 

methods used for specific industries. In 

some cases, certain capital costs and 

annual operating costs were developed 

by our contractor based on actual costs 

associated with specific types of 

sources. Where possible, we have 

conducted new cost analyses 

considering more recent information 

from ADEQ or from the four BART 

facilities. Please refer to the TSD for the 

detailed cost analyses. 

Factor 2: Energy and Non-air Quality 

Environmental Impacts: In assessing the 

potential energy impacts of BART 

control options, we consider direct and 

indirect effects on energy availability 

and costs. An example of a direct energy 

impact is the cost of energy 

consumption from the control 

equipment. Examples of non-air quality 

impacts include safety issues associated 

with handling and transportation of 

anhydrous ammonia or the ability to sell 

fly ash rather than dispose of it. 

Factor 3: Pollution Equipment in Use 

at the Source: The presence of existing 

pollution control technology at each 

source is reflected in our BART analysis 

in two ways. First, we always consider 

simple retention of existing equipment 

as a BART candidate. We also consider 

existing equipment in determining 

available control technologies that can 

be used with or replace such equipment. 

Second, where appropriate, we consider 

existing equipment in developing 

baseline emission rates for use in cost 

calculations and visibility modeling. 

Pollutant-specific discussions of these 

issues are included in the following 

sections. 

Factor 4: Remaining Useful Life of the 

Source: We consider each source’s 

‘‘remaining useful life’’ as one element 

of the overall cost analysis as allowed 

by the BART Guidelines.31 In cases 

where we are not aware of any 

enforceable shut-down date for a 

particular source or unit, we use a 20- 

year amortization period as the 

remaining useful life per the EPA Cost 

Control Manual. 

Factor 5: Anticipated Degree of 

Visibility Improvement: EPA relied on 

the CALPUFF modeling system (version 

5.8) for visibility modeling, which 

consists of the CALPUFF dispersion 

model, the CALMET meteorological 

data processor, and the CALPOST postprocessing program. The initial 

modeling was performed by our 

contractor, the University of North 

Carolina (UNC) at Chapel Hill. In some 

cases, companies submitted BART 

analyses including visibility modeling 

that we used to evaluate visibility 

benefits. An explanation of the visibility 

analysis and tables follows this section, 

a description of the modeling is 

included in the five-factor discussion 

for each source, and more details are 

available in the TSD. 

B. Visibility Analysis 

EPA estimated the degree of visibility 

improvement expected to result from 

various BART control options based on 

the difference between baseline 

visibility impacts prior to controls and 

visibility impacts with controls in 

operation. Baseline emissions were 

based on the highest 24-hour emissions 

from monitored emissions data when 

available, otherwise from estimates of 

production rates and emission factors. 

Control case emissions were derived 

from the baseline by applying the 

percent reduction in emission factor 

expected from the control. Impacts at all 

Class I areas within 300 km of each 

facility were assessed. EPA used the 

CALPUFF model version 5.8 32 to 

determine the baseline and post-control 

visibility impacts, following the 

modeling approach recommended in the 

BART Guidelines. Our contractor at 

UNC developed a modeling protocol 

and carried out most of the modeling 

and the post-processing of model output 

into tables of visibility impacts. EPA 

supplemented this for certain sources 

with modeling of additional control 

scenarios, corrections to some scenarios 

and post-processing work, and some 

sensitivity simulations. Also, EPA 

performed the modeling for the two 

smelters. Details of the modeling are in 

the TSD. 

EPA modeled all units (stacks) and 

pollutants simultaneously for each 

source. Modeling of all emissions from 

all units accounts for the chemical 

interaction between multiple plumes, 

and between plumes and background 

concentrations. This also accounts for 

the fact that deciview benefits from 

controls on individual units are not 

strictly additive. As recommended in 

the BART Guidelines, the 98th 

percentile daily impact in deciviews is 

used as the basic metric of visibility 

impact. EPA relied on the 98th 

percentile over the merged 2001–2003 

period. The alternative of using the 

average of the three 98th percentiles 

from 2001, 2002 and 2003 was also 

calculated, and the results of using it are 

provided in the TSD, although they 

differ little from the merged approach. 

Both are valid indicators of the 98th 

percentile.33 EPA also mainly relied on 

the revised IMPROVE equation for 

translating pollutant concentrations into 

deciviews (CALPOST visibility method 

8), the recommended method for new 

visibility analyses. The old IMPROVE 

equation (method 6) was used by most 

states in their original SIP submittals 

and was acceptable at that time. EPA 

used the best 20 percent of natural 

background days in calculating delta 

deciviews. For the original SIP 

submittals, states were free to use this 

or the annual average background. 

Overall, we refer to the method we used 

as method ‘‘8b’’ (‘‘b’’ for ‘‘best’’). Model 

results using visibility method 6 and 

annual average background conditions 

(‘‘a’’ for average) also are provided in 

the TSD (i.e., methods 6a, 6b, and 8a, as 

well as 8b). 

C. Explanation of Visibility Tables 

For each facility, this notice provides 

one or more tables of visibility impacts 

and visibility improvement from 

controls in deciviews. Each table has the 

same format: columns list the Class I 

areas within 300 km of the facility, the 

distance,34 baseline modeled visibility 

impact from the facility for each area, 

and one or more columns with the 

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35As described in Pima DEQ Permit No. 1052, in 

the TSD. 

modeled visibility improvement from a 

candidate control option. A modeling 

run abbreviation, such as ‘‘base’’ or 

‘‘ctrl2’’, is included along with a short 

description of the option. For several 

facilities, there are two different 

baselines incorporating different 

emission assumptions. For these, there 

are baseline and control columns for 

each of the two baselines. For Sundt 

Unit 4, there are separate tables for SO2

and NOX controls, and an additional 

table showing the effect of reductions 

for both SO2 and NOX for the proposed 

BART controls and for a better-thanBART alternative. At the bottom of each 

table are five rows showing impacts and 

improvements from the facility for all 

the Class I areas considered together, 

and also two measures of visibility costeffectiveness. The cost-effectiveness 

here is ‘‘dollars per deciview,’’ where 

dollars is the annualized total cost of the 

control in millions of dollars per year, 

divided by either the sum of deciview 

improvements over all impacted Class I 

areas, or the largest single area deciview 

improvement. Cost-effectiveness in 

terms of dollars per ton is presented in 

other tables and has been considered for 

each source and BART option. The 

headings for these table rows are: 

(1) ‘‘Cumulative (sum),’’ the 

cumulative impact or improvement that 

is computed as the sum of impact or 

improvement over all the areas; 

(2) ‘‘Maximum,’’ single largest impact 

or improvement that is the maximum 

over all the areas; 

(3) ‘‘# CIAs >= 0.5 dv,’’ the number of 

Class I areas having a baseline impact 

from the source of at least 0.5 dv (or, for 

the control columns, the number of 

areas showing improvement of at least 

0.5 dv due to the control); 

(4) ‘‘Million $/dv (cumul. dv),’’ 

annual control cost in millions of 

dollars per deciview considering the 

improvement at all the Class I areas 

together; and 

(5) ‘‘Million $/dv (max. dv),’’ 

annualized cost per deciview 

considering the largest single area 

improvement. 

The Federal Land Managers have 

sometimes used $10 million/dv as a 

comparison benchmark for the $/dv 

computed from the maximum, and $20 

million/dv as a benchmark for $/dv 

computed from cumulative deciviews. 

We have not endorsed the use of these 

or any other $/dv benchmarks as criteria 

for making BART determinations. 

The TSD for this notice provides bar 

charts and additional visibility tables, 

including results for individual 

modeled years and their average, the old 

IMPROVE equation, and annual average 

background conditions instead of best 

20 percent. There also are model results 

for various sensitivity analyses. 

V. EPA’s Proposed BART FIP 

A. Sundt Generating Station Unit 4 

Summary: EPA is proposing to find 

that Sundt Unit 4 is eligible for and 

subject to BART. EPA is proposing 

BART emissions limits on Sundt 

Generating Station Unit 4 for NOX, SO2

and PM10 based on the corresponding 

control technologies listed in Table 4 

and described in the following BART 

analyses. For NOX, we propose an 

emission limit of 0.36 lb/MMBtu 

consistent with the use of SNCR. For 

SO2, we propose an emission limit of 

0.23 lb/MMBtu consistent with the use 

of DSI. For PM10, we propose a filterable 

PM10 emission limit of 0.03 lb/MMBtu 

based on the use of the existing fabric 

filter baghouse. Finally, we are also 

proposing a switch to natural gas as a 

better-than-BART alternative. 

TABLE 4—SUNDT 4: SUMMARY OF PROPOSED BART DETERMINATIONS

Pollutant Emission limit 

(lb/MMBtu) Control technology 

NOX .................................................................................................................. 0 .36 Selective Non-Catalytic Reduction. 

SO2 .................................................................................................................. 0 .23 Dry Sorbent Injection. 

PM10 ................................................................................................................. 0 .030 Fabric filter baghouse (existing). 

Affected Class I Areas: Ten Class I 

areas are within 300 km of Sundt. Their 

nearest borders range from 17 km to 247 

km away, with Saguaro NP the closest, 

and Galiuro WA the second closest. The 

highest baseline visibility impact of 

Sundt Unit 4 is 3.4 dv at Saguaro. The 

second highest baseline impact is 1.1 dv 

at Galiuro. Other areas have visibility 

impacts of 0.5 dv or less. The 

cumulative sum of visibility impacts 

over all the Class I areas is 6.6 dv. 

Facility Overview: The Sundt 

Generating Station is an electric utility 

power plant located in Tucson, Arizona, 

operated by Tucson Electric Power. The 

plant consists of four steam electric 

boilers and three stationary combustion 

turbines for a total net generating 

capacity of approximately 500 

megawatts (MW).35 Sundt Unit 4 is a 

steam electric boiler that was 

manufactured in 1964 and placed into 

operation in about 1967. Unit 4 is a dry 

bottom wall-fired boiler with a 

maximum gross capacity of 130 MW 

when firing coal. Originally designed to 

fire natural gas and fuel oil, Sundt Unit 

4 was converted to also be able to fire 

coal in the early 1980s as a result of an 

order issued by the Department of 

Energy. The unit now fires both coal 

and natural gas, as explained in more 

detail below. As part of the coal 

conversion, the unit was equipped with 

a fabric filter for particulate matter 

control. Unit 4 was upgraded in 1999 

with LNB and overfire air (OFA) 

designed to meet Phase II Acid Rain 

Program requirements. At present, Unit 

4 operates with the pollution control 

equipment and is subject to the 

emission limits listed in Table 5 that 

reflects a coal-operating scenario. 

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36Pima DEQ Permit No. 1052, Attachment F: 

Phase II Acid Rain Permit. 

37Pima DEQ Permit No. 1052, Specific Condition 

II.A.2.b. 

38As determined by Pima DEQ Permit No. 1052, 

Specific Condition II.A.1. 

39TEP’s letter dated May 10, 2013, page 2. 

40TEP’s letter dated May 10, 2013, page 2. 

41As discussed in the BART Guidelines, 40 CFR 

Part 51, Appendix Y, section IV.D.4.d. 

TABLE 5—SUNDT 4: CURRENT EMISSION LIMITS AND CONTROL TECHNOLOGY

Pollutant Emission limit Control device 

NOX ..................................................................... 0.46 lb/MMBtu 36 ................................................ LNB with OFA. 

SO2 ...................................................................... 1 lb/MMBtu 37 ..................................................... None. 

PM10 .................................................................... 233 lb/hr 38 ......................................................... Fabric filter/baghouse. 

TEP has indicated that the generating 

capacity of Sundt Unit 4 while firing 

coal is reduced compared to its capacity 

using natural gas. As reported to the 

Energy Information Agency (EIA), Unit 

4 has a 173 MW nameplate capacity 

while firing natural gas. However, the 

maximum gross capacity at which the 

unit could operate for a sustained 

period of time while burning coal is 

about 130 MW. This is due primarily to 

the fact that the amount of coal that can 

be introduced to the boiler is limited by 

the size of the boiler. Excess coal 

injection causes the flame to impinge on 

the back wall of the boiler which 

damages the boiler tubes.39 A summary 

of historical emissions data for a recent 

period of time is in Table 6. 

TABLE 6—SUNDT 4: HISTORICAL EMISSIONS (2008–2012) 

Year Heat duty 

(MMBtu/yr) 

NOX SO2 Coal 

(tons) 

Natural gas 

(MCF) (tpy) (lb/MMBtu) (tpy) (lb/MMBtu) 

2012 ......................................................... 6,313,719 945 0.297 371 0.118 44,049 4,660,701 

2011 ......................................................... 5,993,769 1,366 0.445 2,185 0.729 265,111 157,919 

2010 ......................................................... 6,869,999 1,303 0.368 1,733 0.505 162,212 1,904,433 

2009 ......................................................... 4,801,971 709 0.285 636 0.265 73,464 2,642,992 

2008 ......................................................... 8,709,923 1,880 0.429 2,882 0.661 378,956 18,422 

Baseline Emissions Calculations: The 

baseline period, baseline emissions, and 

capacity factor are three key variables in 

determining BART that are linked to 

fuel usage. TEP has indicated that while 

Sundt Unit 4 predominantly has 

operated as a coal-fired unit, it has 

recently expanded its use of natural gas 

as a result of historically low natural gas 

prices.40 As shown in the last column of 

Table 6, Unit 4 has used much higher 

amounts of natural gas during 2009– 

2010 and again in 2012 that are not 

representative of anticipatable 

operations based on coal. Accordingly, 

we use calendar year 2011 emissions 

when Unit 4 predominately used coal as 

the baseline period for annual average 

emission estimates. Although this 

represents only a single year of 

emissions data, we consider this period 

of coal usage, rather than a period of 

primarily natural gas usage, to represent 

a realistic depiction of anticipated 

annual emissions when burning coal.41

In addition, we rely on an annual 

capacity factor of 0.49 based on a coalfired capacity of 130 MW and actual 

generation from the baseline period of 

2011. For visibility modeling, we used 

baseline emissions for NOX and SO2

based on maximum daily emission 

rates, as reported to EPA’s CAMD Acid 

Rain Program database, for the period 

from 2008 to 2010. While this time 

period is prior to the 2011 baseline 

period used for the annual emission 

estimates, the highest daily emission 

rates from 2008 to 2010 correspond to 

coal usage. Since these maximum daily 

emission rates still correspond to coal 

usage, we consider them reasonable 

estimates of baseline emissions despite 

the fact that they are drawn from a 

baseline period different from the one 

used to estimate annual emission rates. 

For PM10, the baseline emission rate 

used in visibility modeling is based on 

the value in the original Western 

Regional Air Partnership (WRAP) 

visibility modeling that reflects the use 

of coal and the existing fabric filter. For 

a more detailed analysis of how we 

determined the baseline period, baseline 

emissions and capacity factor, please 

refer to the TSD. 

Modeling Overview: EPA’s contactor 

UNC performed the initial modeling of 

Sundt’s visibility impacts. EPA 

performed supplemental modeling to 

correct some minor errors in the initial 

work and to estimate impacts from 

additional control scenarios, such as 

switching entirely to natural gas fuel. 

EPA also modeled the impacts for the 

western unit of Saguaro NP, whereas 

originally only the eastern unit was 

included. Although only Unit 4 is 

BART-eligible, all four Sundt units were 

included in the CALPUFF modeling to 

more accurately represent the chemistry 

of the facility’s pollutant plume. 

Baseline emissions for modeling were 

based on daily CAMD emissions 

monitoring data for 2008–2010, a period 

with no changes in pollution controls at 

the facility. Control case emissions were 

derived from the baseline by applying 

the percent reduction expected from the 

control. 

Saguaro NP has an eastern unit, the 

Rincon Mountain District, and a western 

unit, the Tucson Mountain District. In 

the original set of modeling receptor 

locations developed by the National 

Park Service, only the eastern unit was 

included. CALPUFF modeling typically 

covered only the eastern unit. This is 

true of modeling by the WRAP, and also 

of modeling by EPA’s contractor UNC, 

which used the WRAP work as a 

starting point. A more recent set of NPS 

modeling receptors from 2008 is 

available that covers both eastern and 

western units of Saguaro. For this FIP, 

EPA remodeled for both Saguaro units 

where needed for a given facility. The 

only facilities for which it makes a 

significant difference are TEP Sundt and 

CalPortland Cement due to their close 

proximity to Saguaro. 

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42 78 FR 46175 (codified at 40 CFR 

52.145(e)(2)(i)). 

43See 78 FR 75722, 78 FR 46151, and ‘‘TEP Sundt 

Unit I4 BART Eligibility Memo’’ (November 21, 

2012). 

44 40 CFR part 51, appendix Y, section III.A. 

45 77 FR 46152–53. 

46Technical Analysis for Arizona and Hawaii 

Regional Haze FIPs: Report on Identification of 

Sources Subject to BART, UNC, July 20, 2012, Table 

4. 

47For an expanded discussion of our approach to 

visibility modeling, please refer to Section III 

(General Approach to the Five-Factor BART 

analysis) of the Sundt4 TSD. This approach was 

used in both determining whether Sundt 4 was 

subject to BART, as well as in evaluating the 

visibility factor in the BART analysis. 48See ‘‘Emissions Control: Cost-Effective Layered 

Technology for Ultra-Low NOx Control’’ (2007), 

‘‘What’s New in SCRs’’ (2006), and ‘‘Nitrogen 

Oxides Emission Control Options for Coal-Fired 

Electric Utility Boilers’’ (2005). 

49See spreadsheet ‘‘CAMD Wall-fired Coal 

EGUs.xlsx’’ in the docket. 

50See spreadsheet ‘‘Sundt4 2001–12 Emission 

Calcs 2014–01–24.xlsx’’ in the docket. 

51As noted by TEP in its May 10, 2013 letter, 

although the calculated capacity factor is different, 

the annual emissions in tons per year removed do 

not change significantly, as the change in capacity 

factor is largely offset by the change in maximum 

unit gross rating. 

1. Proposed Eligible and Subject to 

BART 

EPA is proposing to find that Sundt 

Unit 4 is eligible for and subject to 

BART. In our final rulemaking on the 

Arizona RH SIP dated July 30, 2013, we 

disapproved ADEQ’s finding that Sundt 

Unit 4 was not eligible for BART.42 In 

particular, we found that, although this 

unit was ‘‘reconstructed’’ in 1987, it 

remains BART-eligible because it did 

not undergo prevention of significant 

deterioration (PSD) review at the time of 

reconstruction.43 For this reason, we 

propose to find Sundt Unit 4 is eligible 

for a BART analysis of the three hazecausing pollutants: NOX, SO2 and PM10. 

Under the RHR and the BART 

Guidelines, any BART-eligible source 

that either ‘‘causes’’ or ‘‘contributes’’ to 

visibility impairment at any Class I area 

is subject to BART.44 EPA previously 

approved ADEQ’s decision to set 0.5 dv 

as the threshold for determining 

whether a source contributes to 

visibility impairment at a given Class I 

area.45 In order to determine whether 

Sundt Unit 4 is subject to BART, EPA’s 

contractor UNC evaluated whether Unit 

4 has an impact of 0.5 dv or more at any 

Class I area. UNC’s visibility modeling 

showed that two Class I areas 

experienced a 98th percentile impact 

greater than 0.5 dv due to emissions 

from Sundt Unit 4.46 In particular, the 

98th percentile impact across the three 

years modeled was 2.798 dv at Saguaro 

and 0.839 dv at Galiuro.47 These results 

indicate that Sundt Unit 4 causes 

visibility impairment at Saguaro and 

contributes to impairment at Galiuro. 

Therefore, EPA proposes to find that 

Sundt Unit 4 is subject to BART. 

2. Proposed BART Analysis and 

Determination for NOX

For our NOX BART analysis, we 

identify all available control 

technologies, eliminate options that are 

not technically feasible, and evaluate 

the control effectiveness of the 

remaining control options. We then 

evaluate each technically feasible 

control in terms of a five-factor BART 

analysis and propose a determination 

for BART. 

a. Control Technology Availability, 

Technical Feasibility, and Effectiveness 

EPA proposes to find that SNCR and 

selective catalytic reduction (SCR) are 

available and technically feasible 

options to control NOX emissions with 

a control efficiency of approximately 50 

percent for SNCR and approximately 89 

percent for SCR. 

SNCR involves the non-catalytic 

decomposition of NOX to molecular 

nitrogen and water. Typical NOX control 

efficiencies for SNCR range from 40 to 

60 percent, depending on inlet NOX

concentrations, fluctuating flue gas 

temperatures, residence time, amount 

and type of nitrogenous reducing agent, 

mixing effectiveness, acceptable levels 

of ammonia slip, and presence of 

interfering chemical substances in the 

gas stream. Because Sundt Unit 4 

already operates with NOX combustion 

controls, we have used an SNCR control 

efficiency of 30 percent from a baseline 

that includes LNB with OFA. 

Considering typical combustion control 

technologies such as LNB and OFA can 

achieve control efficiencies of about 25 

to 30 percent, the result is total control 

efficiency from an uncontrolled baseline 

of about 50 percent, which is in the 

mid-range of SNCR control efficiencies. 

SCR is a post-combustion gas 

treatment technique that uses either 

ammonia or urea in the presence of a 

metal-based catalyst to selectively 

reduce NOX to molecular nitrogen, 

water, and oxygen. The catalyst lowers 

the temperature required for the 

chemical reaction between NOX and the 

reducing agent. Technical factors that 

impact the effectiveness of this 

technology include the catalyst reactor 

design, operating temperature, type of 

fuel fired, sulfur content of the fuel, 

design of the ammonia injection system, 

and the potential for catalyst poisoning. 

SCR has been installed on numerous 

coal-fired boilers of varying sizes, and is 

considered technically feasible. We note 

that SCRs are classified as a low dust 

SCR (LDSCR) or high dust SCR 

(HDSCR). As explained in the TSD, the 

SCR system considered in this analysis 

is the HDSCR. 

Existing vendor literature and 

technical studies indicate that SCR 

systems are capable of achieving 

approximately 80 to 90 percent control 

efficiency, and that this emission rate 

can be achieved on a retrofit basis, 

particularly when combined with 

combustion control technology such as 

LNB.48 Our contractor used a design 

emission rate of 0.050 lb/MMBtu 

(annual average), which in the case of 

Sundt Unit 4 corresponds to a control 

efficiency of 89 percent. While this is a 

value close to the upper range of SCR 

control efficiency, we consider the use 

of 0.050 lb/MMBtu appropriate for 

Sundt Unit 4. A review of Acid Rain 

Program data indicates that there are up 

to seven dry-bottom, wall-fired boilers 

operating with SCR on a retrofit basis 

that have achieved an annual average 

emission rate of 0.050 lb/MMBtu or 

lower in practice.49 However, there are 

design differences between Sundt Unit 

4 and these other units (i.e., boiler size, 

coal type and characteristics, and 

loading profile) that have the potential 

to affect this comparison. If we receive 

additional comments that sufficiently 

document source-specific 

considerations justifying the use of an 

emission rate higher than 0.050 lb/

MMBtu, we may incorporate such 

considerations in our selection of BART. 

b. BART Analysis for NOX

Costs of Compliance: In evaluating the 

costs of compliance for SNCR and SCR, 

we calculated the control costs ($) and 

emission reductions (tons/year of 

pollutant) for each control technology, 

and developed average costeffectiveness ($/ton) values. Estimated 

NOX emission reductions are 

summarized in Table 7 and costeffectiveness numbers are summarized 

in Table 8 for each option. A more 

detailed version of emission 

calculations are in our docket 50 and in 

our contractor’s report. The heat duty 

and capacity factor used in the emission 

calculations below differ from the 

values used in the calculations 

originally prepared by our contractor, 

due to the unit’s lower capacity when 

burning coal (130 MW) rather than 

natural gas (173 MW). The heat duty 

(MMBtu/hr) and capacity factor (0.49) 

reflect the coal-burning heat duty, rather 

than the natural gas-burning heat 

duty.51

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9328 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules 

52See spreadsheet ‘‘Sundt4 Control Costs 2014– 

01–26.xlsx’’ in the docket. 

53Letter dated May 10, 2013. 

54 40 CFR Part 51, Appendix Y, section IV.D.4.k. 

55We note that the 20 year amortization period 

is primarily used in NOX control cost calculations, 

such as for SCR. In order to promote consistency 

in the analysis, we have used the 20 year period in 

the cost calculations for other control options, such 

as for SO2 control, for which the Control Cost 

Manual includes examples that use an amortization 

period of 15 years. 

TABLE 7—SUNDT 4: NOX CONTROL OPTION EMISSION ESTIMATES

Control option 

Control 

efficiency 

Emission 

factor 

Heat duty Capacity 

factor 

NOX emission rate NOX

emission 

reduction 

% lb/MMBtu MMBtu/hr % lb/hr tpy 

tpy 

Baseline (LNB+OFA) ............................... .................... 0.445 1,371 0.49 610 1,310 

SNCR+LNB+OFA .................................... 30 0.312 1,371 0.49 427 917 393 

SCR+LNB+OFA ....................................... 89 0.050 1,371 0.49 69 147 1,162 

Our consideration of the cost of 

compliance focuses primarily on the 

cost-effectiveness of each control option 

as measured in average cost per ton and 

incremental cost per ton of each control 

option as shown in Table 8. SCR is the 

most stringent option with the highest 

average cost-effectiveness of $5,176/ton, 

and incremental cost-effectiveness over 

SNCR of $6,174/ton. Detailed cost 

calculations can be found in our 

docket.52 While we have relied 

primarily upon the cost calculations 

prepared by our contractor, we have 

incorporated certain elements of TEP’s 

analysis 53 into our cost calculations. 

The most significant revisions to cost 

estimates include the following: 

• We have changed the unit size from 

173 MW to 130 MW to reflect the gross 

capacity of using coal. Although this has 

the net effect of decreasing certain costs, 

particularly several operation and 

maintenance (O&M) costs, the revised 

capital cost estimates increased for SCR 

(from $38 million to $45 million) and 

SNCR (from $2.8 million to $3.1 

million). 

• We have used a retrofit difficulty 

value of 1.5 (increased from 1.0) in cost 

estimates due to certain difficulties 

associated with retrofit installation of 

SCR. These difficulties are the result of 

site congestion and the configuration of 

the existing boiler structure and coal 

handling system as noted by TEP. 

• We have included the cost of air 

preheater modifications that TEP stated 

are necessary in order to accommodate 

SCR due to site congestion and coal 

handling configuration. 

TABLE 8—SUNDT 4: NOX CONTROL OPTION COST-EFFECTIVENESS

Control option 

Capital 

cost 

Annualized 

capital cost 

Annual operating cost Total annual 

cost 

Emission 

reduction 

Cost-effectiveness 

($/ton) 

($) ($) ($) ($/yr) (tpy) Ave Incremental 

SNCR ....................................................... $3,079,089 $290,644 $975,124 $1,265,768 393 $3,222 

SCR .......................................................... 45,167,561 4,263,498 1,753,975 6,017,474 1,162 5,176 $6,174 

Pollution Control Equipment in Use at 

the Source: The presence of existing 

pollution control technology at Sundt 

Unit 4 is reflected in the consideration 

of available control technologies and in 

the development of baseline emission 

rates for use in cost calculations and 

visibility modeling. In the case of NOX,

current pollution controls are reflected 

in our selection of 2011 as the baseline 

period, which includes the use of LNB 

and OFA. 

Energy and Non-Air Quality 

Environmental Impacts: Regarding 

potential energy impacts of the BART 

control options, we note that SCR incurs 

a draft loss that will result in certain 

load loss, and that other emissions 

controls may also have modest energy 

impacts. The costs for direct energy 

impacts, i.e., power consumption from 

the control equipment and additional 

draft system fans from each control 

technology, are included in the cost 

analyses. Indirect energy impacts, such 

as the energy to produce raw materials, 

are not considered, which is consistent 

with the BART Guidelines. Ammonia 

adsorption (resulting from ammonia 

injection from SCR or SNCR) to fly ash 

is generally not desirable due to odor 

but does not impact the integrity of the 

use of fly ash in concrete. The ability to 

sell fly ash is unlikely to be affected by 

the installation of SNCR or SCR 

technologies. Finally, SNCR and SCR 

may involve potential safety hazards 

associated with the transportation and 

handling of anhydrous ammonia. 

However, since the handling of 

anhydrous ammonia will involve the 

development of a risk management plan 

(RMP), we consider the associated safety 

issues to be manageable as long as 

established safety procedures are 

followed. As a result, we do not 

consider these impacts sufficient to 

warrant the elimination of either of the 

available control technologies. 

Remaining Useful Life of the Source: 

We are considering the ‘‘remaining 

useful life’’ of Sundt Unit 4 as one 

element of the overall cost analysis as 

allowed by the BART Guidelines.54

Since there is not state- or federallyenforceable shut-down date for this 

unit, we have used a 20-year 

amortization period per the EPA Cost 

Control Manual as the remaining useful 

life for the facility.55

Degree of Visibility Improvement: The 

visibility improvement due to NOX

controls is modest. SNCR was modeled 

at a 30 percent NOX emission reduction. 

As shown in Table 9, this yields a 

maximum visibility improvement of just 

over 0.2 dv at Saguaro. Galiuro 

improves about half as much, and other 

areas much less. The cumulative 

improvement across all impacted Class 

I areas is 0.5 dv. SCR was modeled at 

89 percent NOX reduction to achieve 

0.05 lb/MMBtu. SCR provides a 

maximum improvement of 0.8 dv, 

which occurs at Saguaro. Galiuro again 

improves about half as much, and the 

cumulative improvement across all 

Class I areas is 1.6 dv. This visibility 

improvement is substantially greater for 

SCR than for SNCR. 

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56See spreadsheet ‘‘Sundt4 2001–12 Emission 

Calcs 2014–01–24.xlsx’’ in the docket. 

57See ‘‘Typical Installation Timelines for NOX

Emissions Control Technologies on Industrial 

Sources’’, Institute of Clean Air Companies, 

December 4, 2006. 

58Clean Air Act section 169A(g)(4), 42 U.S.C. 

7491(g)(4). 

TABLE 9—SUNDT 4: VISIBILITY IMPACT AND IMPROVEMENT FROM NOX CONTROLS

Class I area Distance 

(km) 

Visibility 

impact 

Visibility 

improvement 

Base case SNCR 

(ctrl04) 

SCR 

(ctrl08) 

Chiricahua NM ........................................................................................................... 144 0 .43 0 .03 0 .12 

Chiricahua WA ........................................................................................................... 141 0 .51 0 .05 0 .15 

Galiuro WA ................................................................................................................ 64 1 .10 0 .12 0 .34 

Gila WA ...................................................................................................................... 232 0 .17 0 .02 0 .04 

Mazatzal WA .............................................................................................................. 203 0 .19 0 .02 0 .04 

Mount Baldy WA ........................................................................................................ 232 0 .15 0 .01 0 .03 

Pine Mountain WA ..................................................................................................... 247 0 .15 0 .02 0 .03 

Saguaro NP ............................................................................................................... 17 3 .40 0 .23 0 .78 

Sierra Ancha WA ....................................................................................................... 178 0 .19 0 .01 0 .04 

Superstition WA ......................................................................................................... 137 0 .32 0 .01 0 .05 

Cumulative (sum) ....................................................................................................... .................... 6 .6 0 .5 1 .6 

Maximum ................................................................................................................... .................... 3 .40 0 .23 0 .78 

# CIAs >= 0.5 dv ....................................................................................................... .................... 3 0 1 

Million $/dv (cumul. dv) .............................................................................................. .................... ...................... $2 .4 $3 .7 

Million $/dv (max. dv) ................................................................................................ .................... ...................... $5 .5 $7 .7 

c. Proposed BART Determination for 

NOX

EPA proposes to find that BART for 

NOX is an emission limit of 0.36 lb/

MMBtu on a 30-day BOD rolling basis 

that is achievable by SNCR with LNB 

and OFA. The primary factors 

supporting this proposed finding are the 

average cost-effectiveness and 

anticipated visibility benefits of 

controls. In particular, while SCR is 

anticipated to achieve the greatest 

degree of visibility improvement, it is 

also significantly more expensive than 

SNCR, with an average costeffectiveness of $5176/ton. We do not 

consider this average cost to be 

warranted by the projected visibility 

benefit of SCR for this facility. Table 10 

provides a summary of our five-factor 

BART analysis. 

In proposing an emission limit of 0.36 

lb/MMBtu, we have considered the 

annual average design value for SNCR of 

0.31 lb/MMBtu as well as the need to 

account for emissions associated with 

startup and shutdown events. To 

account for this variability, we have 

examined the difference between the 

highest 30-day rolling NOX value and 

the highest annual average NOX value 

observed over the baseline period, 

which is approximately 17 percent.56

We have applied this variability to the 

annual average design value to develop 

a 30-day BOD rolling emission limit, 

which we consider to provide sufficient 

margin for a limit that will apply at all 

times. 

We propose to require compliance 

with this requirement within three years 

of the effective date of the final rule. A 

2006 Institute of Clean Air Companies 

(ICAC) study indicated that the 

installation time for a typical SNCR 

retrofit, from bid to startup, is 10 to 13 

months.57 However, because we are also 

requiring the installation of additional 

SO2 controls, we consider a three year 

period for compliance with both BART 

determinations to be appropriate. We 

are seeking comment on whether this 

compliance date is reasonable and 

consistent with the requirement of the 

Clean Air Act that BART be installed 

‘‘as expeditiously as practicable but in 

no event later than five years after 

[promulgation of the applicable FIP].’’ 58

If we receive information during the 

comment period that establishes that a 

different compliance time frame is 

appropriate, we may finalize a different 

compliance date. Finally, we are 

proposing regulatory text that includes 

monitoring, reporting, and 

recordkeeping requirements to ensure 

that the emission limit and compliance 

deadline are enforceable. As part of the 

proposed monitoring requirements, we 

are including a requirement to monitor 

rates of ammonia injection in order to 

ensure proper operation of the SNCR in 

a manner that minimizes ammonia 

emissions. 

TABLE 10—SUNDT 4: SUMMARY OF BART ANALYSIS FOR NOX

Sundt unit 4 (130 MW) LNB+OFA 

(baseline) SNCR+LNB SCR+LNB 

Emissions 

Emission Factor (lb/MMBtu) ...................................................................................................... 0.445 0.312 ................ 0.050 

Emission Rate (tpy) ................................................................................................................... 1310 917 ................... 147 

Emission Reduction (tpy) ........................................................................................................... .................... 393 ................... 1,162 

Control Effectiveness (%) .......................................................................................................... .................... 30% .................. 89% 

Costs of Compliance 

Capital Cost ($) .......................................................................................................................... .................... $3,079,089 ....... $45,167,561 

Annualized Capital Cost ($) ....................................................................................................... .................... $290,644 .......... $4,263,498 

Annual O&M ($) ......................................................................................................................... .................... $975,124 .......... $1,753,975 

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59TEP’s review does not eliminate consideration 

of wet FGD, but does describe several design 

challenges that TEP notes should be reflected in the 

five factor analysis. We have incorporated certain 

elements of TEP’s review in our analysis, as 

discussed in Step 4. 

TABLE 10—SUNDT 4: SUMMARY OF BART ANALYSIS FOR NOX—Continued 

Sundt unit 4 (130 MW) LNB+OFA 

(baseline) SNCR+LNB SCR+LNB 

Total Annual Cost ($) ................................................................................................................ .................... $1,265,768 ....... $6,017,474 

Ave Cost-Effectiveness ($/ton) .................................................................................................. .................... $3,222 .............. $5,176 

Incremental Cost-Effectiveness ($/ton) ..................................................................................... .................... ........................... $6,174 

Pollution Control Equipment in Use 

Low-NOX Burners and Over Fire Air 

Energy and Non-Air Quality Environmental Impacts 

Energy impacts have been reflected in annual O&M costs in the costs of compliance. 

SCR and SNCR may create potential safety and environmental hazards from the transportation and handling of anhydrous ammonia. We consider these impacts manageable with the development of an RMP and additional safety procedures, and do not consider them sufficient 

enough to warrant eliminating either of these available control technologies. 

Remaining Useful Life 

Control technology amortization period ..................................................................................... .................... 20 years ........... 20 years 

Visibility Improvement 

Single largest Class I area improvement (dv) ........................................................................... .................... 0.23 .................. 0.78 

Single Class I area cost-effectiveness (million $/dv) ................................................................ .................... $5.5 .................. $7.7 

Class I areas with ≥ 0.50 dv improvement ................................................................................ .................... 0 ....................... 1 

Cumulative visibility improvement (dv) ...................................................................................... .................... 0.5 .................... 1.6 

Cumulative cost-effectiveness (million $/dv) ............................................................................. .................... $2.4 .................. $3.7 

4. Proposed BART Analysis and 

Determination for SO2

For our SO2 BART analysis, we 

identified all available control 

technologies, eliminated options that 

are not technically feasible, and 

evaluated the control effectiveness of 

the remaining control options. We then 

evaluated each control in terms of a 

five-factor BART analysis and proposed 

a determination for BART. 

a. Control Technology Availability, 

Technical Feasibility, and Effectiveness 

EPA identified three available and 

technically feasible technologies to 

control SO2 emissions from Sundt Unit 

4. These technologies are lime or 

limestone-based wet flue gas 

desulfurization (wet FGD), lime spray 

dry absorber (SDA or dry FGD), and dry 

sorbent injection (DSI). While each of 

these control options has certain design 

concerns and constraints associated 

with their implementation, all three 

options are considered technically 

feasible. 

Lime or limestone-based wet FGD: 

Wet scrubbing systems mix an alkaline 

reagent, such as hydrated lime or 

limestone, with water to generate 

scrubbing slurry that is used to remove 

SO2 from the flue gas. The alkaline 

slurry is sprayed countercurrent to the 

flue gas, such as in a spray tower, or the 

flue gas may be bubbled through the 

alkaline slurry as in a jet bubbling 

reactor. As the alkaline slurry contacts 

the exhaust stream, it reacts with the 

SO2 in the flue gas. Design variations 

may include changes to increase the 

alkalinity of the scrubber slurry, 

increase slurry/SO2 contact, and 

minimize scaling and equipment 

problems. Insoluble calcium sulfite 

(CaSO3) and calcium sulfate (CaSO4) 

salts are formed in the chemical reaction 

that occurs in the scrubber, and exit as 

part of the scrubber slurry. The salts are 

eventually removed and handled as a 

solid waste byproduct. The waste 

byproduct is mainly CaSO3, which is 

difficult to dewater. Solid waste 

byproducts from wet lime scrubbing are 

typically managed in dewatering ponds 

and landfills. 

Design concerns associated with wet 

FGD involve the substantial water usage 

requirements needed to generate the 

alkaline reagent slurry as well as the 

substantial amount of wastewater and 

solid waste discharge associated with 

the spent byproduct. A wet FGD control 

system must be located after the fabric 

filter baghouse because the moist plume 

resulting from the wet scrubber system 

would create baghouse plugging issues 

if the control is placed ahead of the 

baghouse. In addition, a substantial 

footprint is required for the management 

of these waste products as well as for 

the absorber tower and associated 

process equipment such as the slurry 

preparation, mixing, associated tanks, 

and dewatering activities. While these 

design concerns do present some 

challenges, they do not warrant 

elimination of this option as technically 

infeasible.59

Our contractor has estimated that 

newly constructed wet FGD systems 

could achieve design emission rates 

(annual average basis) of 0.06 lb/

MMBtu. Relative to baseline SO2

emission rates, this corresponds to a 

control efficiency of 92 percent. We 

recognize that FGD systems are 

designed to achieve more stringent 

emission rates, and have demonstrated 

an ability to achieve control efficiencies 

up to 98 percent. Our contractor’s report 

notes that the lower control efficiency 

cited here is regarded as a conservative 

estimate. While this is not the most 

stringent level of control that the 

technology is capable of achieving, we 

consider 92 percent control efficiency to 

be consistent with the median values 

reported for wet FGD systems. 

Lime SDA or dry FGD: A spray dryer 

absorber uses a stream of either dry lime 

or hydrated lime (semi-dry) in a reaction 

tower where it reacts with SO2 in the 

flue gas to form calcium sulfite solids. 

Unlike wet FGD systems that produce a 

slurry by-product that is collected 

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Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules 9331 

60 ‘‘Assessment of Control Technology Options 

for BART-Eligible Sources’’, Northeast States for 

Coordinated Air Use Management In Partnership 

with The Mid-Atlantic/Northeast Visibility Union, 

March 2005. 

61 IPM Model—Revisions to Cost and 

Performance for APC Technologies, Dry Sorbent 

Injection Cost Development Methodology, August 

2010. 

62See spreadsheet ‘‘Sundt4 2001–12 Emission 

Calcs 2014–01–24.xlsx’’ in the docket. 

63As noted by TEP and Burns and McDonnell, 

although the calculated capacity factor is different, 

the annual emissions in tons per year removed do 

not change significantly, as the change in capacity 

factor is largely offset by the change in maximum 

unit gross rating. 

64See spreadsheet ‘‘Sundt4 Control Costs 2014– 

01–26.xlsx’’ in the docket. 

separately from the fly ash, dry FGD 

systems are designed to produce a dry 

byproduct that must be removed with 

the fly ash in the particulate control 

equipment. As a result, dry FGD 

systems must be located upstream of the 

particulate control device to remove the 

reaction products and excess reactant 

material. In instances where hydrated 

lime is used as a reagent, the reaction 

towers must be designed to provide 

adequate contact and residence time 

between the exhaust gas and the slurry 

to produce a relatively dry byproduct. 

Typical process equipment associated 

with a spray dryer typically includes an 

alkaline storage tank, mixing and feed 

tanks, an atomizer, spray chamber, 

particulate control device and a recycle 

system. The recycle system collects 

solid reaction products and recycles 

them back to the spray dryer feed 

system to reduce alkaline sorbent use. 

A design concern associated with a 

dry FGD system is that it must be 

installed prior to the fabric filter 

baghouse in order for the reagent to be 

captured and recycled. As noted in our 

contractor’s report, the location of the 

existing fabric filter baghouse does not 

present enough space to install a new 

absorber between the boiler and the 

existing baghouse. As a result, a dry 

FGD at Sundt Unit 4 is assumed to 

include a new baghouse, which is 

reflected in the costs of compliance for 

the five-factor analysis. We consider this 

control option to be technically feasible. 

Our contractor has estimated that 

newly constructed dry FGD systems 

could achieve design emission rate 

(annual average basis) of 0.08 lb/

MMBtu. Relative to baseline SO2

emission rates, this corresponds to a 

control efficiency of 89 percent. As 

noted for wet FGD systems, this is a 

conservative estimate of what dry FGD 

systems can achieve, and is consistent 

with the median values reported for dry 

FGD systems. 

Dry Sorbent Injection: DSI involves 

the injection of powdered absorbent 

directly into the flue gas exhaust stream. 

These are simple systems that generally 

require a sorbent storage tank, feeding 

mechanism, transfer line and blower, 

and an injection device. The dry sorbent 

is typically injected countercurrent to 

the gas flow. An expansion chamber is 

often located downstream of the 

injection point to increase residence 

time and efficiency. Particulates 

generated in the reaction are controlled 

in the system’s particulate control 

device. DSI requires less capital 

equipment, less physical space, and less 

modification to existing ductwork 

compared to a dry FGD system. 

However, reagent costs are much higher 

and, depending upon the absorbent and 

amount of sorbent injected, control 

efficiency is lower when compared to a 

dry FGD system. Soda ash and Trona 

(sodium sesquicarbonate) are potential 

options for reagent use. An important 

design consideration of DSI is the ability 

of the downstream particulate control 

device to accommodate the additional 

particulate loading resulting from the 

addition of the DSI reagent into the 

boiler flue gas. More effective 

particulate control devices allow for 

higher rates of sorbent injection, which 

in turn allow for more effective SO2

control. 

In a review of SO2 control options for 

BART eligible units, the Northeast 

States for Coordinated Air Use 

Management (NESCAUM) estimated 

control effectiveness for DSI in a range 

of 40–60 percent.60 More recently, as 

part of work done as part of the 

Integrated Planning Model (IPM), EPA 

has estimated control effectiveness as 

high as 80 percent,61 depending upon 

factors such as the type of sorbent, the 

quantity of sorbent used, and the type 

of particulate control device employed. 

Generally, the use of more effective 

particulate control devices allow for 

higher rates of sorbent injection, and 

therefore greater DSI effectiveness. 

Since Sundt Unit 4 operates with a 

fabric filter, we consider a control 

effectiveness value in the upper range 

appropriate, and have used 70 percent 

control effectiveness in our calculations. 

This value is above the range indicated 

in the NESCAUM study, but does not 

require the high sorbent injection rates 

required to achieve the upper range of 

control indicated in IPM 

documentation. A summary of the 

control technologies and their 

associated control effectiveness is 

presented in Table 11. 

TABLE 11—SUNDT 4: SO2 CONTROL

OPTIONS

Control option 

Control effectiveness 

% 

Dry Sorbent Injection ............ 70 

Dry FGD or Lime SDA ......... 89 

TABLE 11—SUNDT 4: SO2 CONTROL

OPTIONS—Continued 

Control option 

Control effectiveness 

% 

Wet FGD (lime- or limestone-based) ..................... 92 

b. BART Analysis for SO2

Costs of Compliance: Our 

consideration of the costs of compliance 

focuses primarily on the costeffectiveness of each control option, as 

measured in cost per ton and 

incremental cost per ton. The emissions 

estimates and cost-effectiveness for the 

three control options are shown in Table 

12 and Table 13, respectively. Both wet 

and dry FGD have average costeffectiveness values over $5,000/ton, 

much greater than DSI, which is a 

control option that we consider very 

cost-effective at $1,857/ton. Moreover, 

both wet and dry FGD have very high 

incremental cost-effectiveness values, 

indicating that while they are more 

effective than less stringent control 

options, this additional degree of 

effectiveness comes at a substantial cost. 

In evaluating the costs of compliance 

for the control options, we have 

calculated the control costs ($) and 

emission reductions (tons/year of 

pollutant) for each control technology, 

developed average cost-effectiveness ($/ 

ton) values, and arrived at the emission 

reductions for each option as 

summarized Table 12. A more detailed 

version of emission calculations is in 

our docket,62 and in our contractor’s 

report. As noted previously in our NOX

BART analysis, the heat duty and 

capacity factor used in these 

calculations differ from the values used 

in the calculations originally prepared 

by our contractor because the maximum 

gross capacity of Sundt Unit 4 while 

burning coal is about 130 MW, 

compared to its natural-gas nameplate 

capacity of 173 MW. The heat duty 

(MMBtu/hr) and capacity factor used in 

Table 12 reflect the coal-burning 

nameplate capacity.63 Detailed cost 

calculations presented in Table 13 are in 

the docket.64

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9332 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules 

TABLE 12—SUNDT 4: SO2 CONTROL OPTION EMISSION ESTIMATES

Control option 

Control 

efficiency 

Emission 

factor 

Heat 

duty Capacity 

factor 

SO2 emission rate SO2

emission 

reduction 

(%) (lb/MMBtu) (MMBtu/hr) (lb/hr) (tpy) 

(tpy) 

Baseline (no control) ................................ .................... 0.729 1,371 0.49 1,000 2,145 

DSI ........................................................... 70 0.219 1,371 0.49 300 644 1,502 

DFGD ....................................................... 89 0.080 1,371 0.49 110 236 1,909 

WFGD ...................................................... 92 0.060 1,371 0.49 82 177 1,969 

TABLE 13—SUNDT 4: SO2 CONTROL OPTION COST-EFFECTIVENESS

Control option 

Capital 

cost 

Annualized 

capital cost 

Annual operating cost Total annual 

cost 

Emission 

reduction 

Cost-effectiveness 

($/ton) 

($) ($) ($) ($/yr) (tpy) Ave Incremental 

DSI ........................................................... $3,250,000 $306,777 $2,482,107 $2,788,884 1,502 $1,857 

DFGD ....................................................... 72,470,559 6,840,708 2,880,841 9,721,549 1,909 5,091 $17,007 

WFGD ...................................................... 80,629,663 7,610,870 3,227,467 10,838,337 1,969 5,505 18,795 

Pollution Control Equipment in use at 

Source: In the case of SO2, Sundt Unit 

4 does not operate with any existing 

control technology. This is reflected in 

our selection of calendar year 2011 as 

the baseline period, which represents 

uncontrolled coal-fired emissions. 

Energy and Non-Air Quality 

Environmental Impacts: For wet FGD, 

energy impacts include certain auxiliary 

power requirements that are necessary 

to operate the wet FGD system and to 

potentially compensate for pressure 

head loss through the scrubber. These 

energy impacts are reflected as auxiliary 

power costs in the cost of compliance 

estimates. Non-air quality 

environmental impacts include water 

usage requirements and the storage and 

disposal of wet ash. Wet FGD requires 

very large quantities of water to ensure 

proper control effectiveness. Securing 

such quantities of water is a significant 

challenge in more arid regions of the 

country such as Arizona, and would 

preclude the use of that water for 

potentially more beneficial uses. The 

on-site storage and disposal of wet ash 

in large retention ponds triggers 

significant additional regulatory 

requirements, as it represents a 

substantial water pollution threat. 

For dry FGD, the energy and non-air 

environmental impacts are similar to 

those for wet FGD. Operation of a dry 

FGD system still requires securing 

significant supplies of water, although 

to a lesser degree than wet FGD systems. 

In addition, dry FGD systems will result 

in generation of larger quantities of 

boiler ash, and has the potential to affect 

negatively the properties and quality of 

boiler ash. In some instances, boiler ash 

that is suitable to sell for beneficial 

purposes may no longer be marketable 

following installation of a dry FGD 

system. Energy impacts also include 

auxiliary power requirements for 

operation of the dry FGD system, and 

for overcoming pressure head loss 

through the scrubber. While we note 

certain potential impacts resulting from 

the water resource requirements 

associated with wet FGD as well as the 

additional solid waste generation 

associated with wet and dry FGD, we do 

not consider these impacts sufficient 

enough to warrant eliminating these 

control technologies. 

DSI could potentially have an adverse 

effect on the quality of the boiler fly ash, 

which would make it unmarketable for 

beneficial uses. Use of DSI also results 

in an ash byproduct which would 

require landfill disposal, thereby 

increasing solid waste generation rates 

at the plant. Energy impacts are limited 

to auxiliary power requirements for 

operation of the DSI system. We do not 

consider these impacts sufficient 

enough to warrant eliminating this 

control technology. 

Remaining Useful Life of the Source: 

We are considering the remaining useful 

life of Sundt Unit 4 as one element of 

the overall cost analysis as allowed by 

the BART Guidelines. Since we are not 

aware of any federally- or Stateenforceable shut down date for Sundt 

Unit 4, we have used a 20-year 

amortization period described in the 

EPA Cost Control Manual as the 

remaining useful life for the control 

options considered for Unit 4. We note 

that the remaining useful life of the 

source is reflected in the evaluation of 

cost of compliance through the use of a 

20-year amortization period in control 

cost calculations. 

Degree of Visibility Improvement: The 

visibility improvement due to SO2

controls is modest. As shown in Table 

14, control via DSI, with a 70 percent 

SO2 emissions reduction, gives a 

maximum visibility improvement of 0.2 

dv, which occurs at Saguaro. Three 

other areas improve about half as much, 

and the cumulative improvement is 0.8 

dv. Emissions controls via dry and wet 

FGD were modeled at 89 percent and 92 

percent SO2 emissions reduction, 

respectively. Both dry and wet FGD 

would cause a visibility disbenefit at 

Saguaro as indicated by the negative 

improvements in Table 14. The 

disbenefit is mainly due to the 

decreased stack exit temperature and 

exit velocity associated with these 

technologies, and more so for wet FGD 

than for dry FGD. These stack decreases 

result in less plume rise and increased 

impacts nearby. At areas farther away, 

the disbenefit is outweighed by the 

benefit of SO2 reductions from FGD. 

This issue is discussed further in the 

TSD. With FGD, the maximum benefit 

occurs not at Saguaro, but at Galiuro, 

with 0.2 dv for dry FGD and 0.1 dv for 

wet FGD. The corresponding cumulative 

improvements are 0.6 dv and 0.4 dv for 

dry and wet FGD, respectively, 

including the areas of disbenefit. All 

these improvements are substantially 

lower than those from DSI, and the 

visibility cost-effectiveness of each FGD 

is more than quadruple that of DSI. EPA 

finds that the improvement from DSI is 

substantial enough to support its 

selection as BART, and that it is clearly 

a better choice than dry FGD and wet 

FGD. 

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Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules 9333 

65See spreadsheet ‘‘Sundt4 2001–12 Emission 

Calcs 2014–01–24.xlsx’’ in the docket. 

66Clean Air Act section 169A(g)(4), 42 U.S.C. 

7491(g)(4). 

TABLE 14—SUNDT 4: VISIBILITY IMPACT AND IMPROVEMENT FROM SO2 CONTROLS

Class I Area Distance 

(km) 

Visibility impact Visibility improvement 

Base 

case 

DSI 70% 

(ctrl14) 

Dry FGD 

(ctrl02) 

Wet FGD 

(ctrl03) 

Chiricahua NM ................................................................................. 144 0.43 0.05 0.07 0.06 

Chiricahua Wild ................................................................................ 141 0.51 0.10 0.10 0.11 

Galiuro Wild ..................................................................................... 64 1.10 0.10 0.16 0.09 

Gila Wild ........................................................................................... 232 0.17 0.04 0.05 0.05 

Mazatzal Wild ................................................................................... 203 0.19 0.07 0.08 0.09 

Mount Baldy Wild ............................................................................. 232 0.15 0.05 0.05 0.06 

Pine Mountain Wild .......................................................................... 247 0.15 0.05 0.06 0.06 

Saguaro NP ..................................................................................... 17 3.40 0.20 ¥0.16 ¥0.27 

Sierra Ancha Wild ............................................................................ 178 0.19 0.06 0.08 0.08 

Superstition Wild .............................................................................. 137 0.32 0.09 0.10 0.10 

Cumulative (sum) ............................................................................. .................... 6.6 0.8 0.6 0.4 

Maximum .......................................................................................... .................... 3.40 0.20 0.16 0.11 

# CIAs >= 0.5 dv .............................................................................. .................... 3 0 0 0 

Million $/dv (cumul. dv) .................................................................... .................... ............................ $3.5 $16.4 $25.1 

Million $/dv (max. dv) ....................................................................... .................... ............................ $14 $60 $97 

c. BART Determination for SO2

EPA proposes an emission limit of 

0.23 lb/MMBtu on a 30-day (BOD) 

rolling basis as BART to control SO2

from Sundt Unit 4. This emission limit, 

equivalent to using DSI, is considered 

very cost-effective at $1,857/ton. In 

evaluating the appropriate emission 

limit for DSI, we have considered the 

annual average design value for DSI of 

0.21 lb/MMBtu as well as the need to 

account for emissions associated with 

startup and shutdown events. To 

determine how to account for this 

variability, we have examined the 

difference between the highest 30-day 

rolling SO2 value and the highest annual 

average SO2 value observed over the 

baseline period, which is approximately 

9 percent.65 We have applied this 

variability to the annual average design 

value to develop a 30-day BOD rolling 

emission limit, which we consider a 

sufficient margin for a limit that will 

apply at all times. Please refer to Table 

15 that provides a summary of our fivefactor BART analysis. 

We propose to require compliance 

with this requirement within three years 

of the effective date of the final rule. 

However, we are seeking comment on 

whether this compliance date is 

reasonable and consistent with the 

requirement of the Clean Air Act that 

BART be installed ‘‘as expeditiously as 

practicable but in no event later than 

five years after [promulgation of the 

applicable FIP].’’ 66 If we receive 

information during the comment period 

that establishes that a different 

compliance time frame is appropriate, 

we may finalize a different compliance 

date. We are also proposing regulatory 

text that includes monitoring, reporting, 

and recordkeeping requirements 

associated with this emission limit. 

TABLE 15—SUNDT 4: SUMMARY OF BART ANALYSIS FOR SO2

Sundt Unit 4 (130 MW) Baseline DSI Dry FGD Wet FGD 

Emission Factor (lb/MMBtu) ....................................................................... 0.729 0.219 ................ 0.08 .................. 0.06 

Emission Rate (tpy) .................................................................................... 2145 644 ................... 236 ................... 177 

Emission Reduction (tpy) ............................................................................ .................... 1,502 ................ 1,909 ................ 1,969 

Control Effectiveness .................................................................................. .................... 70% .................. 89% .................. 92% 

Cost of Compliance 

Capital Cost ($) ........................................................................................... .................... $3,250,000 ....... $72,470,559 ..... $80,629,663 

Annualized Capital Cost ($) ........................................................................ .................... $306,777 .......... $6,840,708 ....... $7,610,870 

Annual O&M ($) .......................................................................................... .................... $2,482,107 ....... $2,880,841 ....... $3,227,467 

Total Annual Cost ($) .................................................................................. .................... $2,788,884 ....... $9,721,549 ....... $10,838,337 

Ave CE ($/ton) ............................................................................................ .................... $1,857 .............. $5,091 .............. $5,505 

Incremental CE ($/ton) ................................................................................ .................... ........................... $23,081 ............ $18,795 

Pollution Control Equipment in Use at Source 

There is no existing control technology for SO2

Energy and Non-Air Quality Environmental Impacts 

Energy impacts are reflected in annual O&M costs in the costs of compliance. 

Wet ash from wet and dry FGD represents a substantial water pollution threat. 

Water resources for wet and dry FGD may preclude more beneficial uses of water. 

Remaining Useful Life 

Control technology amortization period ...................................................... .................... 20 years ........... 20 years ........... 20 years 

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9334 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules 

67 77 FR 9304, 9450, 9458 (February 16, 2012) 

(codified at 40 CFR 60.42Da(a), 60.50Da(b)(1)). 

68See Memorandum from Jeffrey Cole (RTI 

International) to Bill Maxwell (EPA) regarding 

‘‘National Emission Standards for Hazardous Air 

Pollutants (NESHAP) Maximum Achievable Control 

Technology (MACT) Floor Analysis for Coal- and 

Oil-fired Electric Utility Steam Generating Units for 

Final Rule’’ (December 16, 2011). 

69 40 CFR Part 51, Appendix Y, Section IV.C. 

70 40 CFR Part 51, Appendix Y, Section IV.D.1.5, 

‘‘STEP 1: How do I identify all available retrofit 

emission control techniques?’’ 

71Letter dated November 1, 2013. 

72 40 CFR 51.308(e)(2). 

73 40 CFR 51.308(e)(3). 

TABLE 15—SUNDT 4: SUMMARY OF BART ANALYSIS FOR SO2—Continued 

Sundt Unit 4 (130 MW) Baseline DSI Dry FGD Wet FGD 

Visibility Improvement 

Single largest Class I area improvement (dv) ............................................ .................... 0.20 .................. 0.16 .................. 0.11 

Single Class I area cost-effectiveness (million $/dv) .................................. .................... $14.3 ................ $60.4 ................ $96.8 

Class I areas with ≥ 0.50 dv improvement ................................................. .................... 0 ....................... 0 ....................... 0 

Cumulative visibility improvement (dv) ....................................................... .................... 0.8 .................... 0.6 .................... 0.4 

Cumulative cost-effectiveness (million $/dv) .............................................. .................... $3.5 .................. $16.4 ................ $25.1 

3. Proposed BART Analysis and 

Determination for PM10

a. Control Technology Availability, 

Technical Feasibility, and Effectiveness 

Sundt Unit 4 currently operates with 

a fabric filter baghouse for particulate 

control, which is considered the most 

stringent control device for particulate 

matter. These devices operate on the 

same principle as a vacuum cleaner. Air 

carrying dust particles is forced through 

a cloth bag that is designed and 

manufactured to trap particles greater 

than a certain specified diameter. As the 

air passes through the fabric, the dust 

accumulates on the cloth and is 

removed from the air stream. The 

accumulated dust is periodically 

removed from the cloth by shaking or by 

reversing the air flow. The layer of dust, 

known as dust cake, trapped on the 

surface of the fabric has the potential to 

result in high efficiency rates for 

particles ranging in size from submicron 

to several hundred microns in diameter. 

b. BART Analysis for PM10

The BART Guidelines provide that, 

where a source has controls already in 

place that are the most stringent 

controls available, it is not necessary to 

complete comprehensively a full fivefactor BART analysis, as long the most 

stringent controls available are made 

federally enforceable. Therefore, instead 

of completing the remaining steps of a 

five-factor BART analysis, we have 

evaluated the appropriate level of 

emissions to ensure that the fabric filter 

achieves an appropriate degree of 

control. 

c. Proposed BART Determination for 

PM10

EPA is proposing a filterable PM10

BART emission limit of 0.03 lb/MMBtu 

based on the use of the existing fabric 

filter baghouse currently in operation, 

which is the most stringent control for 

particulate matter. We note that 

Mercury and Air Toxics (MATS) Rule 

establishes an emission standard of 0.03 

lb/MMBtu filterable PM (as a surrogate 

for toxic non-mercury metals) as 

representing Maximum Achievable 

Control Technology (MACT) for coalfired EGUs.67 This standard derives 

from the average emission limitation 

achieved by the best performing 12 

percent of existing coal-fired EGUs, as 

based upon test data used in developing 

the MATS Rule.68 The BART Guidelines 

provide that, ‘‘unless there are new 

technologies subsequent to the MACT 

standards which would lead to costeffective increases in the level of 

control, you may rely on the MACT 

standards for purposes of BART.’’ 69

Therefore, we propose to find that 0.03 

lb/MMBtu filterable PM10 is an 

appropriate limit for BART at Sundt 

Unit 4. 

4. Better Than BART Alternative 

We are proposing a switch to natural 

gas on Sundt Unit 4 as a better-thanBART alternative to the emissions 

controls previously proposed in this 

section for a coal-fired unit. Unit 4 was 

originally constructed as a natural gasfired boiler, and has used natural gas as 

a primary fuel for significant periods of 

time since 2009. While a change in fuel 

supply to natural gas instead of coal is 

an inherently less polluting option, the 

BART Guidelines do not require the 

consideration of fuel supply changes as 

a control option.70 As a result, the 

option of burning only natural gas is not 

considered in our BART analysis. 

However, TEP has submitted to EPA an 

alternative to BART based on the 

elimination of coal as a fuel source for 

Sundt Unit 4 by December 31, 2017. As 

part of this submittal, TEP compared the 

potential emission reductions and 

visibility benefit between a natural gas 

fuel change and certain combinations of 

NOX and SO2 controls.71

EPA has evaluated this alternative 

proposal pursuant to the ‘‘better-thanBART’’ provisions of the RHR. In 

particular, the RHR allows for 

implementation of ‘‘an emissions 

trading program or other alternative 

measure’’ in lieu of BART if the 

alternative measure achieves greater 

reasonable progress than would be 

achieved through the installation and 

operation of BART.72 The rule further 

states that ‘‘[i]f the distribution of 

emissions is not substantially different 

than under BART, and the alternative 

measure results in greater emissions 

reductions, than the alternative 

measures may be deemed to achieve 

greater reasonable progress’’.73 Because 

the emissions reductions under EPA’s 

BART proposal for Sundt Unit 4 and the 

reductions from TEP’s proposed 

alternative would occur at the same 

facility, the distribution of emissions 

under BART and the alternative are not 

substantially different. Therefore, if the 

alternative emission control strategy 

results in greater emissions reductions 

than our BART proposal, EPA may 

deem the alternative emission control 

strategy to achieve greater reasonable 

progress. A comparison of annual 

emission estimates between the BART 

determination and alternative to BART 

is summarized in Table 16. BART 

determination annual emissions are 

based upon the annual average emission 

factors and annual capacity factor used 

in our BART analysis, consistent with 

coal usage. For the alternative to BART, 

annual emissions are based on a 

combination of historical natural gas 

usage data as indicated in TEP’s 

submittal, as well as standard emission 

factors for natural gas combustion. A 

more detailed discussion of emission 

estimates from these two scenarios is 

included in our TSD. 

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Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules 9335 

TABLE 16—SUNDT 4: COMPARISON OF BART DETERMINATION AND ALTERNATIVE TO BART 

Parameters Units BART determination Natural gas fuel switch Difference 

Heat Duty ............................... MMBtu/hr ............................... 1,371 ...................................... 1,828.

Capacity Factor ...................... ................................................ 0.49 ........................................ 0.37.

NOX ........................................ Ctrl Tech ................................ SNCR+LNB+OFA .................. LNB+OFA.

lb/MMBtu 1 .............................. 0.31 ........................................ 0.22.

tpy .......................................... 917 ......................................... 652 ......................................... 265 

Particulate Matter ................... Ctrl Tech ................................ Fabric Filter ............................ None.

lb/MMBtu 1 .............................. 0.03 ........................................ 0.01.

tpy .......................................... 88 ........................................... 30 ........................................... 59 

SO2 ......................................... Ctrl Tech ................................ Dry Sorbent Injection ............. None.

lb/MMBtu1 .............................. 0.22 ........................................ 0.00064.

tpy .......................................... 644 ......................................... 1.9 .......................................... 642 

1Annual average emission factors. 

As seen in Table 16, a change to 

natural gas usage achieves greater 

emission reductions than each of the 

individual BART determinations for 

NOX, SO2, and particulate matter, as 

well as in the aggregate. Although 

visibility modeling is not required to 

support a better-than-BART 

determination in this instance, EPA 

conducted modeling to verify the 

visibility benefits of the proposed 

alternative, as compared with EPA’s 

BART determination. This modeling is 

described in the TSD and the results are 

summarized in Table 17. 

TABLE 17—SUNDT 4: VISIBILITY IMPACT AND IMPROVEMENT FROM COMBINED SO2 AND NOX BART, AND FROM BETTERTHAN-BART ALTERNATIVE

Class I Area Distance 

(km) 

Visibility 

impact 

Visibility improvement 

Base case 

SNCR DSI 

70% 

(ctrl15) 

Natural gas 

(ctrl13) 

Chiricahua NM ................................................................................................................. 144 0.43 0.09 0.19 

Chiricahua WA ................................................................................................................. 141 0.51 0.16 0.25 

Galiuro WA ...................................................................................................................... 64 1.10 0.24 0.47 

Gila WA ............................................................................................................................ 232 0.17 0.06 0.10 

Mazatzal WA .................................................................................................................... 203 0.19 0.08 0.12 

Mount Baldy WA .............................................................................................................. 232 0.15 0.06 0.09 

Pine Mountain WA ........................................................................................................... 247 0.15 0.06 0.09 

Saguaro NP ..................................................................................................................... 17 3.40 0.49 1.06 

Sierra Ancha WA ............................................................................................................. 178 0.19 0.08 0.12 

Superstition WA ............................................................................................................... 137 0.32 0.11 0.19 

Cumulative (sum) ............................................................................................................. 6.6 1.4 2.7 

Maximum ......................................................................................................................... 3.40 0.49 1.06 

# CIAs >= 0.5 dv ............................................................................................................. 3 0 1 

Million $/dv (cumul. dv) .................................................................................................... $2.8 

Million $/dv (max. dv) ...................................................................................................... $8.3 

Since Sundt is only 17 km from the 

eastern unit of Saguaro, its emitted NOX

may not be fully converted to NO2 by 

the time it reaches there, as is assumed 

in the CALPUFF model. It thus may not 

be fully available to form visibilitydegrading particulate nitrate. EPA 

explored this issue in CALPUFF 

sensitivity simulations described in the 

TSD. For EPA’s proposed BART of 

SNCR plus DSI, the visibility 

improvement remains above 0.3 dv even 

when unrealistically low 10 percent 

NO-to-NO2 conversion is assumed (i.e., 

no additional conversion of NO to NO2

once the plume leaves the stack). The 

improvement from switching to natural 

gas remains above 0.7 dv at Saguaro. 

These results show that the FIP’s 

proposed BART determination remains 

reasonable despite any concern over the 

NO conversion rate; the visibility 

improvement from BART remains 

substantial. The finding that natural gas 

provides better visibility improvement 

than the proposed BART determination 

also remains sound regardless of the NO 

conversion assumed. 

Based on this information, we 

consider a natural gas fuel switch to 

result in greater emission reductions 

and achieve greater reasonable progress 

than the proposed BART 

determinations. Under this scenario, we 

are proposing a NOX emission limit of 

0.25 lb/MMBtu based on a 30-day BOD 

rolling average. As discussed previously 

in the NOX BART determination, this 

represents about a 17 percent increase 

from the annual average emission rate of 

0.22 lb/MMBtu, which we consider to 

provide sufficient margin for a limit that 

will apply at all times, including 

periods of startup and shutdown. In 

addition, we are proposing particulate 

matter and SO2 emission limits 

consistent with natural gas use, as well 

as monitoring, reporting, and 

recordkeeping requirements. 

B. Chemical Lime Nelson Plant Kilns 1 

and 2 

Summary: EPA is proposing to find 

that Chemical Lime Nelson is subject to 

BART. EPA is proposing BART 

emission limits for NOX, SO2 and PM10

for Kilns 1 and 2 at the Nelson Plant as 

listed in Table 18 and described in this 

section. 

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9336 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules 

74Technical Analysis for Arizona and Hawaii 

Regional Haze FIPs: Task 7: Five-Factor BART 

Analysis for Chemical Lime Company Nelson, TEP 

Sundt (Irvington), and Catalyst Paper (Snowflake) 

Plants, Contract No. EP–D–07–102, Work 

Assignment 5–12; Prepared for EPA Region 9 by 

University of North Carolina at Chapel Hill, ICF 

International, and Andover Technology Partners; 

October 9, 2012. 

75BART Five Factor Analysis, Lhoist North 

America Nelson Lime Plant; Prepared by Trinity 

Consultants in Conjunction with Lhoist North 

America of Arizona, Inc.; Project 131701.0061; 

August 2013. (Public version dated September 27, 

2013). 

76Title V Operating Permit and Technical 

Support Document for the Nelson Lime Plant, 

Permit # 42782, Issued August 8, 2011 by the 

Arizona Department of Environmental Quality. 

77 78 FR 46175 (codified at 40 CFR 

52.145(g)(1)(i)). 

TABLE 18—NELSON LIME PLANT: SUMMARY OF PROPOSED BART DETERMINATIONS

Source Pollutant Emission Limit (lb/ton feed) Control technology* (for 

reference only) 

Kiln 1 ................................. NOX .................................. 3.80 Selective Non-Catalytic Reduction (SNCR). 

SO2 ................................... 9.32 Lower sulfur fuel. 

PM10 ................................. 0.12 Fabric filter baghouse (existing). 

Kiln 2 ................................. NOX .................................. 2.61 Selective Non-Catalytic Reduction (SNCR). 

SO2 ................................... 9.73 Lower sulfur fuel. 

PM10 ................................. 0.12 Fabric filter baghouse (existing). 

* The facility is not required to install the listed technology to meet the BART limit. 

Affected Class I Areas: Nine Class I 

areas are within 300 km of the Nelson 

Lime Plant. Their nearest borders range 

from 24 km to 289 km away, with the 

Grand Canyon the closest and other 

areas more than 100 km away. The 

highest baseline visibility impact from 

the Nelson Plant is 1.79 dv at Grand 

Canyon NP followed by 0.31 at 

Sycamore Canyon WA and 0.28 at Zion 

NP. The cumulative sum of visibility 

impacts over all the Class I areas is 3.34 

dv. 

Facility Overview: The Nelson Plant 

processes limestone and manufactures 

lime near Peach Springs in Yavapai 

County, Arizona. The limestone 

processing plant consists of a quarry 

mining operation, a limestone crushing 

and screening operation, a limestone 

kiln feed system, a solid fuel handling 

system, two rotary lime kilns, front and 

back lime handling systems, a lime 

hydrator, diesel electric generators, fuel 

storage tanks, and other support 

operations and equipment. The lime 

manufacturing equipment consists of 

two lime rotary kilns (Kiln 1 and Kiln 

2) and auxiliary equipment necessary 

for receiving crushed limestone, 

processing it through the lime kilns, and 

processing the lime kiln product. The 

lime kilns are used to convert crushed 

limestone (CaCO3) into quicklime (CaO). 

We primarily relied on four sources of 

information for our proposed BART 

analyses and determinations. An initial 

BART analysis performed by our 

contractor 74 is available in the docket in 

the form of a final contractor’s report 

and associated modeling spreadsheets. 

We also incorporated elements of a fivefactor BART analysis 75 provided by 

Lhoist North America (LNA) of Arizona, 

owner of the Nelson Plant, that includes 

control cost estimates and visibility 

modeling. Another key document in our 

analysis is the Nelson Lime Plant’s Title 

V Operating Permit.76

Baseline Emissions Calculations: 

LNA’s approach to establishing baseline 

emissions was to first establish baseline 

emission factors in lb/ton lime based on 

CEMS testing performed from March to 

June 2013. Annual average baseline 

emissions were calculated by 

multiplying these lb/ton emission 

factors by the highest annual lime 

production rate observed over a period 

from 2001 to 2012. Maximum daily 

emissions were calculated by 

multiplying lb/ton emission factors by 

the maximum daily lime production 

rate observed during the March to June 

2013 testing period. As explained in 

further detail in our TSD, we consider 

LNA’s general approach appropriate, 

but also note that it represents a 

conservatively high estimate of baseline 

emissions, and potentially overstates the 

anticipated emission reductions and 

visibility benefit from the evaluated 

control options. Nonetheless, given the 

lack of measured annual emissions data, 

we concur with LNA’s use of a 

conservatively high baseline emissions 

estimate and we have incorporated this 

estimate into our analysis. The baseline 

daily and annual emission rates and 

associated production levels are shown 

in Table 19. 

TABLE 19—NELSON LIME PLANT: SUMMARY OF MAXIMUM DAILY AND ANNUAL BASELINE EMISSIONS FOR NOX AND SO2

Kiln 

Lime production NOX SO2

Max daily 2 Max annual Year Emission 

factor 1 Maximum emissions Emission factor 1 Maximum emissions 

(tpd) (tpy) (lb/ton lime) (lb/day) (tpy) (lb/ton lime) (lb/day) (tpy) 

Kiln 1 ........ 866 3 258,508 2010 7.59 6,573 981 12.15 10,522 1,570 

Kiln 2 ........ 1,246 4 378,296 2012 5.21 6,492 985 12.69 15,812 2,400 

1 Maximum emission factors observed during March, May and June 2013 CEMS testing. 

2 Maximum daily rates occurring during the March 2013 CEMS testing. 

3 2010. 

4 2012. 

1. Proposed Subject to BART 

As part of our July 30, 2013 final 

rulemaking on the Arizona RH SIP, we 

approved ADEQ’s finding that Chemical 

Lime Nelson Plant (Nelson Lime Plant) 

Kilns 1 and 2 were BART-eligible, but 

disapproved ADEQ’s determination that 

the Nelson Lime Plant was not subject 

to BART.77 In light of this disapproval, 

we have conducted our own evaluation 

of whether Nelson Lime Plant is subject 

to BART, relying primarily on emissions 

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Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules 9337 

78BART Five Factor Analysis, Lhoist North 

America Nelson Lime Plant; Prepared by Trinity 

Consultants in Conjunction with Lhoist North 

America of Arizona, Inc.; Project 131701.0061; 

August 13, 2013 (Public version dated September 

27, 2013). 

79 Id., Table 4–7. We note that the visibility 

modeling performed by LNA used only the annual 

average Class I area background concentrations, 

rather than the best 20 percent days background 

concentrations. The use of annual average generally 

results in lower visibility impacts than the best 20 

percent days. Therefore, had LNA used the best 20 

percent days, the baseline impacts would likely 

have been even greater. 

80 Described on page 5–2, ‘‘BART Five Factor 

Analysis, Lhoist North America Nelson Lime Plant’’ 

(Public version dated September 27, 2013). 

data and modeling results provided by 

the facility’s owner, LNA.78

As explained in the TSD, the baseline 

emissions estimates and the 

corresponding modeling results 

provided by LNA are conservative (i.e., 

tending to overestimate rather than 

underestimate the impacts, in this case). 

Nonetheless, we consider these results 

to be appropriate for purposes of a 

subject-to-BART determination, as well 

as for the five-factor BART analysis. 

LNA’s modeling results indicate that the 

98th percentile impact for each of the 3 

years modeled is well over 0.5 dv at 

Grand Canyon National Park.79

Therefore, we propose to determine that 

Nelson Lime Plant (Kilns 1 and 2) is 

subject to BART. 

2. Proposed BART for NOX

For our NOX BART analysis, we 

identified all available control 

technologies, eliminated options that 

are not technically feasible, and 

evaluated the control effectiveness of 

the remaining control options. We then 

evaluated each control in terms of a 

five-factor BART analysis and made a 

determination for BART. 

a. Control Technology Availability, 

Technical Feasibility and Effectiveness 

EPA proposes to find that SNCR is the 

only technically feasible control option 

to control NOX emissions with a control 

efficiency of 50 percent. In order to 

determine a reasonable performance 

standard for controlling NOX emissions, 

we considered four available retrofit 

control technologies for NOX on Kilns 1 

and 2. These control technologies are a 

LNB, mixing air technology (MAT), 

SCR, and SNCR. After evaluating each 

of these technologies to eliminate 

technically infeasible options, we 

determined that SNCR is the only 

remaining technically feasible control 

option. 

Low-NOX Burners: LNB are designed 

to reduce flame turbulence, delay fuel/ 

air mixing, and establish fuel-rich zones 

for initial combustion. LNA indicated 

that it experimented with the 

installation of bluff body LNB on the 

Nelson Lime Plant kilns in 2001.80

These LNB wore out in about six 

months, negatively affected production, 

caused brick damage, and resulted in 

unscheduled shutdowns of the kilns. 

We recognize that the staged 

combustion principle of LNB can 

present operational difficulties and 

potential product quality issues for lime 

production that are not exhibited in the 

cement industry. At this time we 

consider LNB to be technically 

infeasible for the Nelson Plant kilns, 

since we do not have any information to 

suggest otherwise at this time. The 

technical feasibility of LNB will be reevaluated for lime kilns in subsequent 

reasonable progress planning periods. 

Mixing Air Technology: MAT is the 

practice of injecting a high pressure air 

stream into the middle of a kiln to help 

mix the air flowing through the kiln. 

While the theory behind MAT suggests 

that the technology is effective at 

reducing NOX emissions, it is not clear 

whether this control technology is 

effective on lime kilns. We propose to 

eliminate MAT as not technically 

feasible for retrofit on Kiln 1 and Kiln 

2. 

Selective Catalytic Reduction: This 

process uses ammonia in the presence 

of a catalyst to selectively reduce NOX

emissions from exhaust gases. In SCR, 

ammonia, usually diluted with air or 

steam, is injected through a grid system 

into hot flue gases that are then passed 

through a catalyst bed to carry out NOX

reduction reactions. The catalyst is not 

consumed in the process but allows the 

reactions to occur at a lower 

temperature. However, SCR is subject to 

catalyst poisoning in high dust kiln 

exhausts. Therefore, SCR would have to 

be placed after the particulate control 

systems. According to LNA, given the 

operating temperature range for Kiln 1 

and Kiln 2 at the Nelson Lime Plant, the 

SCR catalyst would need to be located 

prior to the kiln baghouses, which 

would result in poisoning or covering of 

the catalyst. In addition, there are no 

SCR systems currently operating on 

lime kilns. We propose to eliminate SCR 

as not technically feasible for retrofit on 

Kiln 1 and Kiln 2. 

Selective Non-Catalytic Reduction: 

SNCR is a technically feasible option for 

reducing NOX emissions from the 

Nelson Lime Plant kilns as shown in 

Table 20. This control technique relies 

on the reduction of NOX in exhaust 

gases by injection of ammonia or urea, 

without using any catalyst. This 

approach avoids the problems related to 

catalyst fouling and poisoning attributed 

to SCR, but requires injection of the 

reagents in the kiln at a temperature 

between 1600 °F to 2000 °F. Because no 

catalyst is used to increase the reaction 

rate, the temperature window is critical 

for conducting this reaction. LNA has 

not conducted any detailed design work 

for an SNCR system for the Nelson Plant 

kilns, but anticipates that a 50 percent 

reduction is achievable based on LNA’s 

experience with operating a ureainjection system at another LNA lime 

plant. 

TABLE 20—NELSON LIME PLANT: SNCR CONTROL EFFICIENCY FOR BASELINE EMISSIONS

Control option 

Control 

efficiency 

Emission 

factor 

Maximum emission rate Emissions 

removed 

(%) (lb/ton lime) (lb/day) (tpy) (tpy) 

Kiln 1: 

Baseline ........................................................................ ........................ 7.59 6,573 981 

SNCR ............................................................................ 50 3.80 3,286 491 491 

Kiln 2: 

Baseline ........................................................................ ........................ 5.21 6,492 985 

SNCR ............................................................................ 50 2.61 3,246 493 493 

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9338 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules 

81Our estimate of annual operating costs is in the 

spreadsheet ‘‘Nelson Control Costs 2013–10– 

21.xlsx’’ in the docket. 

82BART Five Factor Analysis, Lhoist North 

America Nelson Lime Plant, Trinity Consultants, 

August 2013. 

b. BART Analysis for NOX

EPA conducted a five-factor BART 

analysis of SNCR to evaluate its costeffectiveness and visibility benefit. This 

analysis indicates that SNCR is costeffective and results in visibility 

improvement. 

Cost of Compliance: The following 

table provides LNA’s estimated cost for 

installation and operation of SNCR. 

Capital cost estimates developed by 

LNA relied primarily on vendor cost 

estimates and LNA’s experience at other 

lime plants, with the remainder of the 

capital costs calculated using the cost 

methodology contained in EPA’s 

Control Cost Manual. LNA has asserted 

a confidential business information 

(CBI) claim regarding certain annual 

operating costs such as reagent usage 

and auxiliary power costs. As a result, 

we have prepared our own independent 

estimate of annual operating costs based 

upon a combination of publicly 

available data and certain general 

assumptions as described in the 

Contractor’s Report.81 Table 21 is a 

summary of the estimated cost for 

installation and operation of SNCR. 

TABLE 21—NELSON LIME PLANT: ESTIMATED COST FOR SNCR 

Kiln 

Capital cost Annualized 

capital cost 

Annual 

operating cost 

Total annual 

cost 

Emission 

reduction 

Costeffectiveness 

($) ($) ($) ($/yr) (tpy) ($/ton) 

Kiln 1 ........................................................ $450,000 $42,477 $358,459 $400,936 491 $817 

Kiln 2 ........................................................ 450,000 42,477 354,981 397,458 493 807 

Energy and Non-Air Quality 

Environmental Impacts: SNCR systems 

require electricity to operate the blowers 

and pumps, which will likely involve 

fuel combustion that will generate 

emissions. Overall, while the generation 

of the required electricity will result in 

emissions, the emissions should be low 

compared to the reduction in NOX that 

would be gained by operating an SNCR 

system. The operation of SNCR systems 

on Kiln 1 and Kiln 2 would require that 

either urea or ammonia be stored on 

site. The storage of the chemicals does 

not result in a direct non-air quality 

impact. However, the potential for the 

urea or ammonia that would be stored 

to leak or otherwise be released from the 

storage vessels means there is the 

potential for both air and non-air quality 

related impacts. The storage of these 

chemicals does not significantly impact 

the BART determination. 

Pollution Control Equipment in Use at 

the Source: The presence of existing 

pollution control technology at each 

source is reflected in our BART analysis 

in two ways: first, in the consideration 

of available control technologies, and 

second, in the development of baseline 

emission rates for use in cost 

calculations and visibility modeling. Air 

pollution control equipment in use at 

the Nelson Lime Plant includes a 

number of baghouses, two multi-cyclone 

dust collectors, and a Ducon wet 

scrubber to control particulate matter 

emissions. The facility does not 

currently have control equipment for 

NOX and SO2. The kilns are allowed to 

burn coal, petroleum coke, fuel oil, or 

any combination of these fuels. 

Remaining Useful Life of the Source: 

Since we are not aware of any 

enforceable shutdown date for the 

Nelson Lime Plant, we have used a 20- 

year amortization period, as noted in the 

EPA Cost Control Manual, as the 

remaining useful life of the kilns. 

Degree of Visibility Improvement: 

LNA performed a visibility analysis 82 to 

assess the visibility improvement 

associated with SNCR. LNA performed 

dispersion modeling using the 

CALPUFF modeling system, which 

consists of the CALPUFF dispersion 

model, the CALMET meteorological 

data processor, and the CALPOST postprocessing program. The specific 

program versions that were relied upon 

in the analysis match the program 

versions relied upon by EPA’s 

contractor, the University of North 

Carolina at Chapel Hill and ICF 

International (UNC/ICF), in the BART 

analyses that they prepared for select 

sources, including the Nelson Plant. 

Most of the same data and parameter 

settings relied upon in the analysis are 

the same data and parameter settings 

that were relied upon in the contractor’s 

report. Compared to the UNC work, 

LNA used updated higher base case SO2

and NOx emissions, lower PM 

emissions, and lower stack exit 

velocities. LNA’s analysis included 

tables of visibility impacts and the 

improvement from controls, including 

results for the individual model years 

2001, 2002, and 2003, and it used 

visibility method ‘‘8a’’ and focused on 

the highest value from among the three 

years’ 98th percentiles. In order to put 

all the facilities on the same footing, 

EPA post-processed the modeling files 

provided by LNA using the approach 

followed for the other facilities. 

Table 22 represents the 98th 

percentile by the 22nd high over the 

2001–2003 period using visibility 

method ‘‘8b.’’ Using the EPA procedure, 

the maximum impact still occurs at the 

Grand Canyon, at 1.8 dv. The 98th 

percentile impacts at other Class I areas 

are about 0.3 dv or below, and the 

cumulative impact is 3.3 dv. The 

maximum visibility improvement due to 

SNCR is 0.58 dv, and cumulative 

improvement is 0.85 dv. There is little 

improvement at areas other than the 

Grand Canyon. These improvements 

yield a visibility cost-effectiveness of 

$1.4 million/dv using the maximum, 

and $0.9 million/dv using the 

cumulative improvement. These 

visibility improvements support the 

choice of SNCR as BART for NOX. 

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Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules 9339 

83See ‘‘Typical Installation Timelines for NOX

Emissions Control Technologies on Industrial 

Sources,’’ Institute of Clean Air Companies, 

December 4, 2006. 

84See ‘‘Results of Hydrogeologic Investigations 

for Development of Additional Water Supply, 

Chemical Lime Company, Nelson Plant, Yavapai 

County, AZ,’’ July 8, 1998. 

TABLE 22—NELSON LIME PLANT: VISIBILITY IMPACT AND IMPROVEMENT FROM NOX CONTROLS

Class I area Distance (km) 

Visibility 

impact 

Visibility 

improvement 

Base case SNCR 

(ctr1) 

Bryce Canyon NP .................................................................................................................... 235 0 .20 0 .06 

Grand Canyon NP ................................................................................................................... 24 1 .79 0 .58 

Joshua Tree NP ....................................................................................................................... 238 0 .23 0 .02 

Mazatzal WA ............................................................................................................................ 206 0 .15 0 .01 

Pine Mountain WA ................................................................................................................... 199 0 .15 0 .02 

Sierra Ancha WA ..................................................................................................................... 289 0 .11 0 .01 

Superstition WA ....................................................................................................................... 288 0 .13 0 .01 

Sycamore Canyon WA ............................................................................................................ 132 0 .31 0 .07 

Zion NP .................................................................................................................................... 183 0 .28 0 .08 

Cumulative (sum) ..................................................................................................................... ........................ 3 .34 0 .85 

Maximum ................................................................................................................................. ........................ 1 .79 0 .58 

# CIAs >= 0.5 dv ..................................................................................................................... ........................ 1 1 

Million $/dv (cumul. dv) ............................................................................................................ ........................ .......................... $0 .9 

Million $/dv (max. dv) .............................................................................................................. ........................ .......................... $1 .4 

c. Proposed BART Determination for 

NOX

We propose to find that BART for 

NOX for Kilns 1 and 2 is SNCR, and are 

proposing a BART emission limit for 

Kiln 1 of 3.80 lb/ton lime and for Kiln 

2 of 2.61 lb/ton lime on a 30-day rolling 

basis, as demonstrated through the use 

of a CEMS. We consider SNCR to be a 

very cost-effective control option for 

Kilns 1 and 2, at $817/ton and $807/ton, 

respectively. In addition, we consider 

the anticipated visibility benefit from 

SNCR, 0.58 dv at Grand Canyon 

National Park and 0.85 cumulatively at 

all Class I areas within 300 km, to be 

substantial. In considering the other 

factors, we do not consider their impact 

substantial relative to the cost and 

visibility factors. We note that the 

remaining useful life of the source is 

reflected in the evaluation of cost of 

compliance through the use of a 20-year 

amortization period in control cost 

calculations. Since there is no existing 

NOX control technology in use on the 

kilns, baseline emissions reflect 

uncontrolled NOX emissions. In 

examining energy and non-air quality 

impacts, while we note certain impacts 

associated with SNCR, we do not 

consider these impacts sufficient to 

warrant its elimination as a control 

option. 

We propose to require compliance 

with this requirement within three years 

after the effective date of the final rule. 

A 2006 Institute of Clean Air Companies 

(ICAC) study indicated that the 

installation time for a typical SNCR 

retrofit, from bid to startup-up, is 10–13 

months.83 In relation to other industrial 

sources, such as fossil fuel boilers, there 

are a limited number of examples of 

SNCR installation on lime kilns. Given 

this relative lack of information 

regarding SNCR installation schedules 

on lime kilns, we consider three years 

to be an appropriate length of time to 

design, install, and test an ammonia 

injection system for a lime kiln. In 

addition, we are also proposing 

regulatory text that includes monitoring, 

reporting, and recordkeeping 

requirements associated with this 

emission limit. As part of the proposed 

monitoring requirements, we are 

including a requirement to monitor rates 

of ammonia injection in order to ensure 

proper operation of the SNCR in a 

manner that minimizes ammonia 

emissions. 

3. Proposed BART for SO2

For our BART analysis, we identify all 

available control technologies, eliminate 

options that are not technically feasible, 

and evaluate the control effectiveness of 

the remaining control options. We then 

evaluate each control in terms of a fivefactor BART analysis and make a 

determination for BART. 

a. Control Technology Analysis for SO2

EPA proposes to find that DSI and 

switching to lower sulfur fuel are 

technically feasible controls, while wet 

or semi-dry scrubbing is not technically 

feasible. 

Wet or Semi-Dry Scrubbing: We do 

not consider wet or dry scrubbing to be 

a feasible technology to control SO2

emissions for this source. Wet scrubbing 

involves passing flue gas downstream 

from the main particulate matter control 

device through a sprayed aqueous 

suspension of lime or limestone that is 

contained in a scrubbing device. The 

SO2 reacts with the scrubbing reagent to 

form lime sludge that is collected. The 

sludge usually is dewatered and 

disposed of at an offsite landfill. 

However, LNA has concluded, and we 

agree, that there is not sufficient water 

available for this type of system. 

According to LNA, two ground water 

wells supply about 106 gallons per 

minute (gpm) to the Nelson Plant, 

which currently uses about 80 gpm. 

Therefore, only 26 gpm of water is 

available for a scrubbing system that, 

even for a semi-dry scrubbing system 

that has lower water requirements than 

wet scrubbing, would require about 117 

gpm. Moreover, a 1998 hydrologic 

report indicates that the prospects for 

developing additional wells, even lowyield wells, on the Nelson property are 

poor.84 After reviewing the hydrologic 

report and the vendor estimate of water 

requirements for a semi-dry scrubber, 

we agree with this assessment. 

Dry Sorbent Injection: DSI involves 

the injection of powdered absorbent 

directly into the flue gas exhaust stream. 

The sorbent reacts with SO2 in the 

exhaust to form solid particles that are 

then removed by a particulate matter 

control device downstream of the 

sorbent injection. DSI is a simple system 

that generally requires a sorbent storage 

tank, feeding mechanism, transfer line 

and blower, and an injection device. DSI 

is generally considered technically 

feasible for the cement industry, 

although the level of control 

effectiveness may vary based upon sitespecific conditions. We consider this 

option technically feasible for lime 

kilns. LNA has not included 

information in its analysis indicating 

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9340 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules 

85 40 CFR Part 51, Appendix Y, Section IV.D.1.5, 

‘‘STEP 1: How do I identify all available retrofit 

emission control techniques?’’ 

86While the control efficiency for DSI is much 

higher for cement kilns, LNA conducted onsite 

testing of DSI on the lime kilns at the Nelson Plant 

that demonstrated it is appropriate to use 40 

percent control efficiency. The docket includes a 

comparison of LNA’s tests of DSI to the analysis in 

our contractor’s report. 

87 Vendor quote included as an attachment to 

BART Five Factor Analysis, Lhoist North America 

Nelson Lime Plant; (Public version dated September 

27, 2013). 

88See spreadsheet ‘‘Nelson Control Costs 2013– 

10–24.xlsx’’ in the docket. 

that DSI would be infeasible for the 

Nelson Plant kilns. 

Lower Sulfur Fuel: The lower sulfur 

fuel option described by LNA involves 

changing the proportion of coal and 

petroleum coke used as a fuel blend. 

LNA currently uses a blend of 27 

percent coal and 73 percent petroleum 

coke, on a mass basis, as the fuel for the 

kilns. Since coke has about four to five 

times more sulfur than coal, it is 

possible to decrease the sulfur in the 

fuel blend by increasing the proportion 

of coal. However, an increase in coal in 

the fuel blend will also increase the ash 

content of the fuel blend. Ash in the fuel 

can disrupt operations due to the 

buildup of ash rings in the kilns. A fuel 

blend with an ash content of about 6.5 

percent or less must be used in order to 

avoid these operational challenges. 

As noted in fuel usage and purchase 

records, the Nelson Plant currently 

operates on a coal and petroleum coke 

mixture. As a result, we consider 

adjusting the coal/coke ratio in the fuel 

mixture to be a technically feasible 

option. We note, however, that since the 

BART Guidelines do not require fuel 

supply changes to be considered as a 

control option, we have typically not 

considered changes in fuel in BART 

analyses.85 However, because LNA 

included lower sulfur fuel in its 

analysis, we have retained it as a control 

option. 

b. BART Analysis for SO2

EPA conducted a five-factor BART 

analysis of the two technically feasible 

control options, DSI and lower sulfur 

fuel, to evaluate the cost-effectiveness 

and visibility benefit of each option 

along with any effect on the other 

factors. 

Cost of Compliance: Our 

consideration of the cost of compliance 

focuses primarily on the costeffectiveness of each control option as 

measured in cost per ton and 

incremental cost per ton. We estimate 

the SO2 emissions rates for DSI and 

lower sulfur fuel as shown in Table 23, 

and the cost-effectiveness of these 

options as shown in Table 24. DSI has 

a control efficiency of 40 percent that 

results in about 1,588 tpy of SO2

removed from both kilns. Lower sulfur 

fuel has a control efficiency of 23.3 

percent that results in about 925 tpy of 

SO2 removed from both kilns. Based on 

the total annual costs of controlling SO2

emissions at both kilns, DSI would cost 

an average of about $4,200 per ton 

removed and lower sulfur fuel about 

$860 per ton removed. Since there is no 

existing SO2 control technology in use 

in the plant, baseline emissions reflect 

uncontrolled SO2 emissions. 

While we consider it appropriate to 

use 40 percent control efficiency 86 for 

DSI, we are inviting comment on the 

control effectiveness of 23.3 percent for 

a lower sulfur fuel blend based on the 

ratio of coal (1.15 percent sulfur) to 

petroleum coke (5.64 percent sulfur). 

LNA estimates that the maximum coalto-coke ratio to maintain overall fuel ash 

content below 6.5 percent is a 50 

percent coal to 50 percent coke fuel 

mixture. A 50/50 mix corresponds to a 

fuel sulfur reduction of 1.13 percentage 

points, which represents a 23.3 percent 

reduction from the current fuel mixture. 

Based on a review of coal and coke 

properties along with historical fuel 

usage at the Nelson Plant, we agree with 

the use of a 50/50 coal-to-coke ratio and 

23.3 percent control effectiveness. 

However, LNA cites operational issues 

with fuel ash content above 6.5 percent. 

Since ash is a contaminant that can 

adversely affect lime product quality, 

we are seeking comment regarding the 

extent to which it is appropriate to use 

fuel ash content of 6.5 percent as the 

upper bound for determining fuel 

mixture ratio. We may finalize a 

different fuel mixture ratio based upon 

the comments we receive. 

In estimating the costs of compliance, 

LNA relied on a vendor quote for 

purchased equipment provided by 

Noltech dated May 22, 2013, with the 

remainder of the capital costs calculated 

using the cost methodology contained in 

EPA’s Control Cost Manual.87 While 

these capital costs are higher than those 

estimated by our contractor, we 

consider the use of the Noltech vendor 

quote for the Nelson Plant reasonable, 

and have incorporated it into our 

evaluation of the costs of compliance. 

With regard to annual operating & 

maintenance costs, LNA has asserted a 

confidential business information (CBI) 

claim regarding certain annual operating 

costs such as reagent usage. As a result, 

we have prepared our own independent 

estimate of annual operating costs based 

upon a combination of publicly 

available data and certain assumptions 

as described in the contractor’s report. 

Detailed cost calculations can be found 

in the docket.88

TABLE 23—NELSON LIME PLANT: SO2 CONTROL OPTION EMISSION ESTIMATES

SO2 control technology 

Control 

efficiency 

(%) 

Emission 

factor 

(lb/ton lime) 

Maximum emission rate Removed 

(tpy) lb/day Tpy 

Kiln 1: 

Baseline ............................................................................................ .................... 12.15 10,526 1,571 ....................

Lower Sulfur Fuel Blend ................................................................... 23.30 9.32 8,073 1,205 366 

Dry Sorbent Injection ........................................................................ 40 7.29 6,316 943 628 

Kiln 2: 

Baseline ............................................................................................ .................... 12.69 15,808 2,400 ....................

Lower Sulfur Fuel Blend ................................................................... 23.30 9.73 12,125 1,841 559 

Dry Sorbent Injection ........................................................................ 40 7.61 9,485 1,440 960 

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89These results are from EPA’s post-processing of 

LNA’s modeling. See the TSD for a discussion of 

the differences between EPA’s results and the 

results reported by LNA in their BART analysis. 

TABLE 24—NELSON LIME PLANT: SO2 CONTROL OPTION COST-EFFECTIVENESS

SO2 control technology 

Capital 

cost 

Annual 

direct costs 

Annual 

indirect 

costs 

Total annual 

cost 

Emission 

reduction 

Cost-effectiveness 

($/ton) 

($) ($/yr) ($/yr) ($/yr) (tpy) Average Incremental 

Kiln 1: 

Lower Sulfur Fuel Blend ................... .................... .................... .................... $313,096 366 $856 ....................

Dry Sorbent Injection ........................ $2,497,559 $371,174 $2,621,832 2,621,832 628 4,174 $8,803 

Kiln 2: 

Lower Sulfur Fuel Blend ................... .................... .................... .................... 458,179 559 819 ....................

Dry Sorbent Injection ........................ 2,497,559 371,174 3,895,774 3,895,774 960 4,058 8,576 

Pollution Control Equipment in use at 

the Source: The presence of existing 

pollution control technology at the 

Nelson Plant is reflected in the BART 

analysis in two ways: first, in the 

consideration of available control 

technologies, and second, in the 

development of baseline emission rates 

for use in cost calculations and visibility 

modeling. In the case of SO2, the kilns 

at the Nelson Plant do not operate with 

any existing control technology. This is 

reflected in the baseline emission rates, 

which represent uncontrolled SO2

emissions. 

Energy and non-air quality 

environmental impacts: Regarding the 

first option, DSI systems require 

electricity for operation. The generation 

of the electricity needed to operate a DSI 

system will likely involve fuel 

combustion that will generate 

emissions. Emissions also are associated 

with the transport, handling, and 

storage of sorbent. Overall, while the 

use of DSI will cause emissions from 

select activities, the emissions should be 

low compared to the reduction in SO2

that would be gained by operating a DSI 

system. Regarding the second option, 

using a lower sulfur fuel blend means 

LNA will obtain more of the energy for 

lime production from coal and less of 

the energy from coke. Since the heating 

value of coke is slightly higher than the 

heating value of coal, it is likely that 

LNA will burn more total mass of fuel 

as a result of substituting some coal for 

coke. While burning a lower sulfur fuel 

blend will likely result in a reduction in 

SO2 emissions, it will involve the 

overall use of greater quantities of coal, 

which may result in a collateral increase 

of other pollutants such as NOX and CO. 

Remaining Useful Life of the Source: 

We are considering the ‘‘remaining 

useful life’’ of the kilns as one element 

of the overall cost analysis as allowed 

by the BART Guidelines. In the absence 

of any enforceable closure date, we have 

used a 20-year amortization period 

described in the EPA Cost Control 

Manual as the remaining useful life for 

the control options considered for the 

Nelson Plant kilns. Since there is no 

capital costs associated with using a 

lower sulfur fuel blend, the remaining 

useful life of the kilns is not a factor in 

the evaluation of this technology. 

Degree of Visibility Improvement: As 

was the case for NOX, EPA postprocessed LNA’s modeling results for 

SO2 controls. The greatest improvement 

from DSI is 0.2 dv, occurring at the 

Grand Canyon, with improvements at 

other areas a third or less than this. The 

cumulative improvement is 0.6 dv. The 

maximum and cumulative 

improvements from switching to lower 

sulfur fuel are roughly half of these 

amounts. While visibility improvement 

by itself could support either DSI or 

lower sulfur fuel as BART, lower sulfur 

fuel is favored by its much lower 

average cost-effectiveness at $819–856/

ton compared to over $4000 for DSI. 

Baseline and control option emission 

rates used in SO2 control scenario 

modeling are summarized in Table 25 

with the modeling results in Table 26.89

TABLE 25—NELSON LIME PLANT: SO2 CONTROL MODEL EMISSION RATES

SO2 control technology 

Control 

efficiency 

Emission 

factor 

Maximum 24-hr 

model emission rate 

% lb/ton lime lb/day lb/hr g/s 

Kiln 1: 

Baseline ............................................................................................ .................... 12.15 10,526 439 55 

Lower Sulfur Fuel Blend ................................................................... 23.30 9.32 8,073 336 42 

Dry Sorbent Injection (SBC) ............................................................. 40 7.29 6,315 263 33 

Kiln 2: 

Baseline ............................................................................................ .................... 12.69 15,808 659 83 

Lower Sulfur Fuel Blend ................................................................... 23.30 9.73 12,125 505 64 

Dry Sorbent Injection (SBC) ............................................................. 40 7.61 9,489 395 50 

TABLE 26—NELSON LIME PLANT: SO2 CONTROL OPTION VISIBILITY MODELING RESULTS

Class I area Distance 

(km) 

Visibility 

impact 

Visibility 

improvement 

Base case DSI 

(ctr2) 

Low-S fuel 

(ctr3) 

Bryce Canyon NP ........................................................................................................ 235 0 .20 0 .03 0.02 

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9342 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules 

90The differing emission limits are due to the 

different baseline performance of the two kilns. 

91 40 CFR Part 63, Subpart AAAAA, Table 1, Item 

1 for existing lime kilns with no wet scrubber prior 

to 2005. 

92 40 CFR Part 51, Appendix Y, Section IV.C. 

93Annual costs as described in the Economic 

Impact Analysis for the Lime Manufacturing MACT 

Standard (EPA–452/R–03–013), Table 3–2, Model 

Kiln F. Adjusted from 1997 to 2013 dollars using 

the consumer price index, available at ftp://

ftp.bls.gov/pub/special.requests/cpi/cpiai.txt. 

94As described in the LNA Nelson BART 

Analysis, Table 4–5. 

95 40 CFR Part 51, Appendix Y, Section IV.D.9. 

TABLE 26—NELSON LIME PLANT: SO2 CONTROL OPTION VISIBILITY MODELING RESULTS—Continued 

Class I area Distance 

(km) 

Visibility 

impact 

Visibility 

improvement 

Base case DSI 

(ctr2) 

Low-S fuel 

(ctr3) 

Grand Canyon NP ....................................................................................................... 24 1 .79 0 .21 0.10 

Joshua Tree NP ........................................................................................................... 238 0 .23 0 .07 0.04 

Mazatzal WA ................................................................................................................ 206 0 .15 0 .04 0.02 

Pine Mountain WA ....................................................................................................... 199 0 .15 0 .04 0.02 

Sierra Ancha WA ......................................................................................................... 289 0 .11 0 .04 0.02 

Superstition WA ........................................................................................................... 288 0.13 0 .04 0.02 

Sycamore Canyon WA ................................................................................................ 132 0 .31 0 .06 0.04 

Zion NP ........................................................................................................................ 183 0 .28 0 .04 0.02 

Cumulative (sum) ......................................................................................................... .................... 3 .34 0 .57 0.29 

Maximum ..................................................................................................................... .................... 1 .79 0 .21 0.10 

# CIAs >= 0.5 dv ......................................................................................................... .................... 1 0 0 

Million $/dv (cumul. dv) ................................................................................................ .................... ...................... $11 .5 $2.6 

Million $/dv (max. dv) .................................................................................................. .................... ...................... $30 .7 $8.1 

c. Proposed BART Determination for 

SO2

We propose to find that BART for SO2

is the use of a lower sulfur fuel blend 

with an emission limit of 9.32 lb/ton for 

Kiln 1 and 9.73 lb/ton for Kiln 2 90 on 

a rolling 30-day basis. In evaluating the 

costs of compliance, we note that we 

consider DSI and lower sulfur fuel to 

both be cost-effective control options, 

with average cost-effectiveness values of 

approximately $800/ton and $4,000/ton, 

respectively. In evaluating anticipated 

visibility benefit, while DSI is 

anticipated to achieve the greatest 

visibility improvement (0.21 dv at 

Grand Canyon), this amount of visibility 

improvement is not large, nor is the 

benefit anticipated for the next most 

stringent control option, lower sulfur 

fuel (0.10 dv at Grand Canyon). In 

considering the other factors, there is no 

significant effect on the outcome of the 

cost and visibility analyses. The lack of 

existing control technology is reflected 

in the baseline in the form of 

uncontrolled SO2 emissions. In 

examining energy and non-air quality 

impacts, we note that there may be 

certain collateral increases in emissions, 

but that these increases are outweighed 

by the emission reductions achieved by 

implementing the control technology 

and do not warrant their elimination. 

The remaining useful life of the source 

is reflected in the evaluation of the cost 

of compliance. We consider both DSI 

and use of lower sulfur fuel to be costeffective, but note that the most 

stringent option, DSI, is considerably 

less cost-effective than the use of lower 

sulfur fuel, with an incremental costeffectiveness, relative to lower sulfur 

fuel, of approximately $9,000/ton. As a 

result, although DSI is the most 

stringent control option, the visibility 

benefit it achieves is not large, and is 

achieved at a very high incremental cost 

relative to the next most stringent 

control option. Based on this 

information, we propose to find that 

BART for SO2 is the use of a lower 

sulfur fuel blend. 

4. Proposed BART for PM10

For our BART analysis, we identified 

fabric filter baghouses, the existing 

control technology for PM10 on Kilns 1 

and 2, as the most stringent control 

available for this type of source. 

a. Control Technology Analysis for PM10

The Nelson Plant, as a major source 

of hazardous air pollutants (HAPs), is 

subject to the Maximum Achievable 

Control Technology (MACT) Standard 

for Lime Manufacturing Plants, and is 

required to meet an emission limit of 

0.12 lbs PM/TSF (ton of stone feed).91

The BART Guidelines provide that 

unless there are new technologies 

subsequent to the MACT standards that 

would lead to cost-effective increases in 

the level of control, one may rely on the 

MACT standards for purposes of 

BART.92 Based on information 

developed as part of the Lime MACT, 

we estimate that existing fabric filter 

upgrades would result in annual costs of 

$94,500.93 As noted in LNA’s BART 

analysis, baseline PM emissions for the 

two kilns, based on PM filterable stack 

test data and annual lime production, 

are approximately 8 tpy and 15 tpy.94

This would result in an average costeffectiveness of about $6,300 to $12,000/ 

ton. 

b. BART Analysis for PM10

The BART Guidelines provide that, in 

instances where a source already has the 

most stringent controls available 

(including all possible improvements), 

it is not necessary to complete each step 

of the BART analysis. Further, as long 

as the most stringent controls available 

are made federally enforceable for the 

purpose of implementing BART for that 

source, one may skip the remainder of 

the analysis, including the visibility 

analysis.95

c. Proposed BART Determination for 

PM10

We propose a BART emission limit of 

0.12 lb/TSF to control PM10 at Kilns 1 

and 2 based on the use of the existing 

fabric filter baghouses and 

commensurate with the MACT standard 

that applies to this source. We seek 

comment on any cost-effective upgrades 

or improvements that may result in a 

lower emission limit. We propose to 

require compliance with this 

requirement within 6 months after the 

effective date of the final rule. We also 

propose regulatory text that includes 

monitoring, reporting, and 

recordkeeping requirements associated 

with this emission limit that is found at 

the end of this notice. 

C. Hayden Smelter 

Summary: EPA proposes to find that 

the ASARCO Hayden Smelter is subject 

to BART for NOX in addition to SO2 as 

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96 78 FR 46412 (July 30, 2013). Please refer to the 

TSD for a description of these units. 

97ASARCO Hayden Title V permit. 

98Letter from Jack Garrity, ASARCO to Thomas 

Webb, EPA, July 11, 2013; attached Memorandum 

from Ralph Morris and Lynsey Parker, ENVIRON, 

to Eric Hiser, Jorden, Bischoff and Hiser, PLC, 

March 4, 2013. 

99ASARCO Hayden CEMS Test Report, Energy 

and Environmental Measurement Corporation, Test 

date: September, 2012. 

determined by the State. ASARCO must 

capture and control SO2 emissions from 

the converter units that are subject to 

BART. In the current method of 

operation, thousands of tons of SO2

from these units are vented to the 

atmosphere with no pollution control. 

One method to control SO2 emissions 

from the converter units is to install and 

operate a second double contact acid 

plant with a control efficiency of about 

99.8 percent on a 30-day rolling average. 

We estimate the annual cost of 

constructing and operating a second 

acid plant to control SO2 emissions is 

about $872 per ton of SO2 removed. 

While we consider the cost of a new 

acid plant to be reasonable, we are 

proposing a performance standard as 

BART rather than prescribing a 

particular method of control. For NOX,

we propose to set an annual emission 

limit of 40 tpy from the BART-eligible 

units, based on our proposed 

determination that no NOX controls are 

needed for BART at the Hayden 

Smelter. Finally, we are proposing an 

emission limit and associated 

compliance requirements for PM10. 

Affected Class I Areas: Twelve Class 

I areas are within 300 km of the Hayden 

Smelter. Their nearest borders range 

from 48 km to 239 km away. Galiuro 

WA and Superstition WA are the 

closest, followed by Saguaro NP and 

Sierra Ancha WA. The highest baseline 

98th percentile visibility impact is 1.7 

dv at Superstition, with impacts at 

Galiuro slightly lower. Baseline 

visibility impacts at each of the twelve 

areas exceed 0.5 dv. The cumulative 

sum of visibility impacts over all the 

Class I areas is 12.1 dv. 

Facility Overview: ASARCO Hayden 

Smelter is a batch-process copper 

smelter in Gila County, Arizona. We 

previously approved ADEQ’s 

determination that converters 1, 3, 4 and 

5 and Anode Furnaces 1 and 2 at the 

facility are BART-eligible.96 We also 

approved ADEQ’s determination that 

these units are subject to BART for SO2

and that BART for PM10 at ASARCO 

Hayden is no additional controls. 

However, we disapproved ADEQ’s 

determination that existing controls 

constitute BART for SO2 and that the 

units are not subject to BART for NOX.

In light of these disapprovals and our 

FIP duty for regional haze in Arizona, 

we are required to promulgate a FIP to 

address BART for SO2 and NOX. 

Baseline Emissions Calculations: 

Since neither ASARCO nor ADEQ 

identified baseline emissions for the 

Hayden Smelter, we calculated baseline 

emissions for SO2 and NOX. For SO2, we 

used as the baseline the average of the 

two highest emitting years from the last 

five years that ASARCO reported to 

ADEQ. For NOX, we estimated emission 

rates based on the rated natural gas 

capacity of the burners in the four 

subject-to-BART converters and the two 

anode furnaces.97 As indicated in Table 

27, the majority of the source’s SO2

emissions (20,341 tpy of a total of 

22,621 tpy) are process emissions from 

the converters. These process SO2

emissions are collected through a 

secondary capture system, but are 

emitted uncontrolled through an 

annular stack that bypasses the existing 

double contact acid plant. While our 

BART analysis focuses on these 

uncontrolled SO2 emissions from the 

converters, we also evaluated improved 

control of the SO2 emissions from the 

existing acid plant and from the anode 

furnaces as well as controlling NOX

emissions from all the BART units. 

TABLE 27—HAYDEN SMELTER: BART BASELINE EMISSIONS

[Tons per year] 

Converters 

Anode 

furnaces Total Existing acid plant 

(primary 

capture) 

Annular stack 

(secondary 

capture) 

Uncaptured 

SO2 ...................................................................................................... 1,034 20,341 1,209 37 22,621 

NOX ...................................................................................................... 31 19 50 

Modeling Overview: EPA is relying on 

modeled baseline and post-control 

impacts of the ASARCO Hayden 

Smelter using stack parameters 

provided by ASARCO in response to a 

2013 EPA information request.98 We 

also modeled using stack parameters 

based on a 2012 stack test.99 Stack exit 

temperatures were comparable for these 

two models, but the exit velocities from 

the 2012 stack test were far lower than 

those provided by ASARCO in 2013. 

The 2012 stack test parameters resulted 

in visibility impacts and control benefits 

about 10 percent higher than the model 

using the 2013 parameters. We are 

conservatively using the 2013 ASARCO 

parameters to evaluate controls, since 

using the 2012 parameters would yield 

even greater visibility improvements. 

For both sets of modeling runs, EPA 

used emission rates that were developed 

using information provided by 

ASARCO. 

1. BART Analysis and Determination for 

SO2 From Converters 

a. Control Technology Availability, 

Technical Feasibility and Effectiveness 

EPA identified two available 

technology options to control the 20,341 

tons of SO2 emissions from the annular 

stack that are captured by a secondary 

collection system, but are released 

uncontrolled through the annular stack. 

These options are to construct and 

operate a second double contact acid 

plant or install a wet scrubber on the 

annular portion of the existing stack. In 

addition, we found that ASARCO could 

add a tail stack scrubber to the existing 

acid plant to address the remaining 

emissions that are not converted and 

removed as sulfuric acid by the acid 

plant. Regarding technical feasibility, 

we note that ASARCO Hayden currently 

uses a double contact acid plant to 

control SO2 emissions captured by the 

primary capture system. Wet scrubbing 

also is commonly used in many 

industries to control SO2. Thus, we find 

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9344 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules 

100Letter from Jack Garrity, ASARCO to Thomas 

Webb, EPA, July 11, 2013. 

101 Ibid. 102This is based on the AP 42 factor for low-NOX

burners. 

that the double contact acid plant and 

wet scrubbing are technically feasible. 

In terms of control effectiveness, 

ASARCO indicated in a letter 100 to EPA 

that its double contact acid plant is 

capable of recovering 99.8 percent of the 

SO2 vented to it.101 In the same letter, 

ASARCO noted that the expected 

control effectiveness of wet scrubbing is 

85 percent. We used these removal 

efficiencies in our five-factor analyses. 

These analyses are explained in the TSD 

and summarized below. 

b. Option 1: Double Contact Acid Plant 

for Secondary Capture 

Cost of Compliance: EPA determined 

the cost-effectiveness of a new double 

contact acid plant is $872 per ton of SO2

removed as shown in Table 28. As 

explained in the TSD, we conservatively 

estimated the cost of construction of a 

double contact acid plant to be 

$81,621,297. The annualized capital 

costs are based on a 20-year lifespan and 

a seven percent interest rate. We applied 

a control efficiency of 99.8 percent, 

which the existing acid plant is 

currently achieving with limited cesium 

catalyst. The emission reduction was 

applied to the secondary capture system 

baseline emissions. This cost analysis 

does not include the offsetting value of 

any sulfuric acid produced and sold. It 

does assume full catalyst replacement 

every other year and air preheating with 

natural gas for 8,760 hours per year. 

TABLE 28—HAYDEN SMELTER OPTION 1: SECOND DOUBLE CONTACT ACID PLANT

Capital cost Annualized 

capital cost 

Annual 

variable cost 

Total annual 

cost 

Tons SO2

reduced 

Control 

efficiency 

$/ton SO2

removed 

$81,621,297 ............................................. $7,704,573 $10,006,010 $17,710,483 20,341 99.8% $872 

Energy and Non-Air Quality 

Environmental Impacts: Controlling 

secondary capture with a sulfuric acid 

plant at the Hayden Smelter would 

require energy to heat inlet air from 

approximately 177 °F to 735 °F. This 

would require a heat input of 

approximately 114 MMBtu/hour and 

could require 1,200 MMscf of natural 

gas per year, resulting in up to 30 tpy 

of NOX emissions.102 This assumes 100 

percent of the needed heat results from 

natural gas combustion. Non-air quality 

impacts from a second acid plant are not 

expected to be significant given that 

ASARCO already has the capacity to 

handle and store the much larger 

quantities of sulfuric acid produced by 

the primary acid plant. 

Pollution Control Equipment in Use at 

the Source: As noted above and further 

described in the TSD, a portion of the 

emissions from the converters are 

controlled by a gas cleaning plant to 

remove particulate matter and a double 

contact sulfuric acid plant that converts 

SO2 to sulfuric acid. We considered 

these controls as part of our analysis of 

available control technologies and in 

developing baseline emission rates for 

use in cost calculations and visibility 

modeling. 

Remaining Useful Life of the Source: 

The BART-eligible converters have each 

been in place for about 40 years or 

longer. ASARCO has not indicated that 

any of the converters would need to be 

replaced during the 20-year capital cost 

recovery period. 

Degree of Visibility Improvement: 

Controlling SO2 emissions through a 

second double contact acid plant at a 

98.8 percent efficiency results in 

visibility improvement in 12 Class I 

areas in Arizona and New Mexico as 

indicated in Table 29. Based on air 

quality modeling, visibility 

improvement from controlling SO2 by 

constructing a new acid plant to control 

converter emissions from the secondary 

capture system is 1.5 dv at Superstition, 

and nearly the same at Galiuro. Eleven 

of the Class I areas improve by at least 

0.5 dv. The cumulative improvement is 

10.3 dv. The large visibility 

improvement at many Class I Areas 

supports the choice of a new acid plant 

as BART for SO2. 

TABLE 29—HAYDEN SMELTER OPTION 1: VISIBILITY IMPACT AND IMPROVEMENT FROM SO2 CONTROLS

Class I area Distance 

(km) 

Visibility impact base 

case 

(base) 

Visibility improvement 

new acid 

plant 

(ctrl2) 

Chiricahua NM ..................................................................................................................................... 170 1 .05 0 .89 

Chiricahua WA ..................................................................................................................................... 174 1 .01 0 .87 

Galiuro WA .......................................................................................................................................... 48 1 .73 1 .45 

Gila WA ................................................................................................................................................ 186 0 .69 0 .60 

Mazatzal WA ........................................................................................................................................ 121 0 .88 0 .75 

Mount Baldy WA .................................................................................................................................. 151 0 .66 0 .56 

Petrified Forest NP .............................................................................................................................. 215 0 .70 0 .61 

Pine Mountain WA ............................................................................................................................... 168 0 .67 0 .57 

Saguaro NP ......................................................................................................................................... 82 1 .38 1 .18 

Sierra Ancha WA ................................................................................................................................. 84 1 .09 0 .93 

Superstition WA ................................................................................................................................... 50 1 .74 1 .47 

Sycamore Canyon WA ........................................................................................................................ 239 0 .51 0 .44 

Cumulative (sum) ................................................................................................................................. .................... 12 .10 10 .32 

Maximum ............................................................................................................................................. .................... 1 .74 1 .47 

# CIAs >= 0.5 dv ................................................................................................................................. .................... 12 11 

Million $/dv (cumul. dv) ........................................................................................................................ .................... ...................... $1 .7 

Million $/dv (max. dv) .......................................................................................................................... .................... ...................... $12 .1 

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Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules 9345 

103Letter from Jack Garrity, ASARCO to Thomas 

Webb, EPA (July 11, 2013). 

104 Ibid. 

c. Option 2: Wet Scrubber on Existing 

Stack for Secondary Capture 

Cost of Compliance: EPA determined 

that the annual cost of using a wet 

scrubber to control SO2 emissions from 

the secondary capture system is $972 

per ton of SO2 removed as displayed in 

Table 30. We calculated the costs of 

constructing and operating a wet 

scrubber based on information provided 

in ASARCO’s letter 103 from which we 

used the highest operating cost 

estimates to demonstrate costeffectiveness. We also included a sludge 

hauling fee of $60 per ton and assumed 

one ton of SO2 controlled would result 

in five tons of sludge. According to 

ASARCO, these costs do not include the 

cost of a booster fan or a modified stack 

that may be needed, thereby somewhat 

increasing the cost over what is shown 

here. Although the calculation includes 

the cost of hauling sludge off site, it 

does not include the cost of treating or 

landfilling the sludge. 

TABLE 30—HAYDEN SMELTER OPTION 2: WET SCRUBBER ON EXISTING STACK

Capital cost Annualized 

capital cost 

Annual variable cost Total annual 

cost 

Tons SO2

reduced 

Control 

efficiency 

$/ton SO2

removed 

$28,000,000 ............................................. $2,643,002 $14,186,965 $16,829,967 17,290 85% $972 

Energy and Non-Air Quality 

Environmental Impacts: Operation of a 

wet scrubber would likely require 

operation of a booster fan and a gas reheater to force emissions through the 

305 meter stack. The addition of a wet 

scrubber could result in a detached 

visible plume as water vapor emitted 

from the scrubber condenses. Addition 

of a scrubber would result in sludge 

which would have to be shipped off site 

to be treated or landfilled. Because of 

metals in the sludge, it may need to be 

treated as hazardous waste. 

Pollution Control Equipment in Use at 

the Source: This is the same as for 

Option 1. 

Remaining Useful Life of the Source: 

This is the same as for Option 1. 

Degree of Visibility Improvement: We 

did not conduct visibility modeling for 

this option. Because a scrubber is less 

efficient at removing SO2 than a second 

acid plant, the emission rates would be 

higher and there would be less visibility 

improvement from a scrubber compared 

to an acid plant. Given that scrubbers 

are less cost-effective than a second acid 

plant, we deemed it unnecessary to 

model impacts. 

d. Option 3: Wet Scrubber on Acid Tail 

Stack for Primary Capture 

Cost of Compliance: EPA determined 

the annual cost of using a wet scrubber 

to control SO2 emissions from the 

existing acid plant tail stack is $13,564 

per ton of SO2 removed as displayed in 

Table 31. We calculated the costs of 

constructing and operating a wet 

scrubber based on information provided 

by ASARCO.104 In this case, we used 

the low-end estimate of operating costs 

because we are demonstrating that this 

option is not cost-effective. We also 

included a sludge hauling fee of $60 per 

ton and assumed one ton of SO2

controlled would result in five tons of 

sludge. Again, these costs did not 

include the cost of a booster fan or a 

modified stack that may be needed. 

Although the calculation included the 

cost of hauling sludge off site, it did not 

include the cost of treating or disposing 

the sludge, which may be classified as 

hazardous waste depending on the 

metals content. In addition, we note that 

some of the SO2 that passes through the 

acid plant is emitted by the flash 

furnace that is not BART-eligible. 

TABLE 31—HAYDEN SMELTER OPTION 3: WET SCRUBBER ON ACID TAIL STACK

Capital cost Annualized 

capital cost 

Annual variable cost Total annual 

cost 

Control 

efficiency 

Tons SO2

reduced 

$/ton SO2

removed 

$28,000,000 ............................................. $2,643,002 $9,274,521 $11,917,523 85% 879 $13,564 

Energy and Non-Air Quality 

Environmental Impacts: This is the 

same as for Option 2. 

Pollution Control Equipment in Use at 

the Source: This is the same as for 

Options 1 and 2. 

Remaining Useful Life of the Source: 

This is the same as for Options 1 and 

2. 

Degree of Visibility Improvement: We 

did not conduct visibility modeling for 

a tail stack scrubber because of the high 

control cost per ton of SO2. However, 

because the scrubber would remove 

much less SO2 than options 1 or 2 

(second acid plant and wet scrubber on 

the secondary capture, respectively), the 

expected visibility improvement is far 

less than for options 1 and 2. 

e. Proposed BART Determination for 

SO2 From Converters 

Based on the results of our BART 

analysis, we propose that BART for SO2

from the converters is a level of control 

consistent with what ASARCO could 

achieve through the installation of a 

new double contact acid plant. This 

would control about 20,341 tpy of SO2

emissions from the converter units at a 

cost of about $872 per ton of SO2

removed, which we consider highly 

cost-effective. The expected visibility 

benefits of this option are substantial 

with a greater than 0.5 dv improvement 

in eleven Class I areas with a maximum 

benefit of 1.47 dv at Superstition WA. 

We propose to find that the energy and 

non-air quality environmental effects of 

this option are not sufficient to warrant 

elimination of this option. 

Regarding the other options, a wet 

scrubber for the secondary capture 

(Option 2) is less effective at a similar 

annual cost but with greater non-air 

environmental impacts. Therefore, we 

do not propose to require this as BART. 

Adding a scrubber to the existing acid 

tail stack for the primary capture 

(Option 3) would result in a relatively 

small amount of additional emissions 

reductions at a relatively high cost 

($13,564 per ton of SO2 removed) and 

with potentially significant non-air 

environmental impacts. Therefore, we 

propose that the addition of a scrubber 

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105See the TSD for further discussion of this 

issue. 

106See the TSD, Section III.D.4. 

107 40 CFR 51.308(e)(1)(iii). See also 40 CFR 

51.100(z) (defining ‘‘emission limitation’’ and 

‘‘emission standard’’ to include ‘‘any requirements 

which . . . prescribe equipment . . . for a source 

to assure continuous emission reduction.’’ 

108 40 CFR 51.308(e)(1)(ii)(C). 

to the existing acid plant is not required 

as BART. 

The specifics of our BART proposal 

for SO2 from the converters are as 

follows: 

• An SO2 control efficiency of 99.8 

percent, 30-day rolling average, on all 

SO2 captured by the primary and 

secondary control systems. The control 

efficiency may be averaged between the 

two capture systems on a mass basis, if 

needed. (For every 30-day period the 

total mass of SO2 exiting the two control 

systems must be no greater than 0.0019 

percent of the SO2 entering the control 

systems.) 

• Compliance with the SO2 BART 

limit may be verified either through the 

use of SO2 CEMS before and after 

controls in each system or by using 

post-control CEMS and acid production 

rates. A limit of 2.49 lbs SO2 emissions 

per tons of sulfuric acid production is 

equivalent to 99.8 percent control. 

• Operation and maintenance of 

primary and secondary capture systems 

meeting the requirements of 40 CFR part 

63, subpart QQQ. 

We propose to require that these 

requirements be met within 3 years of 

promulgation of the final rule, 

consistent with the requirement of the 

CAA and the RHR that BART be 

installed ‘‘as expeditiously as 

practicable.’’ 

2. BART Analysis and Determination for 

SO2 From Anode Furnaces 

a. BART Analysis for SO2 From Anode 

Furnaces 

We identified the same two control 

technologies for the anode furnaces: a 

new double contact acid plant and a wet 

scrubber. In addition, we considered 

whether emissions from the anode 

furnaces might be vented to the existing 

acid plant. 

Cost of Compliance: Based on our 

calculations, we estimated that the cost 

to control 37 tpy of SO2 from the anode 

furnaces by construction of a new acid 

plant is over $28,000 per ton, not 

including the cost of inlet preheating,105

as shown in Table 32. The estimated 

cost of installing and operating a wet 

scrubber is even more expensive at over 

$80,000 per ton106 as shown in Table 

33. 

TABLE 32—HAYDEN SMELTER: NEW ACID PLANT FOR THE ANODE FURNACES

Capital cost Annualized 

capital cost 

Annual 

variable cost 

Total annual 

cost 

Tons SO2

reduced 

Control 

efficiency 

$/ton SO2

removed 

$8,583,190 ............................................... $810,192 $261,827 $1,071,920 37 99.8% $28,616 

TABLE 33—HAYDEN SMELTER: NEW WET SCRUBBER FOR THE ANODE FURNACES

Capital cost Annualized 

capital cost 

Annual 

variable cost 

Total annual 

cost 

Tons SO2

reduced 

Control 

efficiency 

$/ton SO2

removed 

$7,000,000 ............................................... $660,750 $2,009,570 $2,670,320 32 85% $83,708 

Energy and Non-Air Quality 

Environmental Impacts: This is the 

same as for the converters. 

Pollution Control Equipment in Use at 

the Source: The anode furnaces 

currently have no SO2 controls in place. 

Remaining Useful Life of the Source: 

ASARCO has not indicated that any of 

the anode furnaces would need to be 

replaced during the 20-year capital cost 

recovery period. 

Degree of Visibility Improvement: We 

did not conduct visibility modeling for 

the anode furnace emissions. However, 

since the emissions from these units are 

a small fraction of those from the 

converters, the expected visibility 

improvement would be far less than for 

any of the controls considered for the 

converters. 

b. Proposed BART Determination for 

SO2 From Anode Furnaces 

Given the high cost of control, and the 

small potential for visibility 

improvement, we propose that 

controlling the 37 tpy of SO2 emissions 

from the anode furnaces is not 

warranted as BART. Furthermore, while 

redirecting the anode furnace emissions 

to the existing acid plant might be 

technically feasible and cost-effective, 

the emission reductions and visibility 

benefit, although not calculated, would 

be much smaller than the calculated 

benefits from controlling additional 

emissions from the converters. 

In order to ensure that emissions from 

anode furnaces do not increase 

substantially in the future, we are 

proposing to establish a work practice 

standard for these units. While BART 

determinations are generally 

promulgated in the form of numeric 

emission limitations, the RHR allows for 

use of equipment requirements or work 

practice standards in lieu of a numeric 

limit where ‘‘technological or economic 

limitations on the applicability of 

measurement methodology to a 

particular source would make the 

imposition of an emission standard 

infeasible.’’107 In this case, we find that 

a numerical emission limitation for the 

anode furnaces would be infeasible 

because of the relatively small amount 

of emissions from these units, compared 

with the converters. Therefore, we are 

proposing to establish a work practice 

standard in the form of a requirement 

that the anode furnaces be charged with 

blister copper or higher purity copper. 

Because blister copper is generally 98 to 

99 percent pure copper, this 

requirement will ensure that sulfur 

emission from the anode furnaces are 

minimized. 

3. Subject-to-BART, BART Analysis and 

BART Determination for NOX

a. Proposed Subject-to-BART Finding 

for NOX

As explained in our final rule on the 

Arizona RH SIP, once a source is 

determined to be subject to BART, the 

RHR allows for the exemption of a 

specific pollutant from a BART analysis 

only if the potential to emit for that 

pollutant is below a specified de 

minimis level.108 Neither the Hayden 

Smelter’s current Title V permit nor the 

Arizona RH SIP contains any physical 

or operational limitations that would 

limit the PTE of the BART-eligible 

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Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules 9347 

109AirControlNet, Version 4.1, documentation 

report by E.H. Pechan and Associates, Inc. for U.S. 

EPA, Office of Air Quality, Planning, and 

Standards, May 2006, section III, page 445. 

110 Id. 

111Summary of WRAP RMC BART Modeling for 

Arizona, Draft Number 5, May 25, 2007. Also, 

ASARCO response letter, July 11, 2013, ENVIRON 

memo attachment, March 4, 2012, (‘‘H–09 2013–03– 

04 ENVIRON report-Asarco-Hayden-BART.pdf’’. 

112 40 CFR 51.308(e)(1)(ii)(C). 

113Letter from Krishna Parameswaran, ASARCO, 

to Gregory Nudd, EPA dated March 6, 2013, page 

15. 

114 78 FR 46412 (July 30, 2013). See also the TSD 

for a description of these units. 

source below the NOX de minimis 

threshold of 40 tpy. Therefore, because 

the Hayden Smelter is subject to BART 

and has a PTE of more than 40 tons per 

year of NOX, we have analyzed potential 

NOX BART controls for the source. 

b. BART Analysis for NOX

The Hayden Smelter’s NOX emissions 

result from the combustion of natural 

gas to heat process equipment. LNB are 

an available, feasible and effective 

technical option for such process 

heaters, with an estimated control 

efficiency of 50 percent.109

Cost of Compliance: According to the 

Documentation Report accompanying 

AirControlNet, the cost to retrofit 

process heaters with LNB is $2,200 per 

ton.110

Energy and Non-Air Quality 

Environmental Impacts: No significant 

energy and non-air environmental 

impacts are expected to result from use 

of LNB. 

Pollution Control Equipment in Use at 

the Source: No NOX controls are 

currently employed at either the 

converters or the anode furnaces. 

Remaining Useful Life of the Source: 

ASARCO has not indicated that any of 

the units would need to be replaced 

during the 20-year capital cost recovery 

period. 

Degree of Visibility Improvement: The 

maximum modeled 98th percentile 

visibility impact resulting from baseline 

NOX emissions from the Hayden 

Smelter is no higher than 0.01 dv111 at 

any of the Class I areas. Thus, the 

maximum visibility benefit of controls 

is less than 0.01 dv. 

c. Proposed BART Determination for 

NOX

Given the small potential for visibility 

improvement, we propose that 

controlling these NOX emissions is not 

warranted for purposes of BART. 

However, in order to ensure that NOX

emissions do not increase in the future, 

we propose to set a 12-month rolling 

limit of 40 tons of NOX from the subjectto-BART units, which is equivalent to 

the de minimis level of emissions set 

out in the RHR.112 This emission limit 

is slightly lower than the annual 50 tpy 

baseline emissions noted above. 

Nonetheless, we consider it to be a 

reasonable limit because the 50 tpy 

estimate assumes that all of the 

converters are all operating 

simultaneously, which is not how they 

typically operate. Therefore, we expect 

actual emissions to be well below 40 

tpy, which is consistent with ASARCO’s 

own estimate.113

4. Summary of EPA’s Proposed BART 

Determinations 

We propose that BART for SO2 from 

the converters is a control efficiency of 

99.8 percent, 30-day rolling average, on 

all SO2 captured by the primary and 

secondary control systems. We propose 

to require compliance with this 

requirement within three years of 

promulgation of a final rule. We also are 

proposing monitoring, recordkeeping 

and reporting as well as operation and 

maintenance requirements, to ensure 

the enforceability of our proposed BART 

determination. We propose a work 

practice standard consistent with 

current practices for the anode furnaces. 

We also propose to set a 12-month 

rolling limit of 40 tons of NOX from the 

subject-to-BART units. 

We are seeking comment on all 

aspects of this proposal. In particular, 

we are seeking comment on the 

following elements of our BART 

analysis and determination for SO2 from 

the converters: 

• The cost of controls; 

• the collection efficiency for the 

primary collection system; 

• the collection efficiency for the 

secondary collection system; 

• the control efficiency to be applied 

to the primary and secondary 

collections systems; 

• the compliance methodology; and 

• the compliance schedule. 

If we receive additional information 

concerning these or other elements of 

our analysis, we may finalize a BART 

determination that differs in some 

respects from this proposal. 

D. Miami Smelter 

Summary: EPA proposes to find that 

the Miami Smelter is subject to BART 

for NOX in addition to SO2 and PM10, 

as determined by the State. For SO2

from the converters, we propose to 

require construction of a secondary 

capture system consistent with the 

requirements of MACT QQQ and an SO2

control efficiency of 99.7 percent, 30- 

day rolling average, on all SO2 captured 

by the primary and secondary capture 

systems. For SO2 emissions from the 

electric furnace, we propose to prohibit 

active aeration of the electric furnace. 

For NOX, we propose to find that 

controlling emissions from the 

converters and anode furnaces is costeffective, but would not result in 

sufficient visibility improvement to 

warrant the cost. Therefore, we are 

proposing an annual emission limit of 

40 tpy NOX emissions from the BARTeligible units at the Miami Smelter, 

which is consistent with current 

emissions from these units. We 

previously approved Arizona’s 

determination that BART for PM10 at the 

Miami Smelter is the NESHAP for 

Primary Copper Smelting. Please refer to 

the Long Term Strategy in Section VII 

below, regarding our proposal to ensure 

the enforceability of this determination. 

Affected Class I Areas: Twelve Class 

I areas are within 300 km of the Miami 

Smelter with the nearest borders ranging 

from 55 km to 260 km away. The set of 

areas differs from the ones near the 

Hayden Smelter only in that Bosque Del 

Apache WA is included, and Sycamore 

Canyon WA is not. The baseline 

visibility impacts are 0.70 dv or less at 

all Class I areas except at Superstition 

where the visibility impact is 3.6 dv. 

The cumulative sum of visibility 

impacts at all areas within 300 km is 8.2 

dv. 

Facility Overview: The Miami Smelter 

is a batch-process copper smelter in Gila 

County, Arizona. We previously 

approved ADEQ’s determination that 

Hoboken Converters 2, 3, 4 and 5 and 

the Electric Furnace at the facility are 

BART-eligible.114 We also approved 

ADEQ’s determination that these units 

are subject to BART for SO2 and that 

BART for PM10 at the Miami Smelter is 

the Maximum Achievable Control 

Technology (MACT) Subpart QQQ 

under the National Emission Standards 

for Hazardous Air Pollutants (NESHAP) 

for primary copper smelting. However, 

we disapproved ADEQ’s determination 

that existing controls constitute BART 

for SO2 and that the units are not subject 

to BART for NOX. In light of these 

disapprovals and our FIP duty for 

Regional Haze in Arizona, we are 

required to promulgate a FIP to address 

BART for both SO2 and NOX. 

Baseline Emissions: Because neither 

FMMI nor ADEQ identified baseline 

emissions for the Miami Smelter, we 

selected emissions from 2010 as the 

baseline. We chose 2010 because ADEQ 

provided the most detailed emissions 

information from this year in its RH SIP 

and because FMMI used 2010 as a basis 

for calculating uncaptured emissions of 

SO2 for 2011 and 2012. FMMI reports 

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115The vent fume duct is the stack for a wet 

scrubber used to control emissions collected by the 

IsaSmelt secondary collection system, other 

collection systems associated with conveyors that 

are not BART-eligible, and emissions collected by 

the BART-eligible electric furnace secondary 

collection system. 

116Letter from Derek Cooke, FMMI, to Thomas 

Webb, EPA, Appendices A and C, January 25, 2013. 

117Letter from Thomas Webb, EPA, to Derek 

Cooke, FMMI (June 27, 2013). 

emissions of SO2 to ADEQ by stack, and 

performs a mass-balance equation to 

determine uncaptured emissions. SO2

emissions in tons per year are presented 

in Table 34 as reported by FMMI to 

ADEQ for the acid plant duct, acid plant 

bypass duct, and the vent fume duct.115

Because each of these stacks vents 

emissions from both BART and nonBART emission units, EPA apportioned 

the emissions to BART and non-BART 

units for purposes of our analysis. The 

BART-eligible emissions from the acid 

plant were based on FMMI and ADEQ’s 

estimate that 35 percent of SO2 sent to 

the acid plant is emitted by the 

converters and 65 percent of SO2 is 

emitted by the primary smelter (often 

called by a proprietary name, the 

IsaSmelt furnace) and electric furnace. 

Because it is not possible to differentiate 

which converter emissions are from the 

one converter that is not BART-eligible, 

we are treating all converter emissions 

as subject to BART. Subject-to-BART 

emissions from the vent fume duct were 

set at seven tons per year based on our 

estimate of the share of emissions 

originating from the electric furnace. 

Please refer to the TSD for an 

explanation for how the subject-toBART uncaptured emissions are 

determined. 

TABLE 34—MIAMI SMELTER: BART BASELINE EMISSIONS FOR SO2 IN 2010 

[Tons per year] 

Acid plant duct Acid plant 

bypass 

Vent fume 

duct Uncaptured 

Total SO2 Emissions ........................................................................................ 1,415 93 331 8,472 

Subject-to-BART SO2 Emissions ..................................................................... 495 33 7 3,231–8,078 

FMMI also reports potentially BARTeligible NOX emissions from the acid 

plant duct and from ‘‘natural gas 

combustion’’ to ADEQ as depicted in 

Table 35. FMMI estimates that 15 

percent of NOX emitted from the acid 

plant duct originates from the BARTeligible converters. While ‘‘natural gas 

emissions’’ includes emissions from the 

converter burners, it is not possible to 

separate the BART-eligible emissions 

from ineligible emissions. Thus, we are 

assuming that all these emissions are 

BART-eligible. 

TABLE 35—MIAMI SMELTER: BART BASELINE EMISSIONS FOR NOX IN 2010 

[Tons per year] 

Acid plant duct Natural gas 

combustion 

Total NOx Emissions ............................................................................................................................................... 154 15 

Subject-to-BART NOX Emissions ............................................................................................................................ 23 15 

Modeling Overview: Using the 

CALPUFF model, EPA estimated the 

visibility impacts of the Miami Smelter 

in its current (i.e., baseline) 

configuration, and with two different 

control options for SO2 emissions. 

Model inputs were developed using 

work by the WRAP and updated stack 

and other information from FMMI. EPA 

made two different emissions 

calculations, incorporating high and low 

estimates of the amount of emissions 

that are not captured by the existing 

systems. Most of the discussion below 

focuses on modeling performed using 

the high estimate as shown in Table 37. 

An additional complication for this 

facility is that most of the emissions 

occur via a ‘‘roofline,’’ a long 

rectangular hole in the roof of the 

building containing the converters. 

Modeling the roofline as if it were a 

stack may be problematic, especially for 

nearby Class I areas. Modeling the 

roofline as a buoyant line source is a 

better characterization of the source. 

EPA performed sensitivity simulations, 

described in the TSD, and found that 

impacts do vary depending on whether 

it is modeled as a stack or a line source. 

Which modeling scenario resulted in 

higher impacts depended on the 

particular Class I area. EPA therefore 

modeled the main emissions from 

FMMI as a buoyant line source, despite 

the considerably longer model run 

times. 

1. BART Analysis for SO2 From 

Converters 

a. Control Technology Availability, 

Technical Feasibility and Effectiveness 

We identified two available and 

feasible technologies to control SO2

emissions from the converters: a double 

contact acid plant and wet scrubbing. 

FMMI already uses these two 

technologies in series to control SO2

emissions currently captured from the 

converters. Based on SO2 acid plant 

emissions and sulfuric acid production 

data provided to EPA by FMMI, we 

calculated that the existing acid plant 

and tail gas scrubber system is 

controlling at least 99.7 percent of the 

SO2 ducted to the acid plant,116 which 

we consider effective. Because FMMI 

already uses both of the two available 

control technologies to control SO2

emissions currently captured from the 

converters and achieves a high degree of 

control of these emissions, we did not 

further evaluate additional controls or 

upgrades to the existing controls as 

BART. Rather, we evaluated ways to 

improve the capture efficiency of the 

existing system so that additional 

emissions may be collected and 

controlled. 

In order to analyze options for 

improved capture, we requested 

information from FMMI regarding 

potential design improvements, 

upgrades to existing equipment or new 

equipment that could increase the 

degree of capture of SO2 emissions from 

the converters.117 In response, FMMI 

reported that it planned to improve the 

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118Letter from Derek Cooke, FMMI to Thomas 

Webb, EPA, Item 2 (July 12, 2013). FMMI indicated 

that ‘‘[t]hese proposed changes are in anticipation 

of measures that may be adopted by ADEQ as 

necessary to demonstrate compliance’’ with the 

2012 SO2 NAAQS.’’ Regardless of their regulatory 

purpose of the changes, FMMI’s proposal indicates 

that these changes are technically feasible. 

119See the TSD, Section III.D.4. 

120Review of New Source Performance Standards 

for Primary Copper Smelters, OAQPS, EPA 450/3– 

83–018a, March 1984. According to Section 4.7.6.3, 

the overall collection efficiency of secondary fixed 

hoods is approximately 90 percent. 

121Letter from Derek Cooke, FMMI to Thomas 

Webb, EPA, Item 2 (July 12, 2013). 

converter mouth covers, reconfigure the 

roofline capture system and route the 

captured emissions to the existing acid 

plant.118 Accordingly, we performed a 

five-factor BART analysis for these 

improvements, which we refer to 

collectively as a ‘‘secondary capture 

system.’’ 

b. Secondary Capture System 

The purpose of the secondary capture 

system is to improve capture and 

control of SO2 emissions from the 

converters that can then be directed to 

the existing double contact acid plant. 

Cost of Compliance: FMMI claimed as 

confidential business information (CBI) 

the cost information for improvements 

in SO2 capture, so we relied on other 

information to estimate the cost of 

controls. In particular, we considered 

cost estimates supplied by ASARCO for 

the Hayden Smelter, a similar facility, 

for a series of upgrades to its capture 

systems.119 We estimated costeffectiveness using a capital cost of 

$47,850,000, and annualized those costs 

assuming a 20-year lifespan and a 7 

percent interest rate with an operation 

and maintenance cost of 50 percent of 

the capital cost. We applied a control 

efficiency of 99.7 percent, which the 

existing acid plant and tail stack 

scrubber system currently achieves 

using very limited cesium catalyst. The 

emission reduction was applied to 85 

percent of the currently uncaptured SO2

emissions from the converters.120 Based 

on these calculations, we estimate the 

cost-effectiveness of installing and 

operating a secondary capture system 

would be $990 to $2,474 per ton of SO2

removed, as shown in Table 36. This 

range reflects the uncertainty in the 

quantity of SO2 emissions that are 

currently not captured. 

TABLE 36—MIAMI SMELTER: COST OF SECONDARY CAPTURE OF SO2 FROM CONVERTERS

Capital cost Annualized 

capital cost 

Annual 

variable cost 

Total annual 

cost 

Tons SO2

reduced 

Control 

efficiency 

$/ton SO2

removed 

$47,850,000 ............................................. $4,516,701 $2,258,351 $6,775,052 2,379–6,845 99.7% $990–2,474 

Energy and Non-Air Quality 

Environmental Impacts: We do not 

anticipate significant energy or other 

non-air quality environmental impacts 

resulting from capturing and ducting 

additional emissions to the existing SO2

control system given that FMMI already 

has the capacity to handle and store the 

much larger quantities of sulfuric acid 

produced by emissions captured from 

the IsaSmelt and converter primary 

capture systems. 

Pollution Control Equipment in Use at 

the Source: SO2 emissions collected 

from the converters are ducted to the 

four-pass, double contact acid plant. 

There is a wet scrubber (the tailstack 

scrubber) located after the acid plant 

outlet, to which emissions may be 

vented during periods of elevated SO2

concentrations.121

Remaining Useful Life: The BARTeligible converters have each been in 

place for about 40 years. FMMI has not 

indicated that any of them would be 

replaced during the 20-year capital cost 

recovery period. 

Degree of Visibility Improvement: As 

shown in Table 37, installing a 

secondary capture system to collect and 

direct SO2 emissions from the 

converters to the acid plant, the 

maximum 98th percentile baseline 

improvement ranges from a low of 0.41 

dv to a high of 1.06 dv at Superstition 

WA. The cumulative improvement 

ranges from 1.7 to 4.3 dv. These are 

large visibility improvements that 

support using the existing acid plant 

with a new secondary capture system as 

BART for SO2. The high and low 

visibility impacts and improvements in 

Table 37 correspond to the range of 

emissions that are not captured. The 

range is 3,231 (low) to 8,078 (high) tpy. 

For the low emission estimate, the 

maximum improvement from the 

secondary capture system is 0.41 dv, 

and the cumulative improvement is 1.7 

dv. These are considerably less than for 

the high emission estimate, which has a 

maximum improvement of 1.06 dv and 

cumulative improvement of 4.3 dv, but 

is still substantial. 

TABLE 37—MIAMI SMELTER: VISIBILITY IMPACT AND IMPROVEMENT FROM SECONDARY CAPTURE SYSTEM

Class I area Distance 

(km) 

Impact Improvement 

from control 

Impact Improvement 

from control 

High base 

case 

(basehi) 

Converter 

85% capture 

(opt1hi) 

Low base 

case 

(baselo) 

Converter 

85% capture 

(opt1lo) 

Bosque del Apache WA ................................................................... 235 0 .15 0 .12 0 .07 0 .05 

Chiricahua NM ................................................................................. 113 0 .36 0 .27 0 .16 0 .10 

Chiricahua WA ................................................................................. 125 0 .35 0 .27 0 .16 0 .10 

Galiuro WA ....................................................................................... 99 0 .56 0 .40 0 .28 0 .17 

Gila WA ............................................................................................ 55 0 .34 0 .26 0 .16 0 .10 

Mazatzal WA .................................................................................... 220 0 .64 0 .44 0 .32 0 .17 

Mount Baldy WA .............................................................................. 95 0 .27 0 .20 0 .13 0 .08 

Petrified Forest NP .......................................................................... 197 0 .33 0 .25 0 .16 0 .10 

Pine Mountain WA ........................................................................... 260 0 .43 0 .32 0 .20 0 .12 

Saguaro NP ..................................................................................... 143 0 .45 0 .34 0 .21 0 .13 

Sierra Ancha WA ............................................................................. 158 0 .70 0 .40 0 .42 0 .17 

Superstition WA ............................................................................... 163 3 .61 1 .06 2 .86 0 .41 

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9350 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules 

122 40 CFR 51.308(e)(1)(iii). See also 40 CFR 

51.100(z)(defining ‘‘emission limitation’’ and 

‘‘emission standard’’ to include ‘‘any requirements 

which . . . prescribe equipment . . . for a source 

to assure continuous emission reduction.’’ 

123ADEQ Class 1 Permit Number 53592, 

Application for a Significant Permit Revision, July, 

2013. 

124AP 42, Chapter 12.3, Primary Copper Smelters, 

Table 12.3–3 (cleaning furnace) and Table 12.3–11 

(converter slag return). 

TABLE 37—MIAMI SMELTER: VISIBILITY IMPACT AND IMPROVEMENT FROM SECONDARY CAPTURE SYSTEM—Continued 

Class I area Distance 

(km) 

Impact Improvement 

from control 

Impact Improvement 

from control 

High base 

case 

(basehi) 

Converter 

85% capture 

(opt1hi) 

Low base 

case 

(baselo) 

Converter 

85% capture 

(opt1lo) 

Cumulative (sum) ............................................................................. .................... 8 .2 4 .3 5 .1 1 .7 

Maximum .......................................................................................... .................... 3 .61 1 .06 2 .86 0 .41 

# CIAs >= 0.5 dv .............................................................................. .................... 4 1 1 0 

Million $/dv (cumul. dv) .................................................................... .................... ...................... $1 .6 ...................... $4 .0 

Million $/dv (max. dv) ....................................................................... .................... ...................... $6 .4 ...................... $16 .7 

c. Proposed BART Determination for 

SO2 From Converters 

Based on the results of our BART 

analysis, we propose that BART for SO2

from the converters is construction of a 

secondary capture system (i.e., 

construction of hooding and ventilation 

systems to capture escaped SO2

emissions) and ducting the emissions to 

existing controls. We have determined 

that these improvements are feasible 

and cost-effective, will result in 

significant visibility improvements, and 

should not result in significant adverse 

impacts. As noted above, the RHR 

allows for use of equipment 

requirements or work practice standards 

in lieu of a numeric limit where 

‘‘technological or economic limitations 

on the applicability of measurement 

methodology to a particular source 

would make the imposition of an 

emission standard infeasible.’’ 122 In this 

instance, we propose to find that 

technological limitations on the source’s 

ability to measure accurately 

uncaptured SO2 emissions make 

numeric capture efficiency infeasible. 

Therefore, we are proposing to prescribe 

specific equipment for capture of SO2

emissions, in addition to numeric 

control efficiency and related 

compliance requirements. Specifically, 

we are proposing the following as BART 

for SO2 from the converters: 

• Construction of a secondary capture 

system consistent with the requirements 

of MACT QQQ as a work practice 

standard. 

• An SO2 control efficiency of 99.7 

percent, 30-day rolling average, on all 

SO2 captured by the primary and 

secondary capture systems. 

• Compliance with the SO2 BART 

limit may be verified either through the 

use of SO2 CEMS before and after 

controls or by using post-control CEMS 

and acid production rates. A limit of 

4.06 lbs SO2 emissions per tons of 

sulfuric acid production is equivalent to 

99.7 percent control. 

d. Alternative Control Efficiency 

We are also seeking comment on 

whether FMMI should be expected to 

meet a 99.8 percent control efficiency, 

30-day rolling average, on all SO2

captured by the primary and secondary 

capture systems. ASARCO Hayden has 

demonstrated that a control efficiency of 

99.8 percent is achievable in practice at 

a batch copper smelter. FMMI could 

increase control efficiency by increasing 

its use of cesium promoted catalyst in 

the acid plant, increasing the volume of 

gas exiting the acid plant that is further 

controlled by the tail stack scrubber, 

and/or using sodium rather than 

magnesium in the scrubbing liquor. If 

we received comments establishing that 

a control efficiency greater than 99.7 

percent is achievable at FMMI, we may 

finalize a control efficiency of up to 99.8 

percent. 

2. BART Analysis for SO2 From Electric 

Furnace 

a. Control Technology Availability, 

Technical Feasibility and Effectiveness 

EPA identified two possible 

technologies to control SO2 emissions 

from the electric furnace: Double 

contact acid plant and wet scrubbing. 

FMMI has indicated to EPA that 

emissions from the electric furnace are 

already controlled by the existing 

double contact acid plant and tail stack 

scrubber.123 In addition, a secondary 

capture system ducts gases not captured 

by the primary capture system to the 

vent fume scrubber, which has a control 

efficiency of 80 percent. Because FMMI 

already uses both of the two available 

control technologies to control SO2

emissions currently captured from the 

furnace, we did not evaluate the 

addition of new controls, nor did we 

evaluate upgrades to the acid plant 

system, which already achieves a high 

degree of control. The one improvement 

to controls that we identified was 

upgrading the scrubber, which currently 

uses magnesium oxide, to use sodium 

hydroxide, which could increase the 

control efficiency from 80 percent to 98 

percent. 

b. Existing Double Contact Acid Plant 

and Wet Scrubbing 

Cost of Compliance: We estimated the 

emissions from the electric furnace by 

multiplying the relevant AP 42 emission 

factors for copper smelters 124 by the 

2010 concentrate throughput provided 

by FMMI. This results in uncontrolled 

emissions of SO2 from the electric 

furnace of 379 tons per year. Because 

the scrubber is a secondary control 

device, however, this would likely 

result in an emissions decrease of no 

more than 5 to 10 tons per year. 

Replacing magnesium oxide with 

sodium hydroxide would cost at least 

$2,000,000 per year, resulting in control 

costs of $200,000–$400,000 per ton of 

SO2 removed, as shown in Table 38. 

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125AirControlNet, Version 4.1, Documentation 

Report. Prepared by E.H. Pechan and Associates, 

Inc. for U.S. EPA, Office of Air Quality, Planning, 

and Standards. May, 2006, section III, page 445. 

126Summary of WRAP RMC BART Modeling for 

Arizona, Draft Number 5, May 25, 2007, page 23. 

127 Id. 

128 40 CFR 51.308(e)(1)(ii)(C). 

129 40 CFR 51.308(d)(1)(i)(A). 

130 40 CFR 51.308(d)(1)(ii). 

131See 78 FR 46173 (codified at 40 CFR 

52.145(g)). 

TABLE 38—MIAMI SMELTER: COST OF UPGRADING VENT FUME SCRUBBER

Capital cost Annualized 

capital cost 

Annual 

variable cost 

Total annual 

cost 

Tons SO2

reduced 

Control 

efficiency $/ton SO2 removed 

$2,000,000 $2,000,000 5–10 98% $200,000–$400,000 

Energy and Non-Air Quality 

Environmental Impacts: We do not 

anticipate significant energy or non-air 

quality environmental impacts resulting 

from capturing and ducting additional 

emissions to the existing SO2 control 

system. Non-air quality impacts from 

venting additional captured emissions 

to the existing scrubber are not expected 

to be significant given that FMMI is 

already controlling much larger 

quantities of SO2 in the existing 

scrubber and managing the wastewater 

and sludge that result. 

Pollution Control Equipment in Use at 

the Source: SO2 emissions collected 

from the electric furnace are ducted to 

the four-pass, double contact acid plant. 

There is a wet scrubber (the tailstack 

scrubber) located after the acid plant 

outlet, to which emissions may be 

vented ‘‘if needed.’’ In addition, gases 

collected from the secondary collection 

system are ducted to the vent fume 

scrubber, which is another wet scrubber. 

The vent fume scrubber also controls 

secondary emissions from the IsaSmelt 

and emissions collected from other 

equipment. 

Remaining Useful Life: FMMI has not 

indicated any plans to remove the 

electric furnace from service. 

Degree of Visibility Improvement: Our 

modeling results did not demonstrate 

even modest visibility improvements at 

any Class I areas from this option. 

Improvements were 0.004 dv or less at 

each Class I area, and only 0.008 dv for 

the cumulative sum over all areas. 

These are negligible visibility 

improvements over the baseline levels, 

as expected from the small emission 

reductions associated with this option. 

c. BART Determination for Electric 

Furnace 

Based on the high cost of compliance 

to upgrade the vent fume scrubber and 

low potential for visibility 

improvement, we are proposing that 

existing controls represent BART for 

SO2 emissions from the electric furnace. 

While we would prefer to set a numeric 

emission limit in order to ensure that 

SO2 emissions from the electric furnace 

do not increase in the future, such a 

limit is impracticable because emissions 

from the electric furnace are 

commingled with emissions from nonBART eligible units in the vent fume 

stack. Therefore, consistent with 40 CFR 

51.308(e)(1), we propose a work practice 

standard prohibiting active aeration of 

the electric furnace. 

3. BART Analysis for NOX From Process 

Heaters 

NOX emissions from the FMMI 

smelter result from the combustion of 

natural gas to heat process equipment. 

According to the Documentation Report 

accompanying AirControlNet, the cost 

to retrofit process heaters with low NOX

burners, which can reduce NOX

emissions by 50 percent, is $2,200 per 

ton.125 Although this is not necessarily 

cost-prohibitive, there is relatively little 

potential for visibility improvement 

from installation of any NOX controls at 

FMMI. In particular, the maximum 

modeled 98th percentile visibility 

impact resulting from baseline NOX

emissions from FMMI is 0.11 dv.126 In 

addition, the WRAP estimated the 

annual BART-eligible NOX emissions 

from the facility as 159 tons per year,127

whereas we estimate annual BARTeligible NOX baseline emissions as 38 

tons per year. Therefore, the baseline 

visibility impact attributable to NOX, 

and thus, the potential for visibility 

improvement due to NOX reductions, is, 

in fact, significantly less than 0.11 dv. 

Given the small potential for visibility 

improvement, we propose that NOX

controls are not warranted for purposes 

of BART. However, in order to ensure 

that NOX emissions do not increase in 

the future, we propose to set a 12-month 

rolling cap of 40 tons of NOX from the 

subject-to-BART units, which is 

equivalent to the de minimis level of 

emissions set out in the RHR and is 

roughly equivalent to current annual 

emissions from these units.128

VI. EPA’s Proposed Reasonable 

Progress Analyses and Determinations 

Summary: In this section, EPA 

addresses point sources for NOX, area 

sources for NOX and SO2, the reasonable 

progress goals for the Class I areas, and 

a demonstration that the rate of progress 

is reasonable compared to the URP. In 

our previous actions on the Arizona RH 

SIP, EPA narrowed the focus of the RP 

analysis to point sources of NOX and 

area sources of NOX and SO2. Based on 

our analysis, we propose to require 

emissions reductions consistent with 

SNCR on Kiln 4 at the Phoenix Cement 

Clarkdale Plant and on Kiln 4 at the 

CalPortland Cement Rillito Plant. EPA 

proposes to find that it is not reasonable 

to require additional controls on area 

sources of NOX and SO2 at this time. We 

are also proposing RPGs consistent with 

a combination of control measures that 

include the approved Arizona RH SIP 

measures as well as the finalized and 

proposed Arizona RH FIP measures. 

Finally, we propose to find that it is not 

reasonable for any of Arizona’s Class I 

areas to meet the URP during this 

planning period, and demonstrate that 

rate of progress is reasonable based on 

our RP analysis. 

Background: The RHR requires the 

State, or EPA in the case of a FIP, to set 

RPGs by considering four factors: ‘‘the 

costs of compliance, the time necessary 

for compliance, the energy and non-air 

quality environmental impacts of 

compliance, and the remaining useful 

life of any potentially affected sources’’ 

(collectively ‘‘the RP factors’’).129 The 

RPGs must provide for an improvement 

in visibility on the worst days and 

ensure no degradation in visibility on 

the best days during the planning 

period. Furthermore, if the projected 

progress for the worst days is less than 

the Uniform Rate of Progress (URP), 

then the state or EPA must demonstrate, 

based on the factors above, that it is not 

reasonable to provide for a rate of 

progress consistent with the URP.130

In our final rule on the Arizona RH 

SIP published on July 30, 2013, we 

partially approved and partially 

disapproved the State’s RP analysis.131

In particular, we approved the State’s 

decision to focus on NOX and SO2

sources and its decision not to require 

additional controls on non-BART point 

sources of SO2 for this planning period. 

However, we disapproved the State’s 

RPGs for the worst days and best days, 

as well as its RP analyses and 

determinations for point sources of NOX

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132The analysis included NOX, SO2, and 

particulate matter pollutants because we had not 

yet approved ADEQ’s determination to focus on 

NOX and SO2, nor had we approved its conclusion 

regarding non-BART SO2 point sources, at the time 

this screening analysis was performed. 

133 ‘‘EP–D–07–102 WA5–12 Task4 Deliverable 

(AZ–BART-QbyD-Screening-report)-final.xlsx’’. 134See 40 CFR part 51, app. Y, § III (How to 

Identify Sources ‘‘Subject to BART’’). 

135Section 3.2, Initial Screening Criteria (New), 

Federal Land Managers’ Air Quality Related Values 

Work Group (FLAG) Phase I Report—Revised 

(2010). 

136See spreadsheet ‘‘10D Screening Update— 

2008–10 Emission Data.xlsx’’ in the docket. 

as well as area sources of SO2 and NOX. 

Accordingly, we have analyzed these 

remaining source categories to 

determine whether additional controls 

are reasonable based on an evaluation of 

the RP factors. 

A. Reasonable Progress Analysis of 

Point Sources for NOX

EPA conducted an extensive 

statewide analysis of NOX point sources 

to determine whether cost-effective 

controls on sources near Class I areas 

would contribute to visibility 

improvements. In this section, we 

describe the process to identify and 

analyze these potentially affected NOX

point sources for reasonable progress. Of 

the nine point sources evaluated for 

reasonable progress, EPA is proposing to 

require Phoenix Cement Clarkdale Plant 

and CalPortland Cement Rillito Plant to 

comply with new emissions limits for 

NOX based on the analysis presented 

below and in the TSD available in the 

docket. We are seeking comment on our 

analyses and proposed determinations 

for all the identified sources. 

1. Identification of NOX Point Sources 

To identify point sources in Arizona 

that potentially affect visibility in Class 

I areas, EPA examined the annual 

emissions data from the WRAP 2002 

planning inventory and identified those 

sources with facility-wide actual 

emissions that exceed 250 tpy of NOX or 

SO2. For these sources, we calculated 

the total actual emission rate (Q) in tpy 

of NOX and SO2 and determined the 

distance (D) in kilometers of each source 

to its closest Class I area.132 We 

employed a contractor to prepare an 

initial spreadsheet calculating these Q 

and D values.133 We used a Q divided 

by D value of ten as a threshold for 

further evaluation of RP controls. We 

selected this value based on guidance 

contained in the BART Guidelines, 

which state: 

Based on our analyses, we believe that a 

State that has established 0.5 deciviews as a 

contribution threshold could reasonably 

exempt from the BART review process 

sources that emit less than 500 tpy of NOX

or SO2 (or combined NOX and SO2), as long 

as these sources are located more than 50 

kilometers from any Class I area; and sources 

that emit less than 1000 tpy of NOX or SO2

(or combined NOX and SO2) that are located 

more than 100 kilometers from any Class I 

area.134

The approach described above 

corresponds to a Q/D threshold of ten. 

In addition, the use of a Q/D threshold 

of ten or greater is recommended by the 

Federal Land Managers’ Air Quality 

Related Values Work Group (FLAG) as 

a screening threshold, as described in 

the FLAG 2010 Phase I Report.135 A 

summary of sources with a Q/D value 

greater than 10 is included in Table 39. 

TABLE 39—SOURCES OF NOX WITH Q/D VALUE GREATER THAN 10 

Owner/operator Facility name Q 

(tpy) 

D 

(km) Q/D 

Arizona Public Service .......................................... West Phoenix Plant .............................................. 992 73.10 14 

CalPortland Cement Co ........................................ Rillito Plant ........................................................... 5,075 6.99 726 

Arizona Electric Power Coop ................................ Apache Generating Station .................................. 11,840 44.86 264 

Arizona Public Service .......................................... Cholla Power Plant ............................................... 33,588 31.75 1058 

Lhoist North America ............................................ Douglas Lime Plant .............................................. 755 55.16 14 

El Paso Natural Gas Co ....................................... Tucson Compressor Station ................................. 336 14.72 23 

El Paso Natural Gas Co ....................................... Flagstaff Compressor Station ............................... 1,010 34.94 29 

Tucson Electric Power .......................................... Sundt Generating Station ..................................... 5,659 15.84 357 

Lhoist North America ............................................ Nelson Lime Plant ................................................ 2,556 24.56 104 

Freeport-McMoRan ............................................... Miami Smelter ...................................................... 5,996 15.58 385 

Phoenix Cement ................................................... Clarkdale Plant ..................................................... 2,744 12.65 217 

Pima County ......................................................... Ina Road Sewage Plant ....................................... 258 12.56 21 

ASARCO ............................................................... Smelter and Mill ................................................... 18,486 47.22 392 

Salt River Project .................................................. Coronado Generating Station .............................. 29,674 48.53 611 

Salt River Project .................................................. San Tan Generating Station ................................ 335 28.13 12 

Catalyst Paper Abitibi ........................................... Snowflake Pulp Mill .............................................. 5,143 39.36 131 

Salt River Project .................................................. Aqua Fria Generating Station .............................. 994 68.87 14 

Tucson Electric Power .......................................... Springerville Generating Station .......................... 32,434 60.46 536 

El Paso Natural Gas Co ....................................... Williams Compressor Station ............................... 1,373 19.12 72 

Of the sources listed in Table 39, we 

eliminated several sources from further 

consideration by calculating updated Q/ 

D values based on 2008–2010 emission 

data.136 As a result, APS West Phoenix 

Plant, Lhoist Douglas Plant, SRP San 

Tan Generating Station, and SRP Agua 

Fria Generating Station have Q/D values 

less than or equal to ten. Thus, we 

eliminated these sources from further 

consideration for this planning period. 

However, if any of these sources resume 

operations at levels sufficient to 

increase their Q/D value to ten or 

greater, Arizona should consider them 

for potential RP controls in the next 

planning period. 

Finally, we eliminated from further 

consideration those sources (or units at 

sources) that were evaluated under 

BART. These include the Apache 

Generating Station, Coronado 

Generating Station, Cholla Power Plant 

(except Unit 1), Sundt Generating 

Station (except for Units 1–3), 

Snowflake Pulp and Paper Mill, and 

Nelson Lime Plant. Because the BART 

analysis examines many of the same 

factors as those evaluated for reasonable 

progress, we propose that the BART 

determinations for these facilities satisfy 

the requirement for reasonable progress 

from these facilities during this 

planning period. The final list of 

sources considered for reasonable 

progress NOX controls is summarized in 

Table 40. 

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137While visibility is not an explicitly listed 

factor to consider when determining whether 

additional controls are reasonable, the purpose of 

the four-factor analysis is to determine what degree 

of progress toward natural visibility conditions is 

reasonable. Therefore, it is appropriate to consider 

the projected visibility benefit of the controls when 

determining if the controls are needed to make 

reasonable progress. 

138Comments submitted on EPA’s December 21, 

2012 proposed rulemaking partially approving and 

disapproving Arizona’s Regional Haze Plan. 77 FR 

75704. 

139Typical Installation Timelines for NOX

Emissions Control Technologies on Industrial 

Sources, Institute of Clean Air Companies, 

December 4, 2006. 

TABLE 40—SOURCES OF NOX FOR REASONABLE PROGRESS ANALYSES

Owner/operator Facility name Notes 

CalPortland Cement Co .................................................... Rillito Plant.

Arizona Public Service ...................................................... Cholla Power Plant (Unit 1) ............................................ Units 2–4 subject to BART. 

El Paso Natural Gas Co ................................................... Tucson Compressor Station.

El Paso Natural Gas Co ................................................... Flagstaff Compressor Station.

Tucson Electric Power ...................................................... Sundt Generating Station (Units 1–3) ............................. Unit 4 subject to BART. 

Phoenix Cement ............................................................... Clarkdale Plant.

Pima County ..................................................................... Ina Road Sewage Plant.

Tucson Electric Power ...................................................... Springerville Generating Station (Units 1–2) .................. Units 3–4 have SCR. 

El Paso Natural Gas Co ................................................... Williams Compressor Station.

2. Analysis of Potentially Affected NOX

Point Sources 

EPA contracted with the University of 

North Carolina (UNC) and their 

subcontractor, Andover Technology 

Partners (ATP), to perform RP analyses 

for the nine sources listed in Table 40. 

EPA considered the four RP factors for 

each of these sources based on the work 

from UNC. In addition, for the larger 

point sources (EGUs and cement kilns), 

we conducted CALPUFF modeling to 

assess the potential visibility benefits of 

controls.137 These analyses are set out in 

the TSD and are summarized in the 

following sections. 

a. Phoenix Cement Clarkdale Plant Kiln 

4 

Costs of Compliance: This facility 

consists of one precalciner kiln, which 

currently uses LNB for NOX control. Our 

estimate of costs of compliance is based 

primarily on estimates provided by PCC 

in their March 6, 2013 comment letter, 

with revisions to certain cost items we 

considered to be unreasonable or not 

allowed by EPA’s Control Cost 

Manual.138 As explained in further 

detail in the TSD, we estimated a total 

annual cost for SNCR of approximately 

$940,000 per year. SNCR is estimated to 

reduce emissions at the kiln by 810 tpy 

at a cost of $1,142/ton, based on 

baseline emissions of 1620 tpy and a 50 

percent SNCR control efficiency. As 

explained in the TSD, we are seeking 

comment on whether a different SNCR 

control efficiency is appropriate for this 

kiln. If we receive technical information 

demonstrating that a different SNCR 

control efficiency is appropriate for Kiln 

4, we will incorporate this change into 

our analysis. 

Time Necessary for Compliance: We 

expect that SNCR could be installed in 

approximately 3 years from the final 

date of this action. The Institute of 

Clean Air Companies estimates that the 

installation time for SNCR on industrial 

sources is 10–13 months.139 CPCC 

estimates that it would require 

approximately three years to install 

SNCR on their similar technology kiln. 

Given these two pieces of information, 

a 3-year timeframe appears to be 

reasonable. 

Energy and Non-Air Quality 

Environmental Impacts of Compliance: 

The installation and operation of SNCR 

at the plant would require a small 

increase in energy usage. The cost of 

this additional energy usage is included 

in the cost analysis. Non-air quality 

environmental impacts associated with 

SNCR include the hazards of 

transporting and storing urea or 

ammonia, especially if anhydrous 

ammonia is used. However, since the 

handling of anhydrous ammonia will 

involve the development of a risk 

management plan (RMP), we consider 

the associated safety issues to be 

manageable as long as established safety 

procedures are followed. Therefore, we 

find that these impacts are not sufficient 

to warrant eliminating SNCR as a 

control option. 

Remaining Useful Life: EPA presumes 

that the kiln would continue operating 

for 20 years and fully amortize the cost 

of controls. 

Degree of Improvement in Visibility: 

There are twelve Class I areas within 

300 km of the Clarkdale Plant. As 

shown in Table 41, the highest 98th 

percentile baseline visibility impact of 

Phoenix Cement is 5.2 dv at Sycamore. 

Pine Mountain, Mazatzal, and the Grand 

Canyon all have visibility impacts over 

0.5 dv, and other areas are at 0.1 dv or 

less. The cumulative sum of visibility 

impacts over all the Class I areas is 7.5 

dv. The maximum visibility 

improvement due to SNCR is 1.9 dv at 

Sycamore, 0.3 dv at Pine Mountain, and 

slightly less at Mazatzal and the Grand 

Canyon. The cumulative improvement 

from SNCR is 3.0 dv. 

TABLE 41—PHOENIX CEMENT KILN 4: VISIBILITY IMPACT AND IMPROVEMENT FROM NOX CONTROLS

Class I Area Distance 

(km) 

Visibility 

impact 

Visibility 

improvement 

Base case 

(base) 

SNCR 

¥50% NOX

(ctrl2) 

Bryce Canyon NP ................................................................................................................................ 296 0 .09 0 .04 

Galiuro WA .......................................................................................................................................... 278 0 .03 0 .01 

Grand Canyon NP ............................................................................................................................... 133 0 .51 0 .25 

Mazatzal WA ........................................................................................................................................ 59 0 .51 0 .24 

Mount Baldy WA .................................................................................................................................. 249 0 .05 0 .02 

Petrified Forest NP .............................................................................................................................. 200 0 .21 0 .10 

Pine Mountain WA ............................................................................................................................... 56 0 .66 0 .32 

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140The basis for this specific emission rate is 

described in the TSD. 

TABLE 41—PHOENIX CEMENT KILN 4: VISIBILITY IMPACT AND IMPROVEMENT FROM NOX CONTROLS—Continued 

Class I Area Distance 

(km) 

Visibility 

impact 

Visibility 

improvement 

Base case 

(base) 

SNCR 

¥50% NOX

(ctrl2) 

Saguaro NP ......................................................................................................................................... 284 0 .03 0 .01 

Sierra Ancha WA ................................................................................................................................. 142 0 .09 0 .04 

Superstition WA ................................................................................................................................... 151 0 .10 0 .05 

Sycamore Canyon WA ........................................................................................................................ 10 5 .15 1 .85 

Zion NP ................................................................................................................................................ 272 0 .09 0 .05 

Cumulative (sum) ................................................................................................................................. .................... 7 .5 3 .0 

Maximum ............................................................................................................................................. .................... 5 .15 1 .85 

# CIAs >= 0.5 dv ................................................................................................................................. .................... 4 1 

Million $/dv (cumul. dv) ........................................................................................................................ .................... ...................... $0 .3 

Million $/dv (max. dv) .......................................................................................................................... .................... ...................... $0 .5 

Phoenix Cement is only 10.5 km away 

from the Sycamore Canyon Wilderness. 

Therefore NOX emitted by the Plant may 

not be fully converted to NO2 by the 

time it reaches Sycamore Canyon and 

may not be fully available to form 

visibility-degrading particulate nitrate. 

However, the CALPUFF model assumes 

100 percent conversion. EPA explored 

this issue by scaling back the visibility 

extinction due to NO2 and nitrate to 

reflect lower NO-to-NO2 conversion 

rates, described further in the TSD. As 

shown in Table 42, EPA found that 

visibility impacts and the improvement 

due to SNCR decrease along with the 

percent conversion assumed. However, 

the benefit of SNCR is 0.52 dv when NO 

conversion is reduced to 25 percent. 

Even for an unrealistically low 

assumption of 10 percent (i.e., no 

conversion of NO to NO2 after the 

plume leaves the stack), the benefit of 

SNCR is 0.25 dv at Sycamore Canyon 

alone. Because the other Class I Areas 

are far enough away for NOX emitted by 

the Plant to be fully converted to NO2, 

the benefits at the other Class I areas 

would remain the same. 

TABLE 42—BENEFIT OF SNCR ON PHOENIX CEMENT AT SYCAMORE CANYON FOR VARIOUS NO-TO-NO2 CONVERSION

RATES

NO % Conversion 100% 75% 50% 25% 10% 

Base case ................................................................................................ 5.14 4.19 3.13 1.94 1.17 

SNCR ....................................................................................................... 3.30 2.68 2.07 1.42 0.92 

Benefit ...................................................................................................... 1.85 1.51 1.06 0.52 0.25 

Proposed RP Determination: Based on 

our analysis of the four RP factors, as 

well as the expected degree visibility 

improvement, EPA proposes to require 

compliance with an emission limit of 

2.12 lb/ton on Kiln 4 based on a 30-day 

rolling average basis.140 We propose to 

find that this emissions limit, equivalent 

to SNCR control, is cost-effective at 

$1,142/ton and would result in 

significant visibility benefits at 

Sycamore Canyon Wilderness Area. We 

are proposing to require compliance 

with the 2.12 lb/ton limit by December 

31, 2018. 

We are also soliciting comment on the 

possibility of establishing an annual cap 

on NOX emissions from Kiln 4 in lieu 

of a lb/ton emission limit. Such a cap 

would provide additional flexibility to 

PCC by allowing them to comply either 

by installing controls or by limiting 

production. In particular, we are seeking 

comment on an annual NOX emission 

cap for Kiln 4 of 810 tpy established on 

a rolling 12-month basis, effective 

December 31, 2018. If production 

remains at current levels, PCC could 

meet this cap without installing any 

additional controls. However, if 

production increases to pre-2008 levels, 

we expect that PCC would need to 

install SNCR on Kiln 4 to comply with 

the cap. 

b. CalPortland Cement Rillito Plant 

Kilns 1–4 

The facility consists of three long dry 

kilns (Kilns 1–3) and one precalciner 

kiln (Kiln 4). Due to the significant 

differences between long dry kilns and 

precalciner kilns, we have separately 

analyzed Kilns 1–3 and Kiln 4. 

1. Rillito Plant Kilns 1–3 

Kilns 1–3 have not operated since 

2008 due to economic conditions. 

However, CPCC retains the ability to 

start using these kilns again at any time. 

Therefore, we conducted an analysis of 

the kilns using pre-2008 emission 

levels. 

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141 ‘‘Reasonable Progress Analysis for CalPortland 

Company Rillito Cement Plant Kiln, prepared by 

CalPortland Company.’’ Submitted to EPA May 9, 

2013. 

142See TSD for an analysis of all control options 

and associated control efficiencies and control 

costs. 

143See Arizona RH SIP supplement, page 32. 

144 ‘‘Reasonable Progress Analysis for CalPortland 

Company Rillito Cement Plant Kiln, prepared by 

CalPortland Company.’’ Submitted to EPA May 9, 

2013. 

Costs of Compliance: Our estimate of 

the costs of compliance is based 

primarily on estimates provided by 

CalPortland in its RP analysis, with 

revisions to certain cost items we 

considered to be unreasonable or not 

allowed by EPA’s Control Cost 

Manual.141 Our analysis identified 

SNCR with Mixing Air Technology 

(MAT) as the most cost-effective control 

technology. Installation of SNCR with 

MAT on Kilns 1–3 is estimated to 

reduce emissions at each kiln by 182 tpy 

at a cost of $5,603/ton reduced, based 

on an annualized cost of approximately 

$1 million per year and 30-percent 

control efficiency for SNCR.142

Time Necessary for Compliance: 

CPCC estimates that the time needed to 

install the control equipment is about 3 

years. 

Energy and Non-Air Quality 

Environmental Impacts of Compliance: 

The installation and operation of SNCR 

at the plant would require a small 

increase in energy usage. The cost of 

this additional energy usage is included 

in the cost analysis. Non-air quality 

environmental impacts associated with 

SNCR include the hazards of 

transporting and storing urea or 

ammonia, especially if anhydrous 

ammonia is used. However, since the 

handling of anhydrous ammonia will 

involve the development of an RMP, we 

consider the associated safety issues to 

be manageable as long as established 

safety procedures are followed. 

Therefore, we find that these impacts 

are not sufficient to warrant eliminating 

SNCR as a control option. 

Remaining Useful Life: The plant’s 

owner intends to shut down all four 

kilns and replace them with a new kiln 

that would be subject to Best Available 

Control Technology and a visibility 

impact analysis.143 This project has 

been on hold while the economy in 

Arizona recovers. As a result, it is 

unclear whether these kilns will be in 

service long enough to fully amortize 

the cost of controls. However, because 

there is no enforceable shutdown date at 

this time, we assume that the kilns will 

remain in service for a 20-year 

amortization period. 

Degree of Improvement in Visibility: 

The maximum visibility improvement 

due to SNCR on Kilns 1–3 is 0.22 dv at 

the eastern unit of Saguaro NP, 0.18 dv 

at Galiuro WA, and smaller for other 

areas. The cumulative visibility 

improvement is 0.7 dv. 

TABLE 43—CALPORTLAND CEMENT KILNS 1–3 AND KILN 4: VISIBILITY IMPACT AND IMPROVEMENT FROM NOX CONTROLS

Class I area Distance 

(km) 

Visibility 

impact 

Visibility 

improvement 

Base case 

(c0) 

SNCR on 

Kilns 1, 2, 3 

(c22) 

SNCR on 

Kiln 4 

(c24) 

Chiricahua NM ........................................................................................................... 171 0 .25 0 .05 0 .06 

Chiricahua WA ........................................................................................................... 170 0 .23 0 .05 0 .05 

Galiuro WA ................................................................................................................ 73 1 .02 0 .18 0 .19 

Gila WA ...................................................................................................................... 240 0 .12 0 .02 0 .03 

Mazatzal WA .............................................................................................................. 171 0 .13 0 .02 0 .03 

Mount Baldy WA ........................................................................................................ 223 0 .11 0 .03 0 .03 

Petrified Forest NP .................................................................................................... 290 0 .11 0 .02 0 .03 

Pine Mountain WA ..................................................................................................... 213 0 .11 0 .02 0 .02 

Saguaro NP ............................................................................................................... 8 1 .26 0 .22 0 .24 

Sierra Ancha WA ....................................................................................................... 153 0 .13 0 .02 0 .03 

Superstition WA ......................................................................................................... 108 0 .30 0 .06 0 .06 

Sycamore Canyon WA .............................................................................................. 287 0 .09 0 .02 0 .02 

Cumulative (sum) ....................................................................................................... .................... 3 .9 0 .7 0 .8 

Maximum ................................................................................................................... .................... 1 .26 0 .22 0 .24 

# CIAs >= 0.5 dv ....................................................................................................... .................... 2 0 0 

Million $/dv (cumul. dv) .............................................................................................. .................... ...................... $1 .5 $1 .4 

Million $/dv (max. dv) ................................................................................................ .................... ...................... $4 .8 $4 .6 

The Saguaro NP results in this table are for the eastern unit of the park only. 

Proposed RP Determination: Given 

the lack of emissions from Kilns 1–3 

over the last five years and the relatively 

high cost of controls ($5,603/ton), EPA 

proposes to find that requiring controls 

for these units is not reasonable at this 

time. 

2. Rillito Plant Kiln 4 

Costs of Compliance: Our estimate of 

the costs of compliance is based 

primarily on estimates provided by 

CalPortland in its RP analysis, with 

revisions to certain cost items we 

considered to be unreasonable or not 

allowed by EPA’s Control Cost 

Manual.144 Our analysis identified the 

addition of SNCR to the existing LNB as 

the most cost-effective available control 

technology. As explained in further 

detail in the TSD, we estimated a total 

annual cost for SNCR of approximately 

$1.1 million per year. SNCR is estimated 

to reduce emissions by 1,041 tpy at a 

cost of $1,047/ton reduced, based on 

baseline emissions of 2,082 tons per 

year and a 50 percent SNCR controlefficiency. As explained in the TSD, we 

are seeking comment on whether a 

different SNCR control efficiency is 

appropriate for Kiln 4. If we receive 

technical information demonstrating 

that a different SNCR control efficiency 

is appropriate for Kiln 4, we will 

incorporate this change into our 

analysis. 

Energy and Non-Air Quality 

Environmental Impacts of Compliance: 

The installation and operation of SNCR 

at the plant would require a small 

increase in energy usage. The cost of 

this additional energy usage is included 

in the cost analysis. Non-air quality 

environmental impacts associated with 

SNCR include the hazards of 

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9356 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules 

145See Arizona RH SIP supplement, page 32. 146See TSD for a discussion of how this emission 

limit was calculated. 

transporting and storing urea or 

ammonia, especially if anhydrous 

ammonia is used. However, since the 

handling of anhydrous ammonia will 

involve the development of an RMP, we 

consider the associated safety issues to 

be manageable as long as established 

safety procedures are followed. 

Therefore, we find that these impacts 

are not sufficient to warrant eliminating 

SNCR as a control option. 

Existing Pollution Control Equipment: 

Kiln 4 is a precalciner kiln that 

currently uses LNB for NOX control. 

Remaining Useful Life: The plant’s 

owner intends to shut down all four 

kilns and replace them with a new kiln 

that would be subject to Best Available 

Control Technology and a visibility 

impact analysis.145 This project has 

been on hold while the economy in 

Arizona recovers. As a result, it is 

unclear whether these kilns will be in 

service long enough to fully amortize 

the cost of controls. However, because 

there is no enforceable shutdown date at 

this time, we assume that the kilns will 

remain in service for a 20-year 

amortization period. 

Degree of Improvement in Visibility: 

As shown in Table 43, the maximum 

visibility improvement due to SNCR on 

Kiln 4 is 0.24 dv at the eastern unit of 

Saguaro NP, 0.19 dv at Galiuro WA, and 

smaller for other areas. The cumulative 

visibility improvement is 0.8 dv. The 

cumulative visibility improvement from 

SNCR on all four kilns would be about 

1.5 dv. 

As discussed above in the section 

covering visibility improvements for 

TEP Sundt, EPA remodeled impacts at 

Saguaro NP to address both the eastern 

and western units of the park. The 

modeled visibility impact at the western 

unit of Saguaro, not shown in the table, 

is 6.04 dv, far greater than at the eastern 

unit. The modeled improvement there 

due to SNCR is 0.30 dv, still rather 

modest but 25 percent greater than for 

the eastern unit. However, CalPortland 

is only 7.8 km away from the western 

unit, so its emitted NOX may not be 

fully converted to NO2 by the time it 

reaches there, as is assumed in the 

CALPUFF model. It thus may not be 

fully available to form visibilitydegrading particulate nitrate. EPA 

explored this issue by scaling back the 

visibility extinction due to NO2 and 

nitrate to reflect lower NO-to-NO2

conversion rates, described further in 

the TSD. EPA found that visibility 

impacts and the improvement due to 

SNCR decrease along with the percent 

conversion assumed, so much so that at 

a 25 percent conversion rate, the SNCR 

benefit was only 0.05 dv. Therefore, 

EPA is relying on impacts and 

improvements for the more distant 

eastern unit of Saguaro NP. 

Proposed RP Determination: EPA 

finds that SNCR is cost-effective for Kiln 

4 at $1,047/ton, would not result in 

undue non-air quality environmental 

impacts, and would result in modest 

visibility benefits at Saguaro NP and 

Galiuro WA. Therefore, we propose to 

determine that it is reasonable to require 

SNCR at Kiln 4. In particular, EPA 

proposes to require compliance with an 

emissions limit of 2.67 lb/ton at Kiln 4 

based on a 30-day rolling average by 

December 31, 2018.146 We are also 

soliciting comment on the possibility of 

requiring an annual cap on NOX

emissions in lieu of a lb/ton emission 

limit. In order to avoid a shift in 

production from Kiln 4 to Kilns 1–3, we 

are proposing that the cap would apply 

to all four kilns. In particular, we are 

seeking comment on an annual NOX

emission cap for Kilns 1–4 of 2,082 tpy, 

established on a rolling 12-month basis. 

CPCC could meet this cap either by 

retaining production at current levels, or 

by increasing production and installing 

SNCR on Kiln 4. We are proposing to 

require compliance with this rolling 12- 

month limit by December 31, 2018. 

c. APS Cholla Unit 1 

Costs of Compliance: Unit 1 is a 1,246 

MMBtu/hr tangential coal-fired boiler, 

which currently employs LNB with 

separated overfire air (SOFA) for NOX

control. EPA identified two feasible 

additional controls: SNCR and SCR. The 

estimated emission reductions and costs 

for these two options are summarized in 

Tables 44 and 45. 

TABLE 44—CHOLLA UNIT 1: NOX EMISSION ESTIMATES

Control option 

NOX

emissions 

Emission 

reduction 

(lb/MMBtu) (lb/hr) (tpy) (tpy) 

Baseline (LNB+OFA) ....................................................................................... 0.22 274 1,032 

SNCR ............................................................................................................... 0.15 192 723 310 

SCR ................................................................................................................. 0.05 62 235 798 

TABLE 45—CHOLLA UNIT 1: NOX CONTROL COST ESTIMATES

Control option 

Total capital 

cost 

Annualized 

capital cost 

Annual O&M 

costs 

Total annual 

cost 

Cost-effectiveness 

($/ton) 

($) ($) ($) ($) Ave Incr 

Baseline (LNB+OFA) 

SNCR ....................................................... $2,272,000 $241,725 $918,875 $1,160,599 $3,748 

SCR .......................................................... 26,437,190 2,812,730 1,425,137 4,237,867 5,313 $6,307 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules 9357 

147Typical Installation Timelines for NOX

Emissions Control Technologies on Industrial 

Sources, Institute of Clean Air Companies, 

December 4, 2006. 

148See 77 FR 42834 at 42865 for more details. 

149See spreadsheet ‘‘Non EGU_RP_Ch5.xlsx’’ in 

the docket. 

150Typical Installation Timelines for NOX

Emissions Control Technologies on Industrial 

Sources, Institute of Clean Air Companies, 

December 4, 2006. 

Time Necessary for Compliance: 

Given the estimate from the Institute of 

Clean Air Companies147 that about a 

year is required to install SNCR, and the 

estimate of three years for installing 

SNCR on a cement kiln discussed 

previously in this notice, EPA estimates 

that SNCR could be installed in less 

than three years. In our previous 

Arizona FIP action, EPA estimated that 

5 years would be required to install SCR 

on coal-fired boilers.148 That estimate 

also holds for this source. 

Energy and Non-Air Quality 

Environmental Impacts of Compliance: 

SCR and SNCR can result in additional 

ammonia emissions. There is also 

increased truck traffic bringing the 

reagent on site. SCR will also slightly 

reduce the efficiency of the plant, 

resulting in increased fuel usage. 

Remaining Useful Life: EPA assumes 

that this plant would continue operating 

for 20 years and fully amortize the cost 

of controls. 

Degree of Improvement in Visibility: 

CALPUFF modeling indicates that 

installation of SNCR at Unit 1 would 

provide a 0.10 dv visibility benefit at the 

most affected Class I area, Petrified 

Forest NP, while installation of SCR 

would provide a 0.20 dv benefit at the 

same area as shown in Table 46. Note 

that all of these results, including the 

base case, assume that SCR has been 

applied to Units 2, 3 and 4, consistent 

with EPA’s previous BART 

determination for those units. 

TABLE 46—CHOLLA UNIT 1: VISIBILITY IMPACT AND IMPROVEMENT FROM NOX CONTROLS

Class I area Distance 

(km) 

Visibility 

impact 

Visibility improvement 

from control 

Base case 

(ctrl0/ctrl2_r2) 

SNCR on 

Unit 1 

(ctrl2–1) 

SCR on 

Unit 1 

(ctrl2–2) 

Capitol Reef NP ......................................................................................................... 300 0 .71 0 .04 0 .09 

Galiuro WA ................................................................................................................ 249 0.30 0 .01 0 .01 

Gila WA ...................................................................................................................... 222 0 .48 0 .01 0 .01 

Grand Canyon NP ..................................................................................................... 179 1 .14 0 .05 0 .12 

Mazatzal WA .............................................................................................................. 128 0 .79 0 .02 0 .04 

Mesa Verde NP ......................................................................................................... 292 0 .65 0 .03 0 .06 

Mount Baldy WA ........................................................................................................ 128 0 .71 0 .01 0 .02 

Petrified Forest NP .................................................................................................... 39 3 .38 0 .10 0 .20 

Pine Mountain WA ..................................................................................................... 149 0 .55 0 .01 0 .03 

Saguaro NP ............................................................................................................... 300 0 .23 0 .00 0 .00 

Sierra Ancha WA ....................................................................................................... 126 0 .87 0 .02 0 .06 

Superstition WA ......................................................................................................... 166 0 .81 0 .03 0 .06 

Sycamore Canyon WA .............................................................................................. 147 0 .76 0 .03 0 .07 

Cumulative (sum) ....................................................................................................... .................... 11 .4 0 .3 0 .7 

Maximum ................................................................................................................... .................... 3 .38 0 .10 0 .20 

# CIAs >= 0.5 dv ....................................................................................................... .................... 10 0 0 

Million $/dv (cumul. dv) .............................................................................................. .................... ...................... $3 .0 $5 .7 

Million $/dv (max. dv) ................................................................................................ .................... ...................... $10 .3 $21 .7 

Proposed Determination: EPA 

proposes to determine that it is not 

reasonable to require additional controls 

on this facility at this time. The costs for 

both SNCR and SCR are relatively high 

in light of the relatively small 

anticipated visibility benefits of the 

controls. However, this decision should 

be revisited in future planning periods. 

d. El Paso Natural Gas Company’s 

Tucson Compressor Station 

Costs of Compliance: This site 

includes seventeen 1,071 hp compressor 

engines. EPA’s analysis indicates that 

the most cost-effective control would be 

an air/fuel ratio controller that would 

reduce emissions by 578 tpy at a cost of 

$792/ton.149

The site also includes four 370 hp 

engines. EPA’s analysis indicates that 

the most cost-effective control would be 

a three-way catalyst that would reduce 

emissions by 96 tons per year at a cost 

of $290/ton. 

Time Necessary for Compliance: The 

Institute of Clean Air Companies 

estimates that 8 to 14 weeks would be 

required to install these kinds of 

controls.150

Energy and Non-Air Quality 

Environmental Impacts of Compliance: 

Both controls may increase fuel usage 

by reducing the thermal efficiency of the 

engines. 

Remaining Useful Life: EPA assumes 

that the engines would continue 

operating for 20 years and fully amortize 

the cost of controls. 

Proposed Determination: EPA 

proposes to find that it is not reasonable 

to require additional controls on this 

facility at this time. Natural gas engines 

similar to those at the Tucson 

Compressor Station are found in various 

locations throughout Arizona. EPA’s 

assessment indicates that a state-wide or 

regional approach to controlling this 

source category could result in 

significant emissions reductions. Given 

the dispersed nature of these engines, it 

is not practical for EPA to control these 

sources. Therefore, EPA proposes to 

find that it is not reasonable to require 

additional controls on this particular 

source at this time. This source category 

should be given serious consideration 

for future planning periods, as it would 

be more appropriately controlled by the 

State. 

e. El Paso Natural Gas Company’s 

Flagstaff Compressor Station 

Costs of Compliance: This site 

includes two 5,500 hp compressor 

engines. EPA’s analysis indicates that 

the most cost-effective control would be 

an air/fuel ratio controller that would 

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9358 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules 

151See spreadsheet ‘‘Non EGU_RP_Ch5.xlsx’’ in 

the docket. 

152Typical Installation Timelines for NOX

Emissions Control Technologies on Industrial 

Sources, Institute of Clean Air Companies, 

December 4, 2006. 

153Typical Installation Timelines for NOX

Emissions Control Technologies on Industrial 

Sources, Institute of Clean Air Companies, 

December 4, 2006. 154Technical Analysis for Arizona and Hawaii 

Regional Haze FIPs: Task 9: Five-Factor RP 

Analyses for TEP Springerville, APS Cholla, TEP 

Sundt, CalPortland Cement and Phoenix Cement 

Plants, Contract No. EP–D–07–102, Work 

Assignment 5–12; Prepared for EPA Region 9 by 

University of North Carolina at Chapel Hill, ICF 

International, and Andover Technology Partners; 

October 3, 2012, Table 20. 

reduce emissions by 398 tpy at a cost of 

$432/ton.151

Time Necessary for Compliance: The 

Institute of Clean Air Companies 

estimates that 8 to 14 weeks would be 

required to install these kinds of 

controls.152

Energy and Non-Air Quality 

Environmental Impacts of Compliance: 

The controls may increase fuel usage by 

reducing the thermal efficiency of the 

engines. 

Remaining Useful Life: EPA assumes 

that the engines would continue 

operating for 20 years and fully amortize 

the cost of controls. 

Proposed RP Determination: EPA 

proposes to find that it is not reasonable 

to require additional controls on this 

facility at this time. Natural gas engines 

similar to those comprising the Flagstaff 

Compressor Station are found in various 

locations throughout Arizona. EPA’s 

assessment indicates that a state-wide or 

regional approach to controlling this 

source category could result in 

significant emissions reductions. Given 

the dispersed nature of these engines, 

many of which may fall into the area 

source category discussed above, it is 

not practical for EPA to control these 

sources. Therefore, EPA proposes to 

find that it is not reasonable to require 

additional controls on this particular 

source at this time. This source category 

should be given serious consideration 

for future planning periods. 

f. Tucson Electric Power Sundt Station 

(Units 1–3) 

Costs of Compliance: TEP Sundt has 

three natural gas-fired boilers rated at 

approximately 1,220 MMBTU/hr each. 

EPA’s analysis indicates that the most 

cost-effective control would be ultra-low 

NOX burners (ULNB). This retrofit 

would reduce emissions from Unit 1 by 

46 tpy at a cost of $8,300/ton. It would 

reduce emissions from Unit 2 by 55 tpy 

at a cost of $7,000/ton. The retrofit 

would reduce emissions from Unit 3 by 

90 tpy at a cost of $4,400/ton. As shown 

in Table 47, modeling indicates that 

these controls would provide a 0.40 dv 

visibility benefit at the most improved 

Class I area. 

Time Necessary for Compliance: The 

Institute of Clean Air Companies 

estimates that 6 to 8 months would be 

required to install these kinds of 

controls.153

Energy and Non-Air Quality 

Environmental Impacts of Compliance: 

The ultra-low-NOX burners may reduce 

the thermodynamic efficiency of the 

boilers and require an increase in fuel 

consumption. 

Remaining Useful Life: EPA assumes 

that the boilers would continue 

operating for 20 years and fully amortize 

the cost of controls. 

Proposed RP Determination: EPA 

proposes to find that it is not reasonable 

to require additional controls on this 

facility at this time. As noted above, 

ULNB has cost-effectiveness values for 

Sundt Units 1–3 in the range of $4,000 

to 7,000 per ton. These costs are 

relatively high in light of the anticipated 

visibility benefits of the controls. 

However, this decision should be 

revisited in future planning periods, 

particularly if these units operate at a 

higher capacity factor in the future. 

Degree of Improvement in Visibility: 

Modeling indicates that installation of 

ULNB on all three units would provide 

a 0.40 dv visibility benefit at the most 

improved Class I area, Saguaro National 

Park, as shown in Table 47. Note that all 

of these results assume that SNCR has 

been applied to Sundt Unit 4, consistent 

with EPA’s previous BART 

determination for that unit. The 

visibility cost-effectiveness values are 

based on an annualized cost of $1.2 

million per year, based on the analysis 

by UNC, contractor to EPA.154

TABLE 47—SUNDT UNIT 1, 2 AND 3: VISIBILITY IMPACT AND IMPROVEMENT FROM NOX CONTROLS

Class I area Distance 

(km) 

Visibility 

impact 

Visibility 

improvement 

from control 

Base case 

(SNCR on 

Unit 4) 

ULNB 

Chiricahua NM ..................................................................................................................................... 144 0 .43 0 .08 

Chiricahua WA ..................................................................................................................................... 141 0 .51 0 .07 

Galiuro WA .......................................................................................................................................... 64 1 .10 0 .22 

Gila WA ................................................................................................................................................ 232 0 .17 0 .02 

Mazatzal WA ........................................................................................................................................ 203 0 .19 0 .02 

Mount Baldy WA .................................................................................................................................. 232 0 .15 0 .02 

Pine Mountain WA ............................................................................................................................... 247 0 .15 0 .01 

Saguaro NP ......................................................................................................................................... 17 3 .40 0 .40 

Sierra Ancha WA ................................................................................................................................. 178 0 .19 0 .02 

Superstition WA ................................................................................................................................... 137 0 .32 0 .04 

Cumulative (sum) ................................................................................................................................. .................... 6 .6 0 .9 

Maximum ............................................................................................................................................. .................... 3 .40 0 .40 

# CIAs >= 0.5 dv ................................................................................................................................. .................... 3 0 

Million $/dv (cumul. dv) ........................................................................................................................ .................... ...................... $1 .3 

Million $/dv (max. dv) .......................................................................................................................... .................... ...................... $2 .9 

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Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules 9359 

155See spreadsheet ‘‘Non EGU_RP_Ch5.xlsx’’ in 

the docket. 

156Typical Installation Timelines for NOX

Emissions Control Technologies on Industrial 

Sources, Institute of Clean Air Companies, 

December 4, 2006. 

157Typical Installation Timelines for NOX

Emissions Control Technologies on Industrial 

Sources, Institute of Clean Air Companies, 

December 4, 2006. 

158See 77 FR 42834 at 42865 for more details. 

g. Ina Road Sewage Plant 

Costs of Compliance: This site has 

seven 1,000 hp natural gas-fired internal 

combustion engines. EPA’s analysis 

indicates that the most cost-effective 

control is non-selective catalytic 

reduction (NSCR). Installation of this 

control would reduce emissions by 

1,029 tpy at a cost of $210/ton.155

Time Necessary for Compliance: The 

Institute of Clean Air Companies 

estimates that 8 to 14 weeks would be 

required to install these kinds of 

controls.156

Energy and Non-Air Quality 

Environmental Impacts of Compliance: 

The control measure may decrease the 

thermodynamic efficiency of the 

engines and increase fuel usage. 

Remaining Useful Life: EPA assumes 

that the engines would continue 

operating for 20 years and fully amortize 

the cost of controls. 

Proposed RP Determination: EPA 

proposes to find that it is not reasonable 

to require additional controls on this 

facility at this time. Natural gas engines 

similar to those at the Ina Road Sewage 

Plant are found in many locations 

throughout Arizona. EPA’s assessment 

indicates that a state-wide or regional 

approach to controlling this source 

category could result in significant 

emissions reductions. Given the 

dispersed nature of these engines, many 

of which may fall into the area source 

category discussed above, it is not 

practical for EPA to control these 

sources. Therefore, EPA proposes to 

find that it is not reasonable to require 

additional controls on this particular 

source at this time. This source category 

should be given serious consideration 

for future planning periods, as it would 

be more appropriately controlled by the 

State. 

h. Tucson Electric Power Springerville 

Plant 

Costs of Compliance: TEP 

Springerville Plant Units 1 and 2 are 

4,700 MMBtu/hr tangential coal-fired 

boilers, which currently employ LNB 

with OFA for NOX control. EPA 

identified two feasible additional 

controls: SNCR and SCR. The estimated 

emission reductions and costs for these 

two options are summarized in Tables 

48 and 49. 

TABLE 48—TEP SPRINGERVILLE 1 AND 2: NOX EMISSION ESTIMATES

Control option 

NOX emissions Emission 

reduction 

lb/MMBtu lb/hr tpy tpy 

Springerville 1: 

Baseline (LNB+OFA) ................................................................................ 0.18 769 2,189 

SNCR ........................................................................................................ 0.13 538 1532 657 

SCR .......................................................................................................... 0.05 212 605 1,584

Springerville 2: 

Baseline (LNB+OFA) ................................................................................ 0.19 798 2,448 

SNCR ........................................................................................................ 0.13 559 1714 734 

SCR .......................................................................................................... 0.05 210 644 1,804

TABLE 49—TEP SPRINGERVILLE 1 AND 2: NOX CONTROL COST ESTIMATES

Control option 

Total capital 

cost 

Annualized 

capital cost 

Annual O&M 

costs 

Total annual 

cost 

Cost-effectiveness 

($/ton) 

$ $/yr $/yr $/yr Ave Incr 

Springerville 1: 

Baseline (LNB+OFA) 

SNCR ................................................ $8,496,000 $903,914 $1,933,059 $2,836,973 $4,320 

SCR .................................................. 71,796,257 7,638,614 3,181,809 10,820,423 6,829 $8,606 

Springerville 2: 

Baseline (LNB+OFA) 

SNCR ................................................ 8,496,000 903,914 2,141,291 3,045,205 4,146 

SCR .................................................. 71,402,351 7,596,705 3,379,514 10,976,219 6,085 7,416 

Time Necessary for Compliance: 

Given the estimate from the Institute of 

Clean Air Companies 157 that 

approximately a year is required to 

install SNCR and the estimate of three 

years for installing SNCR on a cement 

kiln discussed previously in this notice. 

EPA estimates that SNCR could be 

installed in less than three years. In our 

previous Arizona FIP action, EPA 

estimated that 5 years would be 

required to install SCR on coal-fired 

boilers.158 That estimate also holds for 

this source. 

Energy and Non-Air Quality 

Environmental Impacts of Compliance: 

SCR and SNCR can result in additional 

ammonia emissions. There is also 

increased truck traffic bringing the 

reagent on site. SCR will also slightly 

reduce the efficiency of the plant, 

resulting in increased fuel usage. 

Remaining Useful Life: EPA assumes 

that this plant would continue operating 

for 20 years and fully amortize the cost 

of controls. 

Degree of Improvement in Visibility: 

As shown in Table 50, CALPUFF 

modeling indicates that SNCR at Units 

1 and 2 would provide a 0.18 dv 

visibility benefit at the most affected 

Class I area and a cumulative 0.8 dv 

benefit across all affected areas. SCR 

would provide a 0.41 dv benefit at the 

most affected Class I area and 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

9360 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules 

159See spreadsheet ‘‘Non EGU_RP_Ch5.xlsx’’ in 

the docket. 

160Typical Installation Timelines for NOX

Emissions Control Technologies on Industrial 

Sources, Institute of Clean Air Companies, 

December 4, 2006. 

cumulative 1.7 dv across all affected 

areas. 

TABLE 50—SPRINGERVILLE UNITS 1 & 2: VISIBILITY IMPACT AND IMPROVEMENT FROM NOX CONTROLS

Class I area Distance 

(km) 

Impact Improvement from control 

Base case SNC 

(ctrl-1) 

SCR 

(ctrl-2) 

Bandelier NM ............................................................................................. 298 1 .08 0 .07 0 .13 

Chiricahua NM ........................................................................................... 253 0 .85 0 .07 0 .14 

Chiricahua WA ........................................................................................... 264 0 .88 0 .00 0 .01 

Galiuro WA ................................................................................................ 211 0 .95 0 .03 0 .08 

Gila WA ...................................................................................................... 111 4 .39 0 .18 0 .41 

Grand Canyon NP ..................................................................................... 302 0 .79 0 .07 0 .07 

Mazatzal WA .............................................................................................. 209 0 .86 0 .01 0 .01 

Mount Baldy WA ........................................................................................ 51 3 .63 0 .13 0 .32 

Petrified Forest NP .................................................................................... 79 2 .46 0 .06 0 .09 

Pine Mountain WA ..................................................................................... 236 0 .67 0 .02 0 .06 

Saguaro NP ............................................................................................... 263 0 .57 0 .01 0 .04 

San Pedro Parks WA ................................................................................ 281 1 .53 0 .05 0 .23 

Sierra Ancha WA ....................................................................................... 165 1 .01 0 .02 0 .05 

Superstition WA ......................................................................................... 194 0 .52 0 .03 0 .06 

Sycamore Canyon WA .............................................................................. 263 0 .65 0 .02 0 .04 

Cumulative (sum) ....................................................................................... ........................ 20 .8 0 .8 1 .7 

Maximum ................................................................................................... ........................ 4 .39 0 .18 0 .41 

# CIAs >= 0.5 dv ....................................................................................... ........................ 15 0 0 

Million $/dv (cumul. dv) .............................................................................. ........................ .......................... $7 .3 $12 .6 

Million $/dv (max. dv) ................................................................................ ........................ .......................... $32 .2 $53 .4 

Proposed RP Determination: EPA 

proposes to determine that it is not 

reasonable to require additional controls 

at Springerville Units 1 and 2 at this 

time. While the cost per ton for SNCR 

may be reasonable, the projected 

visibility benefits are relatively small 

(0.18 dv at the most affected area). The 

projected visibility benefits of SCR are 

larger (0.41 dv at the most affected area), 

but we do not consider them sufficient 

to warrant the relatively high cost of 

controls for purposes of RP in this 

planning period. However, these units 

should be considered for additional 

NOX controls in future planning 

periods. 

i. El Paso Natural Gas Williams 

Compressor Station 

Costs of Compliance: This site 

consists of five 2,500 hp engines, one 

3,400 hp engine, and one 32,200 hp gas 

turbine. EPA’s analysis indicates that 

air/fuel ratio controllers are the most 

cost-effective controls for the five 2,500 

hp engines and would reduce emissions 

by 288 tpy at a cost of $547/ton. Our 

analysis indicates that an air/fuel ratio 

controller is also the most cost-effective 

control for the 3,400 hp engine and 

would reduce emissions from that 

engine by 131 tpy at a cost of $444/ton. 

Our analysis further indicates that water 

injection would be the most costeffective control for the gas turbine and 

would reduce emissions from that 

engine by 505 tpy at a cost of $854/

ton.159

Time Necessary for Compliance: The 

Institute of Clean Air Companies 

estimates that 8 to 14 weeks would be 

required to install these kinds of 

controls.160

Energy and Non-Air Quality 

Environmental Impacts of Compliance: 

These controls may increase fuel usage 

by reducing the thermal efficiency of the 

engines. 

Remaining Useful Life: EPA assumes 

that the engines would continue 

operating for 20 years and fully amortize 

the cost of controls. 

Proposed RP Determination: EPA 

proposes to find that it is not reasonable 

to require additional controls on this 

facility at this time. Natural gas engines 

similar to those comprising the 

Williams Compressor Station are found 

in various locations throughout Arizona. 

EPA’s assessment indicates that a statewide or regional approach to controlling 

this source could result in significant 

emissions reductions. Given the 

dispersed nature of these engines, many 

of which may fall into the area source 

category discussed above, it is not 

practical for EPA to control these 

sources. Therefore, EPA proposes to 

find that it is not reasonable to require 

additional controls on this particular 

source at this time. This source category 

should be given serious consideration 

for future planning periods, as it would 

be more appropriately controlled by the 

State. 

B. Reasonable Progress Analysis of Area 

Sources for NOX and SO2

1. Identification of Area Sources for 

NOX and SO2. 

The initial step in our area source RP 

analysis was the identification of 

specific SO2 and NOX area source 

categories to evaluate for potential 

controls. To that end, we examined data 

from the 2008 National Emissions 

Inventory (NEI) to determine the most 

significant area sources of SO2 and NOX. 

This analysis is described in the TSD, 

and the results are summarized in 

Tables 51 and 52. As discussed in the 

TSD, there are significant uncertainties 

in the area source emissions inventory 

for Arizona. In spite of the uncertainty, 

it is evident that the primary area source 

categories of most concern are Industrial 

and Commercial Boilers and Internal 

Combustion Engines burning distillate 

fuel oil. A third category, Residential 

Natural Gas Combustion, also comprises 

a significant portion of NOX emissions. 

EPA has therefore identified these 

categories as ‘‘potentially affected 

sources.’’ EPA proposes to find that the 

remaining source categories comprise 

too small of a percentage contribution to 

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Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules 9361 

161 ‘‘Supplementary Information for Four Factor 

Analyses by WRAP States,’’ EC/R Incorporated, 

corrected version, April 20, 2010. 

162 ‘‘AirControlNet, Version 4.1,’’ May 2006, E.H. 

Pechan and Associates. 

163See spreadsheet titled ‘‘AZ FIP Cost Analysis_

for Greg Nudd Rg 9_2013–08–13.xls’’. 

overall emissions to justify consideration for additional controls in 

this initial planning period. 

TABLE 51—SIGNIFICANT AREA SOURCES OF NOX IN ARIZONA

Source type Source classification code 

Tons per year 

(2008) 

Portion of total 

area source 

emissions 

(%) 

Cumulative 

portion 

(%) 

Industrial Boilers and Internal Combustion Engines (burning distillate 

fuel oil) .................................................................................................... 2102004000 2,300 29.3 29.3 

Residential Natural Gas Combustion ........................................................ 2104006000 1,645 .7 20.2 49.5 

Industrial Natural Gas Combustion ........................................................... 2102006000 765 .4 9.4 58.8 

Open Burning, Land Clearing Debris ........................................................ ............................ 727 .0 8.9 67.7 

TABLE 52—SIGNIFICANT AREA SOURCES OF SO2 IN ARIZONA

Source type Source classification code 

Tons per year 

(2008) 

Portion of total 

area source 

emissions 

(%) 

Cumulative 

portion 

(%) 

Industrial Boilers and Internal Combustion Engines (burning distillate fuel 

oil) ............................................................................................................. 2102004000 1652.1 65.3 65.3 

Commercial and Institutional Boilers and Internal Combustion Engines 

(burning distillate fuel oil) ......................................................................... 2103004000 483.5 19.1 84.5 

Industrial processes not elsewhere classified ............................................. 2399000000 110.4 4.4 88.8 

2. Analysis of Significant Area Source 

Categories 

a. Approach to Area Source Analysis 

In conducting an RP analysis for area 

source, EPA encountered significant 

limitations on the availability and 

accuracy of data concerning the relevant 

source categories. For purposes of 

emission inventory development, an 

area source is not a single facility, but 

a category of polluting sources known to 

exist within a certain geographic area 

(such as a county), whose actual 

number, age, and design is not known. 

The emissions from area sources are 

usually estimated based on a ‘‘topdown’’ method, where a surrogate piece 

of information, such as the number of 

people living in a county or the gallons 

of diesel fuel sold there in a given year, 

is used to estimate emissions. Each of 

the source categories analyzed has an 

emissions estimate derived from 

Federal, state, or local databases of fuel 

consumption. In the aggregate, these 

numbers are sufficiently accurate for 

most analyses. However, they do not 

provide adequate detail for EPA to 

precisely estimate the actual costs and 

benefits of controlling the existing 

population of sources. 

Given these limitations in available 

data, EPA’s analyses of area sources are 

limited in scope. For each category we 

have developed ranges for the estimated 

cost of compliance and general 

information about each of the other 

factors, based largely on data from three 

sources: the WRAP Four-Factor 

Analysis report, 161 EPA’s Control 

Strategy Tool, and the documentation 

for EPA’s AirControlNet tool.162 The 

WRAP report lists several possible NOX

and SO2 controls for industrial boilers 

and internal combustion engines, 

depending on their size and pre-existing 

controls. The WRAP report also 

addresses the other mandatory factors 

for an RP analysis. The Control Strategy 

Tool is EPA’s most current tool for 

assessing the cost-effectiveness of 

control strategies for various source 

categories. EPA used this tool to confirm 

that the cost estimates in the WRAP 

report are still reasonable.163 We also 

consulted the AirControlNet 

documentation report that contains the 

most current data on the costeffectiveness of NOX controls for 

residential natural gas combustion. 

Finally, while we lacked sufficient data 

to conduct visibility modeling for 

particular categories of area sources, we 

have analyzed the overall contribution 

of area sources to nitrate and sulfatecaused visibility impairment in 

Arizona’s Class I areas in order to 

estimate the potential benefits of 

controls. The results of this analysis are 

provided below, following the results of 

the four-factor analyses for all of the 

source categories. 

b. RP Analysis of Industrial, 

Commercial, and Institutional Boilers 

Burning Distillate Fuel Oil 

Cost of Compliance: The estimated 

cost-effectiveness values for NOX

control options are: 

• LNB: $400–7,000/ton; 

• LNB/OFA: $400–7,000/ton; 

• SNCR: $400–6,900/ton; 

• SCR: $1,000–8,000/ton. 

The estimated cost-effectiveness 

values for SO2 control options for this 

category are: 

• DSI: $5,000–11,000/ton; 

• Wet FGD: $6,000–13,000/ton. 

Time Necessary for Compliance: 

Installation of the control devices, in 

most cases, should take no more than 2– 

3 years. The only possible exception 

may be for installation of SCR, which 

may take as long as 5 years. 

Energy and Non-Air Quality 

Environmental Impacts of Compliance: 

LNB may reduce combustion efficiency 

and slightly increase fuel consumption; 

SNCR and SCR would require some 

electricity use and environmental 

impacts from ammonia slip and 

transport and storage of the reagent. Wet 

FGD requires large quantities of water 

and requires disposal of wet ash. 

Remaining Useful Life: It is reasonable 

to assume that the units would remain 

in use long enough to fully recover the 

costs of controls. 

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164Both estimates from AirControlNet Manual p. 

III–90 and are in 1990 dollars. 

165 ‘‘Technical Support Document for Technical 

Products Prepared by the Western Regional Air 

Partnership (WRAP) in Support of Western 

Regional Haze Plans,’’ February 28, 2011. 

166See http://vista.cira.colostate.edu/tss/Results/

HazePlanning.aspx, select ‘‘Emissions and Source 

Apportionment’’ and the 2018 Base Case (base 18b) 

emissions scenario. 

167The Colorado Regional Haze SIP includes 

rules limiting emissions from certain Reciprocating 

Internal Combustion Engines. 77 FR 18052, 18089. 

However these rules are part of a State regulation 

intended to control ozone rather than regional haze. 

Colorado Air Quality Control Commission, 

Regulation Number 7, 5 CCR 1001–9, Control of 

Ozone via Ozone Precursors, Section XVII, 

Statewide Control for Oil and Gas Operations and 

Natural Gas-Fired Reciprocating Internal 

Combustion Engines, subsection E.3.a, (Regional 

Haze SIP) Rich Burn Reciprocating Internal 

Combustion Engines. 

c. RP Analysis of Industrial, 

Commercial, and Institutional Internal 

Combustion Engines Burning Distillate 

Fuel Oil 

Costs of Compliance: We estimate the 

following cost-effectiveness values for 

NOX control options: 

• Ignition timing retard: $1,000– 

2,200/ton; 

• Exhaust Gas Recirculation: $780– 

2,000/ton; 

• SCR: $3,000–7,700/ton; 

• Replacement with Tier 4 engines: 

$900–2,400/ton. 

We did not identify any technically 

feasible options for SO2 control other 

than lower sulfur fuel. 

Time Necessary for Compliance: 

Installation of the control devices, in 

most cases, should take no more than 2– 

3 years. The only possible exception 

may be for installation of SCR, which 

may take as long as 5 years. 

Energy and Non-Air Quality 

Environmental Impacts of Compliance: 

SCR would require some electricity use 

and there may also be environmental 

impacts from ammonia slip and 

transport and storage of the reagent. The 

other options would not have negative 

energy or non-air quality environmental 

impacts. 

Remaining Useful Life: It is reasonable 

to assume that the units would remain 

in use long enough to fully recover the 

costs of controls. 

d. RP Analysis of Residential Natural 

Gas Combustion 

Costs of Compliance: We estimate the 

following cost-effectiveness values for 

NOX control options: 

• Replace space heaters with Low 

NOX equivalent: $1,600/ton; 

• Replace water heaters with Low 

NOX equivalent: $1,230/ton.164

SO2 controls are not needed for this 

category due to low sulfur content of 

pipeline natural gas. 

Time Necessary for Compliance: 

Installation of the new devices, in most 

cases, should take no more than 2–3 

years. 

Energy and Non-Air Quality 

Environmental Impacts of Compliance: 

We did not identify any energy or nonair quality environmental impacts. 

Remaining Useful Life: This factor is 

not applicable for a unit replacement. 

Visibility Significance of Area 

Sources: As explained above, we do not 

have sufficient information to assess the 

likely visibility benefits of requiring 

controls on particular categories of area 

sources. However, in order to estimate 

the total potential visibility benefits that 

might result from controlling NOX and 

SO2 emissions from area sources, we 

have analyzed the overall contribution 

of area sources to nitrate- or sulfatecaused visibility impairment in 

Arizona’s Class I areas. The relative 

contribution can be estimated by 

reviewing the results of the Particulate 

Source Apportionment Technology 

(PSAT) modeling conducted by the 

WRAP. This method and our evaluation 

of it are described in the WRAP TSD 

prepared by EPA.165 Tables 53 and 54 

below compare the contribution of 

Arizona area sources to visibility 

impairment in Arizona’s Class I areas 

with the contributions from point and 

mobile sources.166 Table 53 shows the 

relative contribution of these Arizona 

source categories to the 2018 predicted 

total nitrate impairment at the Class I 

areas. Table 54 shows the same data for 

2018 predicted total sulfate impairment. 

Nitrate and sulfate comprise a subset of 

the total visibility impairment at these 

Class I areas. To calculate the source 

category’s total contribution to visibility 

impairment, one would have to account 

for the other pollutants (such as coarse 

mass, black carbon, etc.). EPA has not 

made that calculation here, as we are 

looking specifically at nitrate and 

sulfate impairment for this RP analysis. 

TABLE 53—2018 PROJECTED NITRATE

IMPAIRMENT: COMPARISON OF ARIZONA SOURCE CATEGORIES

Class I area 

Arizona 

area 

sources 

(%) 

Arizona 

point 

sources 

(%) 

Arizona 

mobile 

sources 

CHIR1 ......... 0.7 5.1 5.1 

GRCA2 ....... 2.9 7.4 18.3 

IKBA1 .......... 4.1 12.3 23.6 

BALD1 ........ 0.8 18.1 8.7 

PEFO1 ........ 1.7 26.7 14.2 

SAGU1 ........ 5.2 19.3 27.5 

SAWE1 ....... 4.3 18.4 23.5 

SIAN1 ......... 4.1 5.0 20.7 

TONT1 ........ 5.4 12.7 30.2 

SYCA1 ........ 2.7 14.0 19.3 

TABLE 54—2018 PROJECTED SULFATE

IMPAIRMENT: COMPARISON OF ARIZONA SOURCE CATEGORIES

Class I area 

Arizona 

area 

sources 

Arizona 

point 

sources 

Arizona 

mobile 

sources 

CHIR1 ......... 0.4 4.7 0.5 

GRCA2 ....... 0.4 4.3 1.0 

IKBA1 .......... 1.0 6.7 1.2 

BALD1 ........ 0.7 11.3 0.7 

PEFO1 ........ 0.7 19.6 0.9 

SAGU1 ........ 2.1 10.2 1.7 

SAWE1 ....... 1.7 9.6 1.4 

SIAN1 ......... 0.8 7.8 1.1 

TONT1 ........ 1.3 7.8 2.8 

SYCA1 ........ 1.0 3.5 0.8 

As indicated in Tables 53 and 54, area 

sources in Arizona currently comprise a 

relatively small portion of the visibility 

impairment due to nitrate and sulfate, 

so the potential visibility benefits of 

NOX or SO2 controls on these sources 

would be relatively small at this point 

in time. However, the relative 

contribution of area sources to visibility 

impairment at Arizona’s Class I areas 

may increase over time, as additional 

point source and mobile source controls 

are implemented. Therefore, additional 

analysis of these sources will be 

necessary in future planning periods. 

f. Proposed RP Determination for Area 

Sources 

EPA proposes to find that it is not 

reasonable to require additional controls 

on area sources of NOX and SO2 at this 

time. There are significant uncertainties 

about the costs and potential benefits of 

such rules at this time. Furthermore, the 

visibility benefits due to area source 

controls are likely to be much smaller 

than the significant reductions in SO2

and NOX emissions from point sources 

achieved during this planning period. 

We also note that no other Regional 

Haze SIP or FIP has imposed controls on 

such sources primarily to ensure 

reasonable progress.167 EPA will work 

with the State and the relevant regional 

planning organizations to improve our 

understanding of the nature of these 

area source emissions, the costs and 

methods of controlling them, and their 

impact on visibility at Class I areas. 

Based on the results of these efforts, 

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168 77 FR 72512, 78 FR 46142. 

169 77 FR 72512. 

170The regional-scale modeling that formed the 

basis for Arizona’s RPGs was developed by the 

WRAP’s Regional Modeling Center over the course 

of several years with input from numerous sources. 

171See 77 FR 75728, 78 FR 29298 and 78 FR 

46160. 

172 40 CFR 51.308(d)(1)(ii). 

173See 77 FR 75728 for a discussion on sources 

of organic carbon and elemental carbon (fires), and 

78 FR 29297–29299 for a discussion of coarse mass 

and fine soil. 

174See 78 FR 46172. 

175See 78 FR 46173 (codified at 40 CFR 

52.145(e)(ii)). 

176 40 CFR 51.308(d)(3)(ii). 

177 40 CFR 51.308(d)(3)(v)(C). 

178 40 CFR 51.308(d)(3)(v)(F). 

these source categories should be 

carefully considered in future Regional 

Haze SIPs. 

C. Reasonable Progress Goals 

We are proposing reasonable progress 

goals (RPGs) that are consistent with the 

combination of control measures 

included in the Arizona RH SIP 

measures that we previously 

approved; 168 the partial RH FIP that we 

promulgated on December 5, 2012; 169

and the partial RH FIP we are proposing 

today. In total, these final and proposed 

controls to meet the BART and RP 

requirements will result in higher 

emissions reductions and 

commensurate visibility improvements 

beyond what was in the State’s plan. As 

a result, we expect that the visibility 

levels at Arizona Class I areas will be 

substantially better than predicted in 

the WRAP modeling that served as the 

basis for the State’s RPGs. In addition, 

our final BART FIP for the Four Corners 

Power Plant on the Navajo Nation is 

expected to result in tens of thousands 

of tons per year of additional NOX

reductions that will benefit some of 

Arizona’s Class I areas. Likewise, our 

proposed BART FIP for the Navajo 

Generating Station, if finalized, will 

result in substantial visibility benefit for 

Class I areas. 

While we would prefer to quantify 

these proposed RPGs for each of 

Arizona’s 12 Class I areas based on the 

new state and federal plans, we lack 

sufficient time and resources to conduct 

the type of regional-scale modeling 

required to develop such numerical 

RPGs.170 Nonetheless, we anticipate that 

the additional controls required in 

EPA’s Regional Haze FIPs will result in 

an increase in visibility improvement 

during the 20 percent worst days and 

the 20 percent best days in all of 

Arizona’s Class 1 Areas. 

D. Meeting the Uniform Rate of Progress 

As explained in our proposed and 

final rules on the Arizona RH SIP, the 

State set RPGs that provide for slower 

rates of improvement in visibility than 

the URP for each of the State’s twelve 

Class I areas.171 Given the variety and 

location of the sources contributing to 

visibility impairment in Arizona, EPA 

considers it unlikely that all of 

Arizona’s Class I areas will meet the 

URP during this planning period, even 

with the additional controls required in 

EPA’s Regional Haze FIPs. Therefore, 

EPA must demonstrate that it is not 

reasonable to provide for rates of 

progress consistent with the URP for 

this planning period, based upon the 

four RP factors.172 Given that this 

demonstration must be based on the 

same four factors as the initial RP 

analysis, EPA proposes to find that the 

extensive reasonable progress analysis 

underlying our actions on the Arizona 

SIP, and the reasonable progress 

analysis found in this proposal are 

sufficient to make this demonstration. In 

particular, for the reasons explained in 

our proposed and final rules on the 

Arizona RH SIP, we have approved 

Arizona’s determinations that it is not 

reasonable to require additional controls 

to address organic carbon, elemental 

carbon, coarse mass and fine soil during 

this planning period.173 We also 

approved the State’s decision not to 

require additional controls on nonBART point sources of SO2.174

Moreover, based on the analyses set out 

in the preceding sections of this 

document, we are now proposing to find 

that it is not reasonable to require 

additional controls on most point 

sources of NOX or area sources of NOX

and SO2 during this planning period. 

However, we are proposing to require 

additional NOX controls on two cement 

kilns. Based on all of these analyses, we 

propose to find that it is not reasonable 

for any of Arizona’s Class I areas to meet 

the URP during this planning period. 

VII. EPA’s Proposed Long-Term 

Strategy Supplement 

In our final rule on the Arizona RH 

SIP published on July 30, 2013, we 

disapproved portions of the State’s LTS 

related to three RHR requirements. 

These requirements were for measures 

needed to achieve emission reductions 

for out-of-state Class I areas, emissions 

limitations and schedules for 

compliance to achieve the reasonable 

progress goals, and enforceability of 

emissions limitations and control 

measures.175 These RHR requirements 

are found in 40 CFR 51.308(d)(3)(ii), 

(v)(C) and (v)(F). We now are obligated 

to address these requirements through a 

FIP under CAA section 110(c). In this 

section, we describe each of these 

requirements, our rationale for 

disapproving these elements in the 

Arizona RH SIP, and propose how to 

address these requirements in our FIP. 

A. Emission Reductions for Out-of-State 

Class I Areas 

Under the RHR, where a state has 

participated in a regional planning 

process, the state’s LTS must include all 

measures needed to achieve that state’s 

apportionment of emission reduction 

obligations agreed upon through that 

process.176 Arizona participated in a 

regional planning process through the 

WRAP and incorporated the WRAPdeveloped visibility modeling into the 

Arizona RH SIP. However, the Arizona 

RH SIP did not include all measures 

needed to achieve the State’s 

apportionment of emission reductions 

that were included in the WRAP 

modeling. In particular, Arizona’s BART 

determinations lacked the necessary 

compliance schedules and requirements 

for operation and maintenance of 

control equipment and monitoring, 

recordkeeping and reporting to ensure 

that the assumed reductions at 

Arizona’s BART sources are achieved. 

Therefore, we disapproved this element 

of the Arizona RH SIP. 

B. Emissions Limitations and Schedules 

for Compliance To Achieve RPGs 

One of the factors a state must 

consider in developing its LTS is 

emissions limitations and schedules for 

compliance to achieve the State’s RPGs 

for its own Class I areas.177 As 

explained in the preceding section, the 

Arizona RH SIP did not contain any 

enforceable emission limitations or 

schedules for compliance to achieve the 

State’s RPGs. Therefore, we found that 

the Arizona RH SIP did not meet this 

requirement. 

C. Enforceability of Emissions 

Limitations and Control Measures 

Another factor a state must consider 

in developing its LTS is the 

enforceability of emissions limitations 

and control measures.178 As explained 

in the preceding sections, Arizona’s 

BART determinations lack provisions to 

ensure their enforceability. Therefore, 

we disapproved the Arizona RH SIP 

with respect to this requirement. 

D. Proposed Partial LTS FIP 

The primary flaw in Arizona’s LTS is 

the lack of enforceable emission 

limitations for BART controls. We 

propose to remedy this deficiency by 

promulgating BART emission 

limitations and compliance schedules as 

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9364 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules 

179See CAA section 110(a)(2)(F) and 40 CFR 

51.212(c), 51.308(d)(3)(v)(C) and (F). 

180Letter from Eric Hiser, Counsel for ASARCO, 

to Balaji Vaidyanathan, ADEQ dated March 20, 

2013, page 5. 

181Arizona RH SIP Supplement (May 3, 2013), 

Appendix D, page 23, and Section XII. 182ADEQ Air Quality Class I Permit Number 

53592 issued November 26, 2012, attachment B. 183 77 FR 75704 at 75709. 

184 77 FR 75704 at 75736. 185 77 FR 72512, 78 FR 46142. 186 77 FR 72512. 

well as monitoring, recordkeeping and 

reporting requirements, to ensure the 

enforceability of these limits. 

1. Enforceability Requirements for 

Arizona and EPA’s Phase 1 BART 

Determinations 

As part of our final rule published on 

December 5, 2012, regarding BART for 

Apache Generating Station, Cholla 

Power Plant and Coronado Generating 

Station, we promulgated compliance 

deadlines and requirements for 

equipment maintenance and operation 

including monitoring, recordkeeping 

and reporting, to ensure the 

enforceability of both Arizona’s and 

EPA’s BART determinations. 

2. Enforceability Requirements for 

EPA’s Proposed Phase 3 BART and RP 

Determinations 

As described above, today, we are 

proposing to promulgate similar 

requirements for the remaining subjectto-BART sources and pollutants in 

Arizona. We are also proposing 

emission limitations and compliance 

requirements for two RP sources: the 

Phoenix Cement Clarkdale Plant and the 

CalPortland Rillito Plant. 

3. Enforceability Requirements for 

Arizona’s Phase 2 BART Determinations 

The final element of our proposed 

LTS consists of enforceable emission 

limitations and associated requirements 

for PM10 at the Hayden and Miami 

Copper Smelters. While we previously 

approved the State’s determination that 

existing controls constitute BART for 

PM10 at each of these facilities, the 

Arizona RH SIP lacked any emission 

limitation or associated requirements to 

ensure the enforceability of these 

determinations, as required under the 

CAA and EPA’s regulations.179

Therefore, we are proposing to 

promulgate such limits and associated 

compliance requirements for these 

BART determinations, as necessary to 

ensure their enforceability. 

a. Hayden Smelter PM10

In its BART analysis for PM10, 

ASARCO relied on the particulate limits 

established in National Emission 

Standard for Hazardous Air Pollutants 

(NESHAP) Subpart QQQ, Primary 

Copper Smelting at 40 CFR 

63.1444(d)(5) and (6).180 These limits 

and associated monitoring requirements 

formed the basis for ASARCO’s BART 

determination, which ADEQ 

incorporated in its Regional Haze 

SIP.181 We are now proposing to 

incorporate these requirements into the 

FIP. In particular, we propose to set a 

limit of 6.2 mg/dscm non-sulfuric acid 

particulate matter from the primary 

capture system, and a limit of 23 mg/

dscm particulate matter from the 

secondary capture system, as measured 

using the test methods specified in 40 

CFR 63.1450(b). We propose to require 

demonstration of compliance with these 

limits through the applicable 

procedures in 40 CFR 63.1451 and 1453. 

b. Miami Smelter PM10

In the Arizona Regional Haze SIP, 

ADEQ determined that the NESHAP for 

Primary Copper Smelting constitutes 

BART for PM emissions from the Miami 

Smelter. Because the FMMI smelter is a 

major source of Hazardous Air 

Pollutants (HAPs), and therefore subject 

to the requirements of the NESHAP, 

these requirements are already 

incorporated into the facility’s Title V 

permit.182 We propose to find that these 

existing, federally enforceable 

requirements are sufficient to ensure the 

enforceability of ADEQ’s PM10 BART 

determination for the Miami Smelter. 

VIII. EPA’s Proposal for Interstate 

Transport 

We propose that a combination of SIP 

and FIP measures will satisfy the FIP 

obligation for the visibility requirement 

of CAA section 110(a)(2)(D)(i)(II) for the 

1997 8-hour ozone, 1997 PM2.5, and 

2006 PM2.5 NAAQS. As discussed in 

section II.B (‘‘Overview of Proposed 

Actions; Interstate Transport of 

Pollutants that affect Visibility’’) of this 

proposed rule, EPA disapproved 

Arizona’s 2007 and 2009 Transport SIPs 

as well as its Regional Haze SIP for the 

interstate transport visibility protection 

requirement of CAA section 

110(a)(2)(D)(i)(II) for the 1997 8-hour 

ozone, 1997 PM2.5, and 2006 PM2.5

NAAQS. As noted in our proposed SIP 

action,183 we interpret the visibility 

requirement of section 110(a)(D)(i)(II) as 

requiring states to include in their SIPs 

either measures to prohibit emissions 

that would interfere with attaining RPGs 

of Class I areas in other states, or a 

demonstration that emissions from the 

state’s sources and activities will not 

have the prohibited impacts under the 

existing SIP. Arizona’s 2007 and 2009 

Transport SIP revisions indicated that 

the interstate transport visibility 

requirement should be assessed in 

conjunction with the Arizona RH SIP, 

but did not specify which parts of the 

RH SIP should be considered as meeting 

the visibility requirement of section 

110(a)(2)(D)(i)(II). Therefore we have 

considered the Arizona RH SIP as a 

whole in assessing whether Arizona has 

met this visibility requirement. 

As a result of the partial disapprovals 

of the Arizona RH SIP, we found that 

the Arizona SIP did not contain 

adequate provisions to prohibit 

emissions that may interfere with SIP 

measures required of other states to 

protect visibility. Therefore, we 

disapproved Arizona’s submittals with 

respect to the interstate transport 

visibility requirement for the 1997 8- 

hour ozone, 1997 PM2.5, and 2006 PM2.5

NAAQS, which triggered the obligation 

for EPA to promulgate a FIP under CAA 

section 110(c)(1). We anticipated that 

this FIP obligation could be satisfied by 

a combination of the State’s measures 

that we previously approved and EPA’s 

promulgation of FIPs for the 

disapproved elements of the Arizona RH 

SIP.184

We propose to find that the 

combination of elements in the 

applicable RH SIPs and FIPs will 

contain adequate provisions to prohibit 

emissions from Arizona that would 

interfere with SIP measures required of 

other states to protect visibility. These 

elements are the Arizona RH SIP 

measures that we previously 

approved;185 the partial RH FIP that we 

promulgated on December 5, 2012;186

and the partial RH FIP we are proposing 

today. As explained in the LTS section, 

the combination of all of these measures 

will ensure that the applicable 

implementation plan (i.e., the 

combination of SIP and FIP measures) 

will include all of the measures needed 

to achieve Arizona’s allotment of 

emission reductions agreed upon 

through the WRAP process. We propose 

that this combination of SIP and FIP 

measures will satisfy the FIP obligation 

for the visibility requirement of CAA 

section 110(a)(2)(D)(i)(II) for the 1997 8- 

hour ozone, 1997 PM2.5, and 2006 PM2.5

NAAQS. 

IX. Summary of EPA’s Proposed 

Actions 

A. Regional Haze 

EPA is proposing a FIP to address the 

remaining portions of the Arizona’s RH 

SIP that we disapproved on July 30, 

2013, which includes requirements for 

Best Available Retrofit Technology, 

Reasonable Progress, and the Long-term 

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187See Regulatory Flexibility Act Screening 

Analysis for Proposed Arizona Regional Haze 

Federal Implementation Plan (EPA–R09–OAR– 

2013–0588). 

188See ‘‘Summary of EPA BART Cost Estimates’’ 

in the docket. 

Strategy. We are proposing more 

stringent emission limits on six sources 

that impact visibility in 17 Class I areas 

inside and outside the State. We 

welcome comments on all of our 

proposals and indicate specific issues or 

areas where feedback would be 

particularly useful. Our proposal 

includes compliance dates and specific 

requirements for monitoring, 

recordkeeping, reporting and equipment 

operation and maintenance for all of the 

units covered by this action as described 

in Part 52 attached to this notice. 

Today’s proposed FIP, once finalized, 

along with previously approved SIPs 

and a finalized FIP, will constitute 

Arizona’s regional haze program for the 

first planning period that ends in 2018. 

B. Interstate Visibility Transport 

We propose that the interstate 

transport visibility requirement of 

section 110(a)(2)(D)(i)(II) for the 1997 8- 

hour ozone, 1997 PM2.5, and 2006 PM2.5

NAAQS is satisfied by a combination of 

SIP and FIP elements. These elements 

are the Arizona RH SIP measures that 

we previously approved; the partial RH 

FIP that we promulgated on December 

5, 2012; and the partial RH FIP we are 

proposing today. 

X. Statutory and Executive Order 

Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review 

This proposed action is not a 

‘‘significant regulatory action’’ under 

the terms of Executive Order 12866 (58 

FR 51735, October 4, 1993) and is 

therefore not subject to review under 

Executive Orders 12866 and 13563 (76 

FR 3821, January 21, 2011). The 

proposed FIP applies to only six 

facilities. It is therefore not a rule of 

general applicability. 

B. Paperwork Reduction Act 

This proposed action does not impose 

an information collection burden under 

the provisions of the Paperwork 

Reduction Act, 44 U.S.C. 3501 et seq. 

Under the Paperwork Reduction Act, a 

‘‘collection of information’’ is defined as 

a requirement for ‘‘answers to * * * 

identical reporting or recordkeeping 

requirements imposed on ten or more 

persons * * *.’’ 44 U.S.C. 3502(3)(A). 

Because the proposed FIP applies to just 

six facilities, the Paperwork Reduction 

Act does not apply. See 5 CFR 1320(c). 

Burden means the total time, effort, or 

financial resources expended by persons 

to generate, maintain, retain, or disclose 

or provide information to or for a 

Federal agency. This includes the time 

needed to review instructions; develop, 

acquire, install, and utilize technology 

and systems for the purposes of 

collecting, validating, and verifying 

information, processing and 

maintaining information, and disclosing 

and providing information; adjust the 

existing ways to comply with any 

previously applicable instructions and 

requirements; train personnel to be able 

to respond to a collection of 

information; search data sources; 

complete and review the collection of 

information; and transmit or otherwise 

disclose the information. An agency 

may not conduct or sponsor, and a 

person is not required to respond to a 

collection of information unless it 

displays a currently valid Office of 

Management and Budget (OMB) control 

number. The OMB control numbers for 

our regulations in 40 CFR are listed in 

40 CFR part 9. 

C. Regulatory Flexibility Act 

The Regulatory Flexibility Act (RFA) 

generally requires an agency to prepare 

a regulatory flexibility analysis of any 

rule subject to notice and comment 

rulemaking requirements under the 

Administrative Procedure Act or any 

other statute unless the agency certifies 

that the rule will not have a significant 

economic impact on a substantial 

number of small entities. Small entities 

include small businesses, small 

organizations, and small governmental 

jurisdictions. For purposes of assessing 

the impacts of today’s proposed rule on 

small entities, small entity is defined as: 

(1) A small business as defined by the 

Small Business Administration’s (SBA) 

regulations at 13 CFR 121.201; (2) a 

small governmental jurisdiction that is a 

government of a city, county, town, 

school district or special district with a 

population of less than 50,000; and (3) 

a small organization that is any not-for 

profit enterprise which is independently 

owned and operated and is not 

dominant in its field. 

After considering the economic 

impacts of this proposed action on small 

entities, I certify that this proposed 

action will not have a significant 

economic impact on a substantial 

number of small entities. None of the 

facilities subject to this proposed rule is 

owned by a small entity.187 We continue 

to be interested in the potential impacts 

of the proposed rule on small entities 

and welcome comments on issues 

related to such impacts. 

D. Unfunded Mandates Reform Act 

Title II of the Unfunded Mandates 

Reform Act of 1995 (UMRA), Public 

Law 104–4, establishes requirements for 

Federal agencies to assess the effects of 

their regulatory actions on State, local, 

and Tribal governments and the private 

sector. Under section 202 of UMRA, 

EPA generally must prepare a written 

statement, including a cost-benefit 

analysis, for proposed and final rules 

with ‘‘Federal mandates’’ that may 

result in expenditures to State, local, 

and Tribal governments, in the 

aggregate, or to the private sector, of 

$100 million or more (adjusted for 

inflation) in any 1 year. Before 

promulgating an EPA rule for which a 

written statement is needed, section 205 

of UMRA generally requires EPA to 

identify and consider a reasonable 

number of regulatory alternatives and 

adopt the least costly, most costeffective, or least burdensome 

alternative that achieves the objectives 

of the rule. The provisions of section 

205 of UMRA do not apply when they 

are inconsistent with applicable law. 

Moreover, section 205 of UMRA allows 

EPA to adopt an alternative other than 

the least costly, most cost-effective, or 

least burdensome alternative if the 

Administrator publishes with the final 

rule an explanation why that alternative 

was not adopted. Before EPA establishes 

any regulatory requirements that may 

significantly or uniquely affect small 

governments, including Tribal 

governments, it must have developed 

under section 203 of UMRA a small 

government agency plan. The plan must 

provide for notifying potentially 

affected small governments, enabling 

officials of affected small governments 

to have meaningful and timely input in 

the development of EPA regulatory 

proposals with significant Federal 

intergovernmental mandates, and 

informing, educating, and advising 

small governments on compliance with 

the regulatory requirements. 

Under Title II of UMRA, EPA has 

determined that this proposed rule does 

not contain a Federal mandate that may 

result in expenditures that exceed the 

inflation-adjusted UMRA threshold of 

$100 million by State, local, or Tribal 

governments or the private sector in any 

1 year. In addition, this proposed rule 

does not contain a significant Federal 

intergovernmental mandate as described 

by section 203 of UMRA nor does it 

contain any regulatory requirements 

that might significantly or uniquely 

affect small governments.188

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189See Memorandum to Docket: Summary of 

Communications and Consultation between EPA, 

PCC and SRPMIC (January 27, 2014). 

E. Executive Order 13132: Federalism 

Executive Order 13132 Federalism (64 

FR 43255, August 10, 1999) revokes and 

replaces Executive Orders 12612 

(Federalism) and 12875 (Enhancing the 

Intergovernmental Partnership). 

Executive Order 13132 requires EPA to 

develop an accountable process to 

ensure ‘‘meaningful and timely input by 

State and local officials in the 

development of regulatory policies that 

have federalism implications.’’ ‘‘Policies 

that have federalism implications’’ is 

defined in the Executive Order to 

include regulations that have 

‘‘substantial direct effects on the States, 

on the relationship between the national 

government and the States, or on the 

distribution of power and 

responsibilities among the various 

levels of government.’’ Under Executive 

Order 13132, EPA may not issue a 

regulation that has federalism 

implications, that imposes substantial 

direct compliance costs, and that is not 

required by statute, unless the Federal 

government provides the funds 

necessary to pay the direct compliance 

costs incurred by State and local 

governments, or EPA consults with 

State and local officials early in the 

process of developing the proposed 

regulation. EPA also may not issue a 

regulation that has federalism 

implications and that preempts State 

law unless the Agency consults with 

State and local officials early in the 

process of developing the proposed 

regulation. 

This rule will not have substantial 

direct effects on the states, on the 

relationship between the national 

government and the states, or on the 

distribution of power and 

responsibilities among the various 

levels of government, as specified in 

Executive Order 13132. In this action, 

EPA is fulfilling our statutory duty 

under CAA Section 110(c) to 

promulgate a partial Regional Haze FIP. 

Thus, Executive Order 13132 does not 

apply to this action. In the spirit of 

Executive Order 13132, and consistent 

with EPA policy to promote 

communications between EPA and State 

and local governments, EPA specifically 

solicits comment on this proposed rule 

from State and local officials. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

Subject to the Executive Order 13175 

(65 FR 67249, November 9, 2000) EPA 

may not issue a regulation that has tribal 

implications, that imposes substantial 

direct compliance costs, and that is not 

required by statute, unless the Federal 

government provides the funds 

necessary to pay the direct compliance 

costs incurred by tribal governments, or 

EPA consults with tribal officials early 

in the process of developing the 

proposed regulation and develops a 

tribal summary impact statement. 

EPA has concluded that this action, if 

finalized, will have tribal implications, 

because it will impose substantial direct 

compliance costs on tribal governments, 

and the Federal government will not 

provide the funds necessary to pay 

those costs. PCC is a division of Salt 

River Pima Maricopa Indian Community 

(SRPMIC or the Community) and profits 

from the Phoenix Cement Clarkdale 

Plant are used to provide government 

services to SRPMIC’s members. 

Therefore, EPA is providing the 

following tribal summary impact 

statement as required by section 5(b). 

EPA consulted with tribal officials 

early in the process of developing this 

regulation to permit them to have 

meaningful and timely input into its 

development. In November 2012, we 

shared our initial analyses with SRPMIC 

and PCC to ensure that the tribe had an 

early opportunity to provide feedback 

on potential controls at the Clarkdale 

Plant. PCC submitted comments on this 

initial analysis as part of the rulemaking 

on the Arizona Regional Haze SIP and 

we revised our initial analysis based on 

these comments. On November 6, 2013, 

the EPA Region 9 Regional 

Administrator met with the President 

and other representatives of SRPMIC to 

discuss the potential impacts of the FIP 

on SRPMIC. Following this meeting, 

staff from EPA, SPRMIC and PCC shared 

further information regarding the Plant 

and potential impacts of the FIP on 

SRPMIC.189

During these consultations, SRPMIC 

expressed its concern regarding the 

potential financial impacts of any new 

controls that might be required at the 

Clarkdale Plant. In particular, SRPMIC 

requested that EPA provide PCC with an 

extended compliance schedule for any 

controls in order to enable PCC and 

SRPMIC to plan for such controls in 

their long-term budgets and thus 

mitigate the potential impacts to the 

Community.190 However, SRPMIC 

provided only limited information 

documenting the potential for such 

impacts and claimed all such 

information as CBI. 

As explained above, EPA is proposing 

to determine that it is reasonable to 

require installation of SNCR at Kiln 4 at 

the Clarkdale Plant by December 31, 

2018. EPA is also seeking comment on 

the possibility of establishing an annual 

cap on NOX emissions from Kiln 4 in 

lieu of a lb/ton emission limit. An 

annual cap would allow SRPMIC to 

delay installation of controls until the 

Plant’s production returns to prerecession levels and would thus help to 

address the Community’s concerns 

about the budgetary impacts of control 

requirements. EPA specifically solicits 

additional comment on this proposed 

rule from tribal officials. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks (62 FR 19885, 

April 23, 1997), applies to any rule that: 

(1) Is determined to be economically 

significant as defined under Executive 

Order 12866; and (2) concerns an 

environmental health or safety risk that 

we have reason to believe may have a 

disproportionate effect on children. EPA 

interprets EO 13045 as applying only to 

those regulatory actions that concern 

health or safety risks, such that the 

analysis required under section 5–501 of 

the EO has the potential to influence the 

regulation. This action is not subject to 

EO 13045 because it implements 

specific standards established by 

Congress in statutes. However, to the 

extent this proposed rule will limit 

emissions of NOX, SO2 and PM, the rule 

will have a beneficial effect on 

children’s health by reducing air 

pollution. 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This action is not subject to Executive 

Order 13211 (66 FR 28355 (May 22, 

2001)), because it is not a significant 

regulatory action under Executive Order 

12866. 

I. National Technology Transfer and 

Advancement Act 

Section 12 of the National Technology 

Transfer and Advancement Act 

(NTTAA) of 1995 requires Federal 

agencies to evaluate existing technical 

standards when developing a new 

regulation. To comply with NTTAA, 

EPA must consider and use ‘‘voluntary 

consensus standards’’ (VCS) if available 

and applicable when developing 

programs and policies unless doing so 

would be inconsistent with applicable 

law or otherwise impractical. EPA 

believes that VCS are inapplicable to 

this action. Today’s action does not 

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require the public to perform activities 

conducive to the use of VCS. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

Executive Order 12898 (59 FR 7629, 

February 16, 1994), establishes federal 

executive policy on environmental 

justice. Its main provision directs 

federal agencies, to the greatest extent 

practicable and permitted by law, to 

make environmental justice part of their 

mission by identifying and addressing, 

as appropriate, disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies, and activities on minority 

populations and low-income 

populations in the United States. 

We have determined that this 

proposed rule, if finalized, will not have 

disproportionately high and adverse 

human health or environmental effects 

on minority or low-income populations 

because it increases the level of 

environmental protection for all affected 

populations without having any 

disproportionately high and adverse 

human health or environmental effects 

on any population, including any 

minority or low-income population. 

This proposed federal rule limits 

emissions of NOX and SO2 from six 

facilities in Arizona. 

List of Subjects in 40 CFR Part 52 

Environmental protection, Air 

pollution control, Incorporation by 

reference, Intergovernmental relations, 

Nitrogen oxides, Sulfur dioxide, 

Particulate matter, Reporting and 

recordkeeping requirements, Visibility, 

Volatile organic compounds. 

Authority: 42 U.S.C. 7401 et seq. 

Dated: January 27, 2014. 

Jared Blumenfeld, 

Regional Administrator, Region 9. 

Part 52, chapter I, title 40 of the Code 

of Federal Regulations is proposed to be 

amended as follows: 

PART 52—APPROVAL AND 

PROMULGATION OF 

IMPLEMENTATION PLANS 

■ 1. The authority citation for part 52 

continues to read as follows: 

Authority: 42 U.S.C. 7401 et seq. 

Subpart D—Arizona 

■ 2. Amend § 52.145 by adding 

paragraphs (i), (j), (k), (l) and (m) to read 

as follow: 

§ 52.145 Visibility protection. 

* * * * * 

(i) Source-specific federal 

implementation plan for regional haze 

at Nelson Lime Plant—(1) Applicability. 

This paragraph (i) applies to the owner/ 

operator of the lime kilns designated as 

Kiln 1 and Kiln 2 at the Nelson Lime 

Plant located in Yavapai County, 

Arizona. 

(2) Definitions. Terms not defined in 

this paragraph (i)(2) shall have the 

meaning given them in the Clean Air 

Act or EPA’s regulations implementing 

the Clean Air Act. For purposes of this 

paragraph (i): 

Ammonia injection shall include any 

of the following: anhydrous ammonia, 

aqueous ammonia or urea injection. 

Continuous emission monitoring 

system or CEMS means the equipment 

required by this section to sample, 

analyze, measure, and provide, by 

means of readings recorded at least once 

every 15 minutes (using an automated 

data acquisition and handling system 

(DAHS)), a permanent record of NOX

emissions, SO2 emissions, diluent, or 

stack gas volumetric flow rate. 

Kiln 1 means rotary kiln 1, as 

identified in paragraph (i)(1) of this 

section. 

Kiln 2 means rotary kiln 2, as 

identified in paragraph (i)(1) of this 

section. 

Kiln operating day means a 24-hour 

period between 12 midnight and the 

following midnight during which the 

kiln operates. 

Lime product means the product of 

the lime kiln calcination process 

including calcitic lime, dolomitic lime, 

and dead-burned dolomite. 

NOX means nitrogen oxides. 

Owner/operator means any person 

who owns or who operates, controls, or 

supervises a kiln identified in paragraph 

(i)(1) of this section. 

SO2 means sulfur dioxide. 

Unit means any of the kilns identified 

in paragraph (i)(1) of this section. 

(3) Emission limitations. The owner/ 

operator of each kiln identified in 

paragraph (i)(1) of this section shall not 

emit or cause to be emitted pollutants in 

excess of the following limitations, in 

pounds of pollutant per ton of lime 

product (lb/ton), from any kiln. Each 

emission limit shall be based on a 

rolling 30 kiln-operating day basis. 

Kiln ID 

Pollutant emission limit 

NOX SO2

Kiln 1 ......... 3.80 9.32 

Kiln 2 ......... 2.61 9.73 

(4) Compliance dates. (i) The owner/ 

operator of each unit shall comply with 

the NOX emissions limitations and other 

NOX-related requirements of this 

paragraph (i) no later than (three years 

after date of publication of the final rule 

in the Federal Register). 

(ii) The owner/operator of each unit 

shall comply with the SO2 emissions 

limitations and other SO2-related 

requirements of this paragraph (i) no 

later than (six months after date of 

publication of the final rule in the 

Federal Register). 

(5) Compliance determination—(i) 

Continuous emission monitoring 

system. At all times after the compliance 

dates specified in paragraph (i)(4) of this 

section, the owner/operator of Kiln 1 

and 2 shall maintain, calibrate, and 

operate a CEMS, in full compliance with 

the requirements found at 40 CFR 60.13 

and 40 CFR Part 60, Appendices B and 

F, to accurately measure the mass 

emission rate of NOX and SO2, in 

pounds per hour, from Kiln 1 and 2. The 

CEMS shall be used by the owner/

operator to determine compliance with 

the emission limitations in paragraph 

(i)(3) of this section, in combination 

with data on actual lime production. 

The owner/operator must operate the 

monitoring system and collect data at all 

required intervals at all times that an 

affected unit is operating, except for 

periods of monitoring system 

malfunctions, repairs associated with 

monitoring system malfunctions, and 

required monitoring system quality 

assurance or quality control activities 

(including, as applicable, calibration 

checks and required zero and span 

adjustments). 

(ii) Ammonia consumption 

monitoring. Upon and after the 

completion of installation of ammonia 

injection on a unit, the owner or 

operator shall install, and thereafter 

maintain and operate, instrumentation 

to continuously monitor and record 

levels of ammonia consumption for that 

unit. 

(iii) Compliance determination for 

NOX. Compliance with the NOX

emission limit described in paragraph 

(i)(3) of this section shall be determined 

based on a rolling 30 kiln-operating day 

basis. The 30-day rolling NOX emission 

rate for each kiln shall be calculated for 

each kiln operating day in accordance 

with the following procedure: Step one, 

sum the hourly pounds of NOX emitted 

for the current kiln operating day and 

the preceding twenty-nine (29) kiln 

operating days, to calculate the total 

pounds of NOX emitted over the most 

recent thirty (30) kiln operating day 

period for that kiln; Step two, sum the 

total lime product, in tons, produced 

during the current kiln operating day 

and the preceding twenty-nine (29) kiln 

operating days, to calculate the total 

lime product produced over the most 

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recent thirty (30) kiln operating day 

period for that kiln; Step three, divide 

the total amount of NOX calculated from 

Step one by the total lime product 

calculated from Step two to calculate 

the 30-day rolling NOX emission rate for 

that kiln. Each 30-day rolling NOX

emission rate shall include all emissions 

and all lime product that occur during 

all periods within any kiln operating 

day, including emissions from startup, 

shutdown and malfunction. 

(iv) Compliance determination for 

SO2. Compliance with the SO2 emission 

limit described in paragraph (i)(3) of 

this section shall be determined based 

on a rolling 30 kiln-operating day basis. 

The 30-day rolling SO2 emission rate for 

each kiln shall be calculated for each 

kiln operating day in accordance with 

the following procedure: Step one, sum 

the hourly pounds of SO2 emitted for 

the current kiln operating day and the 

preceding twenty-nine (29) kiln 

operating days, to calculate the total 

pounds of SO2 emitted over the most 

recent thirty (30) kiln operating day 

period for that kiln; Step two, sum the 

total lime product, in tons, produced 

during the current kiln operating day 

and the preceding twenty-nine (29) kiln 

operating days, to calculate the total 

lime product produced over the most 

recent thirty (30) kiln operating day 

period for that kiln; Step three, divide 

the total amount of SO2 calculated from 

Step one by the total lime product 

calculated from Step two to calculate 

the 30-day rolling SO2 emission rate for 

that kiln. Each 30-day rolling SO2

emission rate shall include all emissions 

and all lime product that occur during 

all periods within any kiln operating 

day, including emissions from startup, 

shutdown and malfunction. 

(6) Recordkeeping. The owner/

operator shall maintain the following 

records for at least five years: 

(i) All CEMS data, including the date, 

place, and time of sampling or 

measurement; parameters sampled or 

measured; and results. 

(ii) All records of lime production. 

(iii) Daily 30-day rolling emission 

rates of NOX and SO2, when applicable, 

calculated in accordance with 

paragraphs (i)(5)(iii) and (iv) of this 

section. 

(iv) Records of quality assurance and 

quality control activities for emissions 

measuring systems including, but not 

limited to, any records required by 40 

CFR part 60, appendix F, Procedure 1. 

(v) Records of ammonia consumption, 

as recorded by the instrumentation 

required in paragraph (i)(5)(ii) of this 

section. 

(vi) Records of all major maintenance 

activities conducted on emission units, 

air pollution control equipment, CEMS 

and clinker production measurement 

devices. 

(vii) Any other records required by 40 

CFR part 60, Subpart F, or 40 CFR part 

60, Appendix F, Procedure 1. 

(7) Reporting. All reports required 

under this section shall be submitted by 

the owner/operator to the Director, 

Enforcement Division (Mail Code ENF– 

2–1), U.S. Environmental Protection 

Agency, Region 9, 75 Hawthorne Street, 

San Francisco, California 94105–3901. 

All reports required under this section 

shall be submitted within 30 days after 

the applicable compliance date(s) in 

paragraph (i)(4) of this section and at 

least semiannually thereafter, within 30 

days after the end of a semiannual 

period. The owner/operator may submit 

reports more frequently than 

semiannually for the purposes of 

synchronizing reports required under 

this section with other reporting 

requirements, such as the title V 

monitoring report required by 40 CFR 

70.6(a)(3)(iii)(A), but at no point shall 

the duration of a semiannual period 

exceed six months. 

(i) The owner/operator shall submit a 

report that lists the daily 30-day rolling 

emission rates for NOX and SO2. 

(ii) The owner/operator shall submit 

excess emissions reports for NOX and 

SO2 limits. Excess emissions means 

emissions that exceed the emissions 

limits specified in paragraph (i)(3) of 

this section. The reports shall include 

the magnitude, date(s), and duration of 

each period of excess emissions, 

specific identification of each period of 

excess emissions that occurs during 

startups, shutdowns, and malfunctions 

of the unit, the nature and cause of any 

malfunction (if known), and the 

corrective action taken or preventative 

measures adopted. 

(iii) The owner/operator shall submit 

CEMS performance reports, to include 

dates and duration of each period 

during which the CEMS was inoperative 

(except for zero and span adjustments 

and calibration checks), reason(s) why 

the CEMS was inoperative and steps 

taken to prevent recurrence, and any 

CEMS repairs or adjustments. 

(iv) The owner/operator shall also 

submit results of any CEMS 

performance tests required by 40 CFR 

part 60, appendix F, Procedure 1 

(Relative Accuracy Test Audits, Relative 

Accuracy Audits, and Cylinder Gas 

Audits). 

(v) When no excess emissions have 

occurred or the CEMS has not been 

inoperative, repaired, or adjusted during 

the reporting period, the owner/operator 

shall state such information in the 

semiannual report. 

(8) Notifications. (i) The owner/

operator shall notify EPA of 

commencement of construction of any 

equipment which is being constructed 

to comply with the NOX emission limits 

in paragraph (i)(3) of this section. 

(ii) The owner/operator shall submit 

semiannual progress reports on 

construction of any such equipment. 

(iii) The owner/operator shall submit 

notification of initial startup of any such 

equipment. 

(9) Equipment operations. (i) At all 

times, including periods of startup, 

shutdown, and malfunction, the owner 

or operator shall, to the extent 

practicable, maintain and operate the 

unit including associated air pollution 

control equipment in a manner 

consistent with good air pollution 

control practices for minimizing 

emissions. Pollution control equipment 

shall be designed and capable of 

operating properly to minimize 

emissions during all expected operating 

conditions. Determination of whether 

acceptable operating and maintenance 

procedures are being used will be based 

on information available to the Regional 

Administrator which may include, but 

is not limited to, monitoring results, 

review of operating and maintenance 

procedures, and inspection of the kiln. 

(ii) After completion of installation of 

ammonia injection on a unit, the owner 

or operator shall inject sufficient 

ammonia to achieve compliance with 

NOX emission limits from paragraph 

(i)(3) for that unit while preventing 

excessive ammonia emissions. 

(10) Enforcement. Notwithstanding 

any other provision in this 

implementation plan, any credible 

evidence or information relevant as to 

whether the unit would have been in 

compliance with applicable 

requirements if the appropriate 

performance or compliance test had 

been performed, can be used to establish 

whether or not the owner or operator 

has violated or is in violation of any 

standard or applicable emission limit in 

the plan. 

(11) Affirmative defense for 

malfunctions. The following provisions 

of the Arizona Administrative Code are 

incorporated by reference and made part 

of this Federal implementation plan: 

(i) R–18–2–101, paragraph 65; 

(ii) R18–2–310, sections (A), (B), (D) 

and (E) only; and 

(iii) R18–2–310.01. 

(j) Source-specific federal 

implementation plan for regional haze 

at H. Wilson Sundt Generating Station— 

(1) Applicability. This paragraph (j) 

applies to the owner and operator of the 

electricity generating unit (EGU) 

designated as Unit I4 at the H. Wilson 

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Sundt Generating Station located in 

Tucson, Pima County, Arizona. 

(2) Definitions. Terms not defined in 

this paragraph (j)(2) shall have the 

meaning given them in the Clean Air 

Act or EPA’s regulations implementing 

the Clean Air Act. For purposes of this 

paragraph (j): 

Ammonia injection shall include any 

of the following: anhydrous ammonia, 

aqueous ammonia or urea injection. 

Boiler operating day means a 24-hour 

period between 12 midnight and the 

following midnight during which any 

fuel is combusted at any time in the 

unit. 

Continuous emission monitoring 

system or CEMS means the equipment 

required by 40 CFR Part 75 and this 

paragraph (j). 

MMBtu means one million British 

thermal units. 

NOX means nitrogen oxides. 

Owner/operator means any person 

who owns or who operates, controls, or 

supervises the EGU identified in 

paragraph (j)(1) of this section. 

Pipeline natural gas means a naturally 

occurring fluid mixture of hydrocarbons 

as defined in 40 CFR 72.2. 

PM means total filterable particulate 

matter. 

PM10 means total particulate matter 

less than 10 microns in diameter. 

SO2 means sulfur dioxide. 

Unit means the EGU identified 

paragraph (j)(1) of this section. 

(3) Emission limitations. The owner/ 

operator of the unit shall not emit or 

cause to be emitted pollutants in excess 

of the following limitations, in pounds 

of pollutant per million british thermal 

units (lb/MMBtu), from the subject unit. 

Pollutant Pollutant emission 

limit 

NOX .............................. 0.36 

PM ................................ 0.030 

SO2 ............................... 0.23 

(4) Alternative emission limitations. 

The owner/operator of the unit may 

choose to comply with the following 

limitations in lieu of the emission 

limitations listed in paragraph (j)(3). 

(i) The owner/operator of the unit 

shall combust only pipeline natural gas 

in the subject unit. 

(ii) The owner/operator of the unit 

shall not emit or cause to be emitted 

pollutants in excess of the following 

limitations, in pounds of pollutant per 

million british thermal units (lb/

MMBtu), from the subject unit. 

Pollutant Pollutant emission 

limit 

NOX .............................. 0.25 

Pollutant Pollutant emission 

limit 

PM10 .............................. 0.010 

SO2 ............................... 0.00064 

(5) Compliance dates. (i) The owner/ 

operator of the unit subject to this 

paragraph shall comply with the NOX

and SO2 emissions limitations of 

paragraph (j)(3) of this section no later 

than (three years after date of 

publication of the final rule in the 

Federal Register). 

(ii) The owner/operator of the unit 

subject to this paragraph shall comply 

with the PM emissions limitations of 

paragraph (j)(3) of this section no later 

than April 16, 2015. 

(6) Alternative compliance dates. If 

the owner/operator chooses to comply 

with the emission limits of paragraph 

(j)(4) of this section in lieu of paragraph 

(j)(3) of this section, the owner/operator 

of the unit shall comply with the NOX, 

SO2 and PM10 emissions limitations of 

paragraph (j)(4) no later than December 

31, 2017. 

(7) Compliance determination—(i) 

Continuous emission monitoring 

system. (A) At all times after the 

compliance date specified in paragraph 

(j)(5)(i) of this section, the owner/

operator of the unit shall maintain, 

calibrate, and operate a CEMS, in full 

compliance with the requirements 

found at 40 CFR Part 75, to accurately 

measure SO2, NOX, diluent, and stack 

gas volumetric flow rate from the unit. 

All valid CEMS hourly data shall be 

used to determine compliance with the 

emission limitations for NOX and SO2 in 

paragraph (j)(3) of this section. When 

the CEMS is out-of-control as defined by 

Part 75, that CEMs data shall be treated 

as missing data and not used to 

calculate the emission average. Each 

required CEMS must obtain valid data 

for at least 90 percent of the unit 

operating hours, on an annual basis. 

(B) The owner/operator of the unit 

shall comply with the quality assurance 

procedures for CEMS found in 40 CFR 

Part 75. In addition to these Part 75 

requirements, relative accuracy test 

audits shall be calculated for both the 

NOX and SO2 pounds per hour 

measurement and the heat input 

measurement. The CEMs monitoring 

data shall not be bias adjusted. 

Calculations of relative accuracy for lb/ 

hr of NOX, SO2 and heat input shall be 

performed each time the Part 75 CEMS 

undergo relative accuracy testing. 

(ii) Ammonia consumption 

monitoring. Upon and after the 

completion of installation of ammonia 

injection on the unit, the owner or 

operator shall install, and thereafter 

maintain and operate, instrumentation 

to continuously monitor and record 

levels of ammonia consumption for that 

unit. 

(iii) Compliance determination for 

NOX. Compliance with the NOX

emission limit described in paragraph 

(j)(3) of this section shall be determined 

based on a rolling 30 boiler-operatingday basis. The 30-day rolling NOX

emission rate for the unit shall be 

calculated for each boiler operating day 

in accordance with the following 

procedure: Step one, sum the hourly 

pounds of NOX emitted for the current 

boiler operating day and the preceding 

twenty-nine (29) boiler operating days, 

to calculate the total pounds of NOX

emitted over the most recent thirty (30) 

boiler operating day period for that unit; 

Step two, sum the total heat input, in 

millions of BTU, during the current 

boiler operating day and the preceding 

twenty-nine (29) boiler operating days, 

to calculate the total heat input over the 

most recent thirty (30) boiler operating 

day period for that unit; Step three, 

divide the total amount of NOX

calculated from Step one by the total 

heat input calculated from Step two to 

calculate the 30-day rolling NOX

emission rate, in pounds per million 

BTU for that unit. Each 30-day rolling 

NOX emission rate shall include all 

emissions and all heat input that occur 

during all periods within any boiler 

operating day, including emissions from 

startup, shutdown and malfunction. If a 

valid NOX pounds per hour or heat 

input is not available for any hour for 

the unit, that heat input and NOX

pounds per hour shall not be used in the 

calculation of the 30-day rolling 

emission rate. 

(iv) Compliance determination for 

SO2. Compliance with the SO2 emission 

limit described in paragraph (j)(3) of this 

section shall be determined based on a 

rolling 30 boiler-operating-day basis. 

The 30-day rolling SO2 emission rate for 

the unit shall be calculated for each 

boiler operating day in accordance with 

the following procedure: Step one, sum 

the hourly pounds of SO2 emitted for 

the current boiler operating day and the 

preceding twenty-nine (29) boiler 

operating days, to calculate the total 

pounds of SO2 emitted over the most 

recent thirty (30) boiler operating day 

period for that unit; Step two, sum the 

total heat input, in millions of BTU, 

during the current boiler operating day 

and the preceding twenty-nine (29) 

boiler operating days, to calculate the 

total heat input over the most recent 

thirty (30) boiler operating day period 

for that unit; Step three, divide the total 

amount of SO2 calculated from Step one 

by the total heat input calculated from 

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Step two to calculate the 30-day rolling 

SO2 emission rate, in pounds per 

million BTU for that unit. Each 30-day 

rolling SO2 emission rate shall include 

all emissions and all heat input that 

occur during all periods within any 

boiler operating day, including 

emissions from startup, shutdown and 

malfunction. If a valid SO2 pounds per 

hour or heat input is not available for 

any hour for the unit, that heat input 

and SO2 pounds per hour shall not be 

used in the calculation of the 30-day 

rolling emission rate. 

(v) Compliance determination for PM. 

Compliance with the PM emission limit 

described in paragraph (j)(3) shall be 

determined from annual performance 

stack tests. Within sixty (60) days either 

preceding or following the compliance 

deadline specified in paragraph (j)(5)(ii) 

of this section, and on at least an annual 

basis thereafter, the owner/operator of 

the unit shall conduct a stack test on the 

unit to measure PM using EPA Method 

5, in 40 CFR part 60, Appendix A. Each 

test shall consist of three runs, with 

each run at least 120 minutes in 

duration and each run collecting a 

minimum sample of 60 dry standard 

cubic feet. Results shall be reported in 

lb/MMBtu using the calculation in 40 

CFR Part 60 Appendix A, Method 19. 

(8) Alternative compliance 

determination. If the owner/operator 

chooses to comply with the emission 

limits of paragraph (j)(4) of this section, 

this paragraph may be used in lieu of 

paragraph (j)(7) of this section to 

demonstrate compliance with the 

emission limits in paragraph (j)(4). 

(i) Continuous emission monitoring 

system. (A) At all times after the 

compliance date specified in paragraph 

(j)(6) of this section, the owner/operator 

of the unit shall maintain, calibrate, and 

operate a CEMS, in full compliance with 

the requirements found at 40 CFR part 

75, to accurately measure NOX, diluent, 

and stack gas volumetric flow rate from 

the unit. All valid CEMS hourly data 

shall be used to determine compliance 

with the emission limitations for NOX in 

paragraph (j)(4) of this section. When 

the CEMS is out-of-control as defined by 

Part 75, that CEMS data shall be treated 

as missing data and not used to 

calculate the emission average. Each 

required CEMS must obtain valid data 

for at least 90 percent of the unit 

operating hours, on an annual basis. 

(B) The owner/operator of the unit 

shall comply with the quality assurance 

procedures for CEMS found in 40 CFR 

part 75. In addition to these part 75 

requirements, relative accuracy test 

audits shall be calculated for both the 

NOX pounds per hour measurement and 

the heat input measurement. The CEMS 

monitoring data shall not be bias 

adjusted. Calculations of relative 

accuracy for lb/hr of NOX and heat 

input shall be performed each time the 

Part 75 CEMS undergo relative accuracy 

testing. 

(ii) Compliance determination for 

NOX. Compliance with the NOX

emission limit described in paragraph 

(j)(4) of this section shall be determined 

based on a rolling 30 boiler-operatingday basis. The 30-day rolling NOX

emission rate for the unit shall be 

calculated for each boiler operating day 

in accordance with the following 

procedure: Step one, sum the hourly 

pounds of NOX emitted for the current 

boiler operating day and the preceding 

twenty-nine (29) boiler operating days, 

to calculate the total pounds of NOX

emitted over the most recent thirty (30) 

boiler operating day period for that unit; 

Step two, sum the total heat input, in 

millions of BTU, during the current 

boiler operating day and the preceding 

twenty-nine (29) boiler operating days, 

to calculate the total heat input over the 

most recent thirty (30) boiler operating 

day period for that unit; Step three, 

divide the total amount of NOX

calculated from Step one by the total 

heat input calculated from Step two to 

calculate the 30-day rolling NOX

emission rate, in pounds per million 

BTU for that unit. Each 30-day rolling 

NOX emission rate shall include all 

emissions and all heat input that occur 

during all periods within any boiler 

operating day, including emissions from 

startup and shutdown. If a valid NOX

pounds per hour or heat input is not 

available for any hour for the unit, that 

heat input and NOX pounds per hour 

shall not be used in the calculation of 

the 30-day rolling emission rate. 

(iii) Compliance determination for 

SO2. Compliance with the SO2 emission 

limit for the unit shall be determined 

from fuel sulfur documentation 

demonstrating the use of pipeline 

natural gas. 

(iv) Compliance determination for 

PM10. Compliance with the PM10

emission limit for the unit shall be 

determined from performance stack 

tests. Within sixty (60) days following 

the compliance deadline specified in 

paragraph (j)(6) of this section, and at 

the request of the Regional 

Administrator thereafter, the owner/

operator of the unit shall conduct a 

stack test on the unit to measure PM10

using EPA Method 201A and Method 

202, per 40 CFR part 51, Appendix M. 

Each test shall consist of three runs, 

with each run at least 120 minutes in 

duration and each run collecting a 

minimum sample of 60 dry standard 

cubic feet. Results shall be reported in 

lb/MMBtu using the calculation in 40 

CFR part 60 Appendix A, Method 19. 

(9) Recordkeeping. The owner or 

operator shall maintain the following 

records for at least five years: 

(i) CEMS data measuring NOX in lb/ 

hr, SO2 in lb/hr, and heat input rate per 

hour. 

(ii) Daily 30-day rolling emission rates 

of NOX and SO2 calculated in 

accordance with paragraphs (j)(7)(iii) 

and (iv) of this section. 

(iii) Records of the relative accuracy 

test for NOX lb/hr and SO2 lb/hr 

measurement, and hourly heat input 

measurement. 

(iv) Records of quality assurance and 

quality control activities for emissions 

systems including, but not limited to, 

any records required by 40 CFR part 75. 

(v) Records of all major maintenance 

activities conducted on emission units, 

air pollution control equipment, and 

CEMS. 

(vi) Any other records required by 40 

CFR part 75. 

(vii) Records of ammonia 

consumption for the unit, as recorded 

by the instrumentation required in 

paragraph (j)(7)(ii) of this section. 

(viii) All PM stack test results. 

(10) Alternative recordkeeping 

requirements. If the owner/operator 

chooses to comply with the emission 

limits of paragraph (j)(4) of this section, 

the owner/operator shall maintain the 

records listed in this paragraph in lieu 

of the records contained in paragraph 

(j)(9) of this section. The owner or 

operator shall maintain the following 

records for at least five years: 

(i) CEMS data measuring NOX in lb/ 

hr and heat input rate per hour. 

(ii) Daily 30-day rolling emission rates 

of NOX calculated in accordance with 

paragraph (j)(8)(ii) of this section. 

(iii) Records of the relative accuracy 

test for NOX lb/hr measurement and 

hourly heat input measurement. 

(iv) Records of quality assurance and 

quality control activities for emissions 

systems including, but not limited to, 

any records required by 40 CFR part 75. 

(v) Records of all major maintenance 

activities conducted on emission units, 

air pollution control equipment, and 

CEMS. 

(vi) Any other records required by 40 

CFR part 75. 

(vii) Records sufficient to demonstrate 

that the fuel for the unit is pipeline 

natural gas. 

(viii) All PM10 stack test results. 

(11) Notifications. (i) By July 31, 2015, 

the owner/operator shall notify the 

Regional Administrator by letter 

whether it will comply with the 

emission limits in paragraph (j)(3) of 

this section or whether it will comply 

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with the emission limits in paragraph 

(j)(4) of this section. 

(ii) The owner/operator shall notify 

EPA of commencement of construction 

of any equipment which is being 

constructed to comply with either the 

NOX or SO2 emission limits in 

paragraph (j)(3) of this section. 

(iii) The owner/operator shall submit 

semiannual progress reports on 

construction of any such equipment. 

(iv) The owner/operator shall submit 

notification of initial startup of any such 

equipment. 

(12) Reporting. All reports required 

under this section shall be submitted by 

the owner/operator to the Director, 

Enforcement Division (Mail Code ENF– 

2–1), U.S. Environmental Protection 

Agency, Region 9, 75 Hawthorne Street, 

San Francisco, California 94105–3901. 

All reports required under this section 

shall be submitted within 30 days after 

the applicable compliance date(s) in 

paragraph (j)(5) of this section and at 

least semiannually thereafter, within 30 

days after the end of a semiannual 

period. The owner/operator may submit 

reports more frequently than 

semiannually for the purposes of 

synchronizing reports required under 

this section with other reporting 

requirements, such as the title V 

monitoring report required by 40 CFR 

70.6(a)(3)(iii)(A), but at no point shall 

the duration of a semiannual period 

exceed six months. 

(i) The owner/operator shall submit a 

report that lists the daily 30-day rolling 

emission rates for NOX and SO2. 

(ii) The owner/operator shall submit 

excess emission reports for NOX and 

SO2 limits. Excess emissions means 

emissions that exceed the emissions 

limits specified in paragraph (j)(3) of 

this section. Excess emission reports 

shall include the magnitude, date(s), 

and duration of each period of excess 

emissions, specific identification of 

each period of excess emissions that 

occurs during startups, shutdowns, and 

malfunctions of the unit, the nature and 

cause of any malfunction (if known), 

and the corrective action taken or 

preventative measures adopted. 

(iii) The owner/operator shall submit 

CEMS performance reports, to include 

dates and duration of each period 

during which the CEMS was inoperative 

(except for zero and span adjustments 

and calibration checks), reason(s) why 

the CEMS was inoperative and steps 

taken to prevent recurrence, and any 

CEMS repairs or adjustments. 

(iv) The owner/operator shall submit 

the results of any relative accuracy test 

audits performed during the two 

preceding calendar quarters. 

(v) When no excess emissions have 

occurred or the CEMS has not been 

inoperative, repaired, or adjusted during 

the reporting period, the owner/operator 

shall state such information in the 

semiannual report. 

(vi) The owner/operator shall submit 

results of any PM stack tests conducted 

for demonstrating compliance with the 

PM limit specified in paragraph (j)(3). 

(13) Alternative reporting 

requirements. If the owner/operator 

chooses to comply with the emission 

limits of paragraph (j)(4) of this section, 

the owner/operator shall submit the 

reports listed in this paragraph in lieu 

of the reports contained in paragraph 

(j)(12) of this section. All reports 

required under this paragraph shall be 

submitted by the owner/operator to the 

Director, Enforcement Division (Mail 

Code ENF–2–1), U.S. Environmental 

Protection Agency, Region 9, 75 

Hawthorne Street, San Francisco, 

California 94105–3901. All reports 

required under this paragraph shall be 

submitted within 30 days after the 

applicable compliance date(s) in 

paragraph (j)(6) of this section and at 

least semiannually thereafter, within 30 

days after the end of a semiannual 

period. The owner/operator may submit 

reports more frequently than 

semiannually for the purposes of 

synchronizing reports required under 

this section with other reporting 

requirements, such as the title V 

monitoring report required by 40 CFR 

70.6(a)(3)(iii)(A), but at no point shall 

the duration of a semiannual period 

exceed six months. 

(i) The owner/operator shall submit a 

report that lists the daily 30-day rolling 

emission rates for NOX. 

(ii) The owner/operator shall submit 

excess emissions reports for NOX limits. 

Excess emissions means emissions that 

exceed the emissions limits specified in 

paragraph (j)(4) of this section. The 

reports shall include the magnitude, 

date(s), and duration of each period of 

excess emissions, specific identification 

of each period of excess emissions that 

occurs during startups, shutdowns, and 

malfunctions of the unit, the nature and 

cause of any malfunction (if known), 

and the corrective action taken or 

preventative measures adopted. 

(iii) The owner/operator shall submit 

CEMS performance reports, to include 

dates and duration of each period 

during which the CEMS was inoperative 

(except for zero and span adjustments 

and calibration checks), reason(s) why 

the CEMS was inoperative and steps 

taken to prevent recurrence, and any 

CEMS repairs or adjustments. 

(iv) The owner/operator shall submit 

the results of any relative accuracy test 

audits performed during the two 

preceding calendar quarters. 

(v) When no excess emissions have 

occurred or the CEMS has not been 

inoperative, repaired, or adjusted during 

the reporting period, the owner/operator 

shall state such information in the 

semiannual report. 

(vi) The owner/operator shall submit 

results of any PM10 stack tests 

conducted for demonstrating 

compliance with the PM10 limit 

specified in paragraph (j)(4) of this 

section. 

(14) Equipment operations. (i) At all 

times, including periods of startup, 

shutdown, and malfunction, the owner 

or operator shall, to the extent 

practicable, maintain and operate the 

unit including associated air pollution 

control equipment in a manner 

consistent with good air pollution 

control practices for minimizing 

emissions. Pollution control equipment 

shall be designed and capable of 

operating properly to minimize 

emissions during all expected operating 

conditions. Determination of whether 

acceptable operating and maintenance 

procedures are being used will be based 

on information available to the Regional 

Administrator which may include, but 

is not limited to, monitoring results, 

review of operating and maintenance 

procedures, and inspection of the unit. 

(ii) After completion of installation of 

ammonia injection on a unit, the owner 

or operator shall inject sufficient 

ammonia to achieve compliance with 

NOX emission limits contained in 

paragraph (j)(3) of this section for that 

unit while preventing excessive 

ammonia emissions. 

(15) Enforcement. Notwithstanding 

any other provision in this 

implementation plan, any credible 

evidence or information relevant as to 

whether the unit would have been in 

compliance with applicable 

requirements if the appropriate 

performance or compliance test had 

been performed, can be used to establish 

whether or not the owner or operator 

has violated or is in violation of any 

standard or applicable emission limit in 

the plan. 

(16) Affirmative defense for 

malfunctions. The following provisions 

of the Arizona Administrative Code are 

incorporated by reference and made part 

of this federal implementation plan: 

(i) R–18–2–101, paragraph 65; 

(ii) R18–2–310, sections (A), (B), (D) 

and (E) only; and 

(iii) R18–2–310.01. 

(k) Source-specific federal 

implementation plan for regional haze 

at Clarkdale Cement Plant and Rillito 

Cement Plant—(1) Applicability. This 

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paragraph (k) applies to each owner/

operator of the following cement kilns 

in the state of Arizona: Kiln 4 located at 

the cement plant in Clarkdale, Arizona, 

and Kiln 4 located at the cement plant 

in Rillito, Arizona. 

(2) Definitions. Terms not defined in 

this paragraph (k)(2) shall have the 

meaning given them in the Clean Air 

Act or EPA’s regulations implementing 

the Clean Air Act. For purposes of this 

paragraph (k): 

Ammonia injection shall include any 

of the following: Anhydrous ammonia, 

aqueous ammonia or urea injection. 

Continuous emission monitoring 

system or CEMS means the equipment 

required by this section to sample, 

analyze, measure, and provide, by 

means of readings recorded at least once 

every 15 minutes (using an automated 

data acquisition and handling system 

(DAHS)), a permanent record of NOX

emissions, diluent, or stack gas 

volumetric flow rate. 

Kiln operating day means a 24-hour 

period between 12 midnight and the 

following midnight during which the 

kiln operates. 

NOX means nitrogen oxides. 

Owner/operator means any person 

who owns or who operates, controls, or 

supervises a cement kiln identified in 

paragraph (k)(1) of this section. 

Unit means a cement kiln identified 

in paragraph (k)(1) of this section. 

(3) Emissions limitations. The owner/ 

operator of each unit identified in 

paragraph (k)(1) of this section shall not 

emit or cause to be emitted NOX in 

excess of the following limitations, in 

pounds per ton of clinker produced, 

based on a rolling 30-kiln operating day 

basis. 

Cement Kiln NOX emission 

limitation 

Clarkdale Plant, Kiln 4 ........ 2.12 

Rillito Plant, Kiln 4 .............. 2.67 

(4) Compliance date. The owner/

operator of each unit identified in 

paragraph (k)(i) of this section shall 

comply with the NOX emissions 

limitations and other NOX-related 

requirements of this paragraph (k) no 

later than (three years after date of 

publication of the final rule in the 

Federal Register). 

(5) Compliance determination—(i) 

Continuous emission monitoring 

system. (A) At all times after the 

compliance date specified in paragraph 

(k)(4) of this section, the owner/operator 

of the unit at the Clarkdale Plant shall 

maintain, calibrate, and operate a 

CEMS, in full compliance with the 

requirements found at 40 CFR 60.63(f) 

and (g), to accurately measure 

concentration by volume of NOX, 

diluent, and stack gas volumetric flow 

rate from the in-line/raw mill stack, as 

well as the stack gas volumetric flow 

rate from the coal mill stack. The CEMS 

shall be used by the owner/operator to 

determine compliance with the 

emission limitation in paragraph (k)(3) 

of this section, in combination with data 

on actual clinker production. The 

owner/operator must operate the 

monitoring system and collect data at all 

required intervals at all times the 

affected unit is operating, except for 

periods of monitoring system 

malfunctions, repairs associated with 

monitoring system malfunctions, and 

required monitoring system quality 

assurance or quality control activities 

(including, as applicable, calibration 

checks and required zero and span 

adjustments). 

(B) At all times after the compliance 

date specified in paragraph (k)(4) of this 

section, the owner/operator of the unit 

at the Rillito Plant shall maintain, 

calibrate, and operate a CEMS, in full 

compliance with the requirements 

found at 40 CFR 60.63(f) and (g), to 

accurately measure concentration by 

volume of NOX, diluent, and stack gas 

volumetric flow rate from the unit. The 

CEMS shall be used by the owner/

operator to determine compliance with 

the emission limitation in paragraph 

(k)(3) of this section, in combination 

with data on actual clinker production. 

The owner/operator must operate the 

monitoring system and collect data at all 

required intervals at all times the 

affected unit is operating, except for 

periods of monitoring system 

malfunctions, repairs associated with 

monitoring system malfunctions, and 

required monitoring system quality 

assurance or quality control activities 

(including, as applicable, calibration 

checks and required zero and span 

adjustments). 

(ii) Methods. (A) The owner/operator 

of each unit shall record the daily 

clinker production rates. 

(B)(1) The owner/operator of each 

unit shall calculate and record the 30- 

kiln operating day average emission rate 

of NOX, in lb/ton of clinker produced, 

as the total of all hourly emissions data 

for the cement kiln in the preceding 30- 

kiln operating days, divided by the total 

tons of clinker produced in that kiln 

during the same 30-day operating 

period, using the following equation: 

Where: 

ED = 30 kiln operating day average emission 

rate of NOX, lb/ton of clinker; 

Ci = Concentration of NOX for hour i, ppm; 

Qi = volumetric flow rate of effluent gas for 

hour i, where Ci and Qi are on the same 

basis (either wet or dry), scf/hr; 

Pi = total kiln clinker produced during 

production hour i, ton/hr; 

k = conversion factor, 1.194 × 10¥7 for NOX; 

and.

n = number of kiln operating hours over 30 

kiln operating days, n = 1 to 720. 

(2) For each kiln operating hour for 

which the owner/operator does not have 

at least one valid 15-minute CEMS data 

value, the owner/operator must use the 

average emissions rate (lb/hr) from the 

most recent previous hour for which 

valid data are available. Hourly clinker 

production shall be determined by the 

owner/operator in accordance with the 

requirements found at 40 CFR 60.63(b). 

(C) At the end of each kiln operating 

day, the owner/operator shall calculate 

and record a new 30-day rolling average 

emission rate in lb/ton clinker from the 

arithmetic average of all valid hourly 

emission rates for the current kiln 

operating day and the previous 29 

successive kiln operating days. 

(D) Upon and after the completion of 

installation of ammonia injection on a 

unit, the owner/operator shall install, 

and thereafter maintain and operate, 

instrumentation to continuously 

monitor and record levels of ammonia 

consumption that unit. 

(6) Recordkeeping. The owner/

operator of each unit shall maintain the 

following records for at least five years: 

(i) All CEMS data, including the date, 

place, and time of sampling or 

measurement; parameters sampled or 

measured; and results. 

(ii) All records of clinker production. 

(iii) Daily 30-day rolling emission 

rates of NOX, calculated in accordance 

with paragraph (k)(5)(ii) of this section. 

(iv) Records of quality assurance and 

quality control activities for emissions 

measuring systems including, but not 

limited to, any records required by 40 

CFR part 60, appendix F, Procedure 1. 

(v) Records of ammonia consumption, 

as recorded by the instrumentation 

required in paragraph (k)(5)(ii)(D) of this 

section. 

(vi) Records of all major maintenance 

activities conducted on emission units, 

air pollution control equipment, CEMS 

and clinker production measurement 

devices. 

(vii) Any other records required by 40 

CFR part 60, Subpart F, or 40 CFR part 

60, Appendix F, Procedure 1. 

(7) Reporting. All reports required 

under this section shall be submitted by 

the owner/operator to the Director, 

Enforcement Division (Mailcode ENF– 


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Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules 9373 

2–1), U.S. Environmental Protection 

Agency, Region 9, 75 Hawthorne Street, 

San Francisco, California 94105–3901. 

All reports required under this section 

shall be submitted within 30 days after 

the applicable compliance date in 

paragraph (k)(4) of this section and at 

least semiannually thereafter, within 30 

days after the end of a semiannual 

period. The owner/operator may submit 

reports more frequently than 

semiannually for the purposes of 

synchronizing reports required under 

this section with other reporting 

requirements, such as the title V 

monitoring report required by 40 CFR 

70.6(a)(3)(iii)(A), but at no point shall 

the duration of a semiannual period 

exceed six months. 

(i) The owner/operator shall submit a 

report that lists the daily 30-day rolling 

emission rates for NOX. 

(ii) The owner/operator shall submit 

excess emissions reports for NOX limits. 

Excess emissions means emissions that 

exceed the emissions limits specified in 

paragraph (k)(3) of this section. The 

reports shall include the magnitude, 

date(s), and duration of each period of 

excess emissions, specific identification 

of each period of excess emissions that 

occurs during startups, shutdowns, and 

malfunctions of the unit, the nature and 

cause of any malfunction (if known), 

and the corrective action taken or 

preventative measures adopted. 

(iii) The owner/operator shall submit 

CEMS performance reports, to include 

dates and duration of each period 

during which the CEMS was inoperative 

(except for zero and span adjustments 

and calibration checks), reason(s) why 

the CEMS was inoperative and steps 

taken to prevent recurrence, and any 

CEMS repairs or adjustments. 

(iv) The owner/operator shall also 

submit results of any CEMS 

performance tests required by 40 CFR 

part 60, appendix F, Procedure 1 

(Relative Accuracy Test Audits, Relative 

Accuracy Audits, and Cylinder Gas 

Audits). 

(v) When no excess emissions have 

occurred or the CEMS has not been 

inoperative, repaired, or adjusted during 

the reporting period, the owner/operator 

shall state such information in the 

reports required by paragraph (k)(7)(ii) 

of this section. 

(8) Notifications. (i) The owner/

operator shall submit notification of 

commencement of construction of any 

equipment which is being constructed 

to comply with the NOX emission limits 

in paragraph (k)(3) of this section. 

(ii) The owner/operator shall submit 

semiannual progress reports on 

construction of any such equipment. 

(iii) The owner/operator shall submit 

notification of initial startup of any such 

equipment. 

(9) Equipment operation. (i) At all 

times, including periods of startup, 

shutdown, and malfunction, the owner 

or operator shall, to the extent 

practicable, maintain and operate the 

unit including associated air pollution 

control equipment in a manner 

consistent with good air pollution 

control practices for minimizing 

emissions. Pollution control equipment 

shall be designed and capable of 

operating properly to minimize 

emissions during all expected operating 

conditions. Determination of whether 

acceptable operating and maintenance 

procedures are being used will be based 

on information available to the Regional 

Administrator which may include, but 

is not limited to, monitoring results, 

review of operating and maintenance 

procedures, and inspection of the unit. 

(ii) After completion of installation of 

ammonia injection on a unit, the owner 

or operator shall inject sufficient 

ammonia to achieve compliance with 

NOX emission limits from paragraph 

(k)(3) for that unit while preventing 

excessive ammonia emissions. 

(10) Enforcement. Notwithstanding 

any other provision in this 

implementation plan, any credible 

evidence or information relevant as to 

whether the unit would have been in 

compliance with applicable 

requirements if the appropriate 

performance or compliance test had 

been performed, can be used to establish 

whether or not the owner or operator 

has violated or is in violation of any 

standard or applicable emission limit in 

the plan. 

(11) Affirmative defense for 

malfunctions. The following provisions 

of the Arizona Administrative Code are 

incorporated by reference and made part 

of this Federal implementation plan: 

(i) R–18–2–101, paragraph 65; 

(ii) R18–2–310, sections (A), (B), (D) 

and (E) only; and 

(iii) R18–2–310.01. 

(l) Source-specific federal 

implementation plan for regional haze 

at Hayden Copper Smelter—(1) 

Applicability. This paragraph (l) applies 

to each owner/operator of each batch 

copper converter and anode furnaces #1 

and #2 at the copper smelting plant 

located in Hayden, Gila County, 

Arizona. 

(2) Definitions. Terms not defined in 

this paragraph (l)(2) shall have the 

meaning given them in the Clean Air 

Act or EPA’s regulations implementing 

the Clean Air Act. For purposes of this 

paragraph (l): 

Anode furnace means a furnace in 

which molten blister copper is refined 

through introduction of a reducing agent 

such as natural gas. 

Batch copper converter means a 

Pierce-Smith converter or Hoboken 

converter in which copper matte is 

oxidized to form blister copper by a 

process that is performed in discrete 

batches using a sequence of charging, 

blowing, skimming, and pouring. 

Blister copper means an impure form 

of copper, typically between 98 and 99 

percent pure copper that is the output 

of the converters. 

Calendar day means a 24 hour period 

that begins and ends at midnight, local 

standard time. 

Continuous emission monitoring 

system or CEMS means the equipment 

required by this section to sample, 

analyze, measure, and provide, by 

means of readings recorded at least once 

every 15 minutes (using an automated 

data acquisition and handling system 

(DAHS)), a permanent record of SO2

emissions, other pollutant emissions, 

diluent, or stack gas volumetric flow 

rate. 

Copper matte means a material 

predominately composed of copper and 

iron sulfides produced by smelting 

copper ore concentrates. 

NOX means nitrogen oxides. 

Owner/operator means any person 

who owns or who operates, controls, or 

supervises the equipment identified in 

paragraph (l)(1) of this section. 

SO2 means sulfur dioxide. 

(3) Emission capture. (i) The owner/ 

operator of the batch copper converters 

identified in paragraph (l)(1) of this 

section must operate a capture system 

that has been designed to maximize 

collection of process off gases vented 

from each converter. At all times when 

one or more converters are blowing, you 

must operate the capture system 

consistent with a written operation and 

maintenance plan that has been 

prepared according to the requirements 

in 40 CFR 63.1447(b) and approved by 

EPA within 180 days of the compliance 

date in paragraph (l)(5) of this section. 

The capture system must include a 

primary capture system as described in 

40 CFR 63.1444(d)(2) and a secondary 

hood as described in 40 CFR 

63.1444(d)(2). (ii) The operation of the 

batch copper converters and secondary 

hood shall be optimized to capture the 

maximum amount of process off gases 

vented from each converter at all times. 

(4) Emission limitations and work 

practice standards. (i) SO2 emissions 

collected by the capture system required 

by paragraph (l)(3) of this section must 

be controlled by one or more control 

devices and reduced by at least 99.81 

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9374 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules 

percent, based on a 30-day rolling 

average. 

(ii) The owner/operator must not 

cause or allow to be discharged to the 

atmosphere from any primary capture 

system required by paragraph (l)(3) offgas that contains nonsulfuric acid 

particulate matter in excess of 6.2 mg/ 

dscm as measured using the test 

methods specified in 40 CFR 63.1450(b). 

(iii) The owner/operator must not 

cause or allow to be discharged to the 

atmosphere from any secondary capture 

system required by paragraph (l)(3) of 

this section off-gas that contains 

particulate matter in excess of 23 mg/

dscm as measured using the test 

methods specified in 40 CFR 63.1450(a). 

(iv) Total NOX emissions from anode 

furnaces #1 and #2 and the batch copper 

converters shall not exceed 40 tons per 

12-continuous month period. 

(v) Anode furnaces #1 and #2 shall 

only be charged with blister copper or 

higher purity copper. 

(5) Compliance dates. The owner/

operator of each batch copper converter 

identified in paragraph (l)(1) of this 

section shall comply with the emissions 

limitations and other requirements of 

this section no later than (three years 

after date of publication of the final rule 

in the Federal Register). 

(6) Compliance determination—(i) 

Continuous emission monitoring 

system. At all times after the compliance 

date specified in paragraph (e) of this 

section, the owner/operator of each 

batch copper converter identified in 

paragraph (l)(1) of this section shall 

maintain, calibrate, and operate a 

CEMS, in full compliance with the 

requirements found at 40 CFR 60.13 and 

40 CFR part 60, Appendices B and F, to 

accurately measure the mass emission 

rate in pounds per hour of SO2

emissions entering each control device 

used to control emissions from the 

converters, and venting from the 

converters to the atmosphere after 

passing through a control device or an 

uncontrolled bypass stack. The CEMS 

shall be used by the owner/operator to 

determine compliance with the 

emission limitation in paragraph (l)(4) 

of this plan. The owner/operator must 

operate the monitoring system and 

collect data at all required intervals at 

all times that an affected unit is 

operating, except for periods of 

monitoring system malfunctions, repairs 

associated with monitoring system 

malfunctions, and required monitoring 

system quality assurance or quality 

control activities (including, as 

applicable, calibration checks and 

required zero and span adjustments). 

(ii) Compliance determination for 

SO2. The 30-day rolling SO2 emission 

control efficiency for the converters 

shall be calculated for each calendar day 

in accordance with the following 

procedure: Step one, sum the hourly 

pounds of SO2 vented to each 

uncontrolled bypass stack and to each 

control device used to control emissions 

from the converters for the current 

calendar day and the preceding twentynine (29) calendar days, to calculate the 

total pounds of pre-control SO2

emissions over the most recent thirty 

(30) calendar day period; Step two, sum 

the hourly pounds of SO2 vented to each 

uncontrolled bypass stack and emitted 

from the release point of each control 

device used to control emissions from 

the converters for the current calendar 

day and the preceding twenty-nine (29) 

calendar days, to calculate the total 

pounds of post-control SO2 emissions 

over the most recent thirty (30) calendar 

day period; Step three, divide the total 

amount of post-control SO2 emissions 

calculated from Step two by the total 

amount of pre-control SO2 emissions 

calculated from Step one, subtract the 

resulting quotient from one, and 

multiply the difference by 100 percent 

to calculate the 30-day rolling SO2

emission control efficiency as a 

percentage. 

(iii) Compliance determination for 

nonsulfuric acid particulate matter. 

Compliance with the emission limit for 

nonsulfuric acid particulate matter in 

paragraph (l)(4)(ii) of this section shall 

be demonstrated by the procedures in 

40 CFR 63.1451(b) and 40 CFR 

63.1453(a)(2). 

(iv) Compliance determination for 

particulate matter. Compliance with the 

emission limit for particulate matter in 

paragraph (l)(4)(iii) of this section shall 

be demonstrated by the procedures in 

40 CFR 63.1451(a) and 40 CFR 

63.1453(a)(1). 

(v) Compliance determination for 

NOX. Compliance with the emission 

limit for NOX in paragraph (l)(4)(iv) of 

this section shall be demonstrated by 

monitoring natural gas consumption in 

each of the units identified in paragraph 

(l)(1) of this section for each calendar 

day. At the end of each calendar month, 

the owner/operator shall calculate 12- 

consecutive month NOX emissions by 

multiplying the daily natural gas 

consumption rates for each unit by an 

approved emission factor and adding 

the sums for all units over the previous 

12-consecutive month period. 

(7) Alternative compliance 

determination for sulfuric acid plants. If 

the owner/operator uses one or more 

double contact acid plants to control 

SO2 from the batch copper converters 

identified in paragraph (l)(1) of this 

section, this paragraph may be used to 

demonstrate compliance with the 

emission limit in paragraph (l)(4)(i) of 

this section. 

(i) Continuous emission monitoring 

system. At all times after the compliance 

date specified in paragraph (l)(5) of this 

section, the owner/operator of each 

batch copper converter identified in 

paragraph (l)(1) of this section shall 

maintain, calibrate, and operate a 

CEMS, in full compliance with the 

requirements found at 40 CFR 60.13 and 

40 CFR part 60, Appendices B and F, to 

accurately measure the mass emission 

rate in pounds per hour of SO2

emissions venting from the converters to 

the atmosphere after passing through a 

control device or an uncontrolled 

bypass stack. The CEMS shall be used 

by the owner/operator to determine 

compliance with the emission limitation 

in paragraph (l)(4) of this section. The 

owner/operator must operate the 

monitoring system and collect data at all 

required intervals at all times that an 

affected unit is operating, except for 

periods of monitoring system 

malfunctions, repairs associated with 

monitoring system malfunctions, and 

required monitoring system quality 

assurance or quality control activities 

(including, as applicable, calibration 

checks and required zero and span 

adjustments). 

(ii) Daily sulfuric acid production 

monitoring. At all times after the 

compliance date specified in paragraph 

(l)(5) of this section, the owner/operator 

of each batch copper converter subject 

to this section shall monitor and 

maintain records of sulfuric acid 

production for each calendar day. 

(iii) Compliance determination for 

SO2. The 30-day rolling SO2 emission 

rate for the converters shall be 

calculated for each calendar day in 

accordance with the following 

procedure: Step one, sum the hourly 

pounds of SO2 vented to each 

uncontrolled bypass stack and emitted 

from the release point of each double 

contact acid plant used to control 

emissions from the converters for the 

current calendar day and the preceding 

twenty-nine (29) calendar days, to 

calculate the total pounds of SO2

emissions over the most recent thirty 

(30) calendar day period; Step two, sum 

the total sulfuric acid production in tons 

of pure sulfuric acid for the current 

calendar day and the preceding twentynine (29) calendar days, to calculate the 

total tons of sulfuric acid production 

over the most recent thirty (30) calendar 

day period; Step three, divide the total 

amount of SO2 emissions calculated 

from Step one by the total tons of 

sulfuric acid production calculated from 

Step one to calculate the 30-day rolling 

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Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules 9375 

SO2 emission rate in lbs-SO2 per ton of 

sulfuric acid. An emission rate of 4.06 

or lower shall be deemed to be in 

compliance with the emission limit in 

paragraph (i)(4) of this section. 

(8) Capture system monitoring. For 

each operating limit established under 

the capture system operation and 

maintenance plan required by paragraph 

(l)(4) of this section, the owner/operator 

must install, operate, and maintain an 

appropriate monitoring device 

according to the requirements in 40 CFR 

63.1452(a)(1) though (6) to measure and 

record the operating limit value or 

setting at all times the required capture 

system is operating. Dampers that are 

manually set and remain in the same 

position at all times the capture system 

is operating are exempted from these 

monitoring requirements. 

(9) Recordkeeping. The owner/

operator shall maintain the following 

records for at least five years: 

(i) All CEMS data, including the date, 

place, and time of sampling or 

measurement; parameters sampled or 

measured; and results. 

(ii) Records of quality assurance and 

quality control activities for emissions 

measuring systems including, but not 

limited to, any records required by 40 

CFR part 60, appendix F, Procedure 1. 

(iii) Records of all major maintenance 

activities conducted on emission units, 

air pollution control equipment, and 

CEMS. 

(iv) Any other records required by 40 

CFR part 60, Subpart F, or 40 CFR part 

60, Appendix F, Procedure 1. 

(v) Records of all monitoring required 

by paragraph (l)(8) of this section. 

(vi) Records of daily sulfuric acid 

production in tons per day of pure 

sulfuric acid if the owner/operator 

chooses to use the alternative 

compliance determination method in 

paragraph (l)(7) of this section. 

(vii) Records of daily natural gas 

consumption in each units identified in 

paragraph (l)(1) and all calculations 

performed to demonstrate compliance 

with the limit in paragraph (l)(4)(iv). 

(10) Reporting. All reports required 

under this section shall be submitted by 

the owner/operator to the Director, 

Enforcement Division (Mail Code ENF– 

2–1), U.S. Environmental Protection 

Agency, Region 9, 75 Hawthorne Street, 

San Francisco, California 94105–3901. 

All reports required under this section 

shall be submitted within 30 days after 

the applicable compliance date in 

paragraph (l)(5) of this section and at 

least semiannually thereafter, within 30 

days after the end of a semiannual 

period. The owner/operator may submit 

reports more frequently than 

semiannually for the purposes of 

synchronizing reports required under 

this section with other reporting 

requirements, such as the title V 

monitoring report required by 40 CFR 

70.6(a)(3)(iii)(A), but at no point shall 

the duration of a semiannual period 

exceed six months. 

(i) The owner/operator shall promptly 

submit excess emissions reports for the 

SO2 limit. Excess emissions means 

emissions that exceed the emissions 

limit specified in paragraph (d) of this 

section. The reports shall include the 

magnitude, date(s), and duration of each 

period of excess emissions, specific 

identification of each period of excess 

emissions that occurs during startups, 

shutdowns, and malfunctions of the 

unit, the nature and cause of any 

malfunction (if known), and the 

corrective action taken or preventative 

measures adopted. For the purpose of 

this paragraph, promptly shall mean 

within 30 days after the end of the 

month in which the excess emissions 

were discovered. 

(ii) The owner/operator shall submit 

CEMS performance reports, to include 

dates and duration of each period 

during which the CEMS was inoperative 

(except for zero and span adjustments 

and calibration checks), reason(s) why 

the CEMS was inoperative and steps 

taken to prevent recurrence, and any 

CEMS repairs or adjustments. The 

owner/operator shall submit reports 

semiannually. 

(iii) The owner/operator shall also 

submit results of any CEMS 

performance tests required by 40 CFR 

part 60, appendix F, Procedure 1 

(Relative Accuracy Test Audits, Relative 

Accuracy Audits, and Cylinder Gas 

Audits). 

(iv) When no excess emissions have 

occurred or the CEMS has not been 

inoperative, repaired, or adjusted during 

the reporting period, the owner/operator 

shall state such information in the 

semiannual report. 

(v) When performance testing is 

required to determine compliance with 

an emission limit in paragraph (l)(4) of 

this section, the owner/operator shall 

submit test reports as specified in 40 

CFR part 63, subpart A. 

(11) Notifications. (i) The owner/

operator shall notify EPA of 

commencement of construction of any 

equipment which is being constructed 

to comply with the capture or emission 

limits in paragraph (l)(3) or (4) of this 

section. 

(ii) The owner/operator shall submit 

semiannual progress reports on 

construction of any such equipment. 

(iii) The owner/operator shall submit 

notification of initial startup of any such 

equipment. 

(12) Equipment operations. At all 

times, including periods of startup, 

shutdown, and malfunction, the owner 

or operator shall, to the extent 

practicable, maintain and operate the 

unit including associated air pollution 

control equipment in a manner 

consistent with good air pollution 

control practices for minimizing 

emissions. Pollution control equipment 

shall be designed and capable of 

operating properly to minimize 

emissions during all expected operating 

conditions. Determination of whether 

acceptable operating and maintenance 

procedures are being used will be based 

on information available to the Regional 

Administrator which may include, but 

is not limited to, monitoring results, 

review of operating and maintenance 

procedures, and inspection of the unit. 

(13) Enforcement. Notwithstanding 

any other provision in this 

implementation plan, any credible 

evidence or information relevant as to 

whether the unit would have been in 

compliance with applicable 

requirements if the appropriate 

performance or compliance test had 

been performed, can be used to establish 

whether or not the owner or operator 

has violated or is in violation of any 

standard or applicable emission limit in 

the plan. 

(14) Affirmative defense for 

malfunctions. The following provisions 

of the Arizona Administrative Code are 

incorporated by reference and made part 

of this Federal implementation plan: 

(i) R–18–2–101, paragraph 65; 

(ii) R18–2–310, sections (A), (B), (D) 

and (E) only; and 

(iii) R18–2–310.01. 

(m) Source-specific federal 

implementation plan for regional haze 

at Miami Copper Smelter—(1) 

Applicability. This paragraph (m) 

applies to each owner/operator of each 

batch copper converter and the electric 

furnace at the copper smelting plant 

located in Hayden, Gila County, 

Arizona. 

(2) Definitions. Terms not defined in 

this paragraph (m)(2) shall have the 

meaning given them in the Clean Air 

Act or EPA’s regulations implementing 

the Clean Air Act. For purposes of this 

paragraph (m): 

Batch copper converter means a 

Pierce-Smith converter or Hoboken 

converter in which copper matte is 

oxidized to form blister copper by a 

process that is performed in discrete 

batches using a sequence of charging, 

blowing, skimming, and pouring. 

Calendar day means a 24 hour period 

that begins and ends at midnight, local 

standard time. 

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9376 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules 

Continuous emission monitoring 

system or CEMS means the equipment 

required by this section to sample, 

analyze, measure, and provide, by 

means of readings recorded at least once 

every 15 minutes (using an automated 

data acquisition and handling system 

(DAHS)), a permanent record of SO2

emissions, other pollutant emissions, 

diluent, or stack gas volumetric flow 

rate. 

Copper matte means a material 

predominately composed of copper and 

iron sulfides produced by smelting 

copper ore concentrates. 

Electric furnace means a furnace in 

which copper matte and slag are heated 

by electrical resistance without the 

mechanical introduction of air or 

oxygen. 

NOX means nitrogen oxides. 

Owner/operator means any person 

who owns or who operates, controls, or 

supervises the equipment identified in 

paragraph (m)(1) of this section. 

Slag means the waste material 

consisting primarily of iron sulfides 

separated from copper matte during the 

smelting and refining of copper ore 

concentrates. 

SO2 means sulfur dioxide. 

(3) Emission capture. (i)The owner/

operator of the batch copper converters 

identified in paragraph (m)(1) of this 

section must operate a capture system 

that has been designed to maximize 

collection of process off gases vented 

from each converter. At all times when 

one or more converters are blowing, you 

must operate the capture system 

consistent with a written operation and 

maintenance plan that has been 

prepared according to the requirements 

in 40 CFR 63.1447(b) and approved by 

EPA within 180 days of the compliance 

date in paragraph (m)(5) of this section. 

The capture system must include a 

primary capture system as described in 

40 CFR 63.1444(d)(3) and a secondary 

hood as described in 40 CFR 

63.1444(d)(2). (ii) The operation of the 

batch copper converters and secondary 

hood shall be optimized to capture the 

maximum amount of process off gases 

vented from each converter at all times. 

(4) Emission limitations and work 

practice standards. (i) SO2 emissions 

collected by the capture system required 

by paragraph (m)(3) of this section must 

be controlled by one or more control 

devices and reduced by at least 99.7 

percent, based on a 30-day rolling 

average. 

(ii) Total NOX emissions the electric 

furnace and the batch copper converters 

shall not exceed 40 tons per 12- 

continuous month period. 

(iii) The owner/operator shall not 

actively aerate the electric furnace. 

(5) Compliance dates. The owner/

operator of each batch copper converter 

identified in paragraph (m)(1) of this 

section shall comply with the emissions 

limitations and other requirements of 

this section no later than (three years 

after date of publication of the final rule 

in the Federal Register). 

(6) Compliance determination—(i) 

Continuous emission monitoring 

system. At all times after the compliance 

date specified in paragraph (e) of this 

section, the owner/operator of each 

batch copper converter identified in 

paragraph (m)(1) of this section shall 

maintain, calibrate, and operate a 

CEMS, in full compliance with the 

requirements found at 40 CFR 60.13 and 

40 CFR part 60, Appendices B and F, to 

accurately measure the mass emission 

rate in pounds per hour of SO2

emissions entering each control device 

used to control emissions from the 

converters, and venting from the 

converters to the atmosphere after 

passing through a control device or an 

uncontrolled bypass stack. The CEMS 

shall be used by the owner/operator to 

determine compliance with the 

emission limitation in paragraph (m)(4) 

of this section. The owner/operator 

must operate the monitoring system and 

collect data at all required intervals at 

all times that an affected unit is 

operating, except for periods of 

monitoring system malfunctions, repairs 

associated with monitoring system 

malfunctions, and required monitoring 

system quality assurance or quality 

control activities (including, as 

applicable, calibration checks and 

required zero and span adjustments). 

(ii) Compliance determination for 

SO2. The 30-day rolling SO2 emission 

control efficiency for the converters 

shall be calculated for each calendar day 

in accordance with the following 

procedure: Step one, sum the hourly 

pounds of SO2 vented to each 

uncontrolled bypass stack and to each 

control device used to control emissions 

from the converters for the current 

calendar day and the preceding twentynine (29) calendar days, to calculate the 

total pounds of pre-control SO2

emissions over the most recent thirty 

(30) calendar day period; Step two, sum 

the hourly pounds of SO2 vented to each 

uncontrolled bypass stack and emitted 

from the release point of each control 

device used to control emissions from 

the converters for the current calendar 

day and the preceding twenty-nine (29) 

calendar days, to calculate the total 

pounds of post-control SO2 emissions 

over the most recent thirty (30) calendar 

day period; Step three, divide the total 

amount of post-control SO2 emissions 

calculated from Step two by the total 

amount of pre-control SO2 emissions 

calculated from Step one, subtract the 

resulting quotient from one, and 

multiply the difference by 100 percent 

to calculate the 30-day rolling SO2

emission control efficiency as a 

percentage. 

(iii) Compliance determination for 

NOX. Compliance with the emission 

limit for NOX in paragraph (m)(4)(ii) of 

this section shall be demonstrated by 

monitoring natural gas consumption in 

each of the units identified in paragraph 

(m)(1) of this section for each calendar 

day. At the end of each calendar month, 

the owner/operator shall calculate 

monthly and 12-consecutive month 

NOX emissions by multiplying the daily 

natural gas consumption rates for each 

unit by an approved emission factor and 

adding the sums for all units over the 

previous 12-consecutive month period. 

(7) Alternative compliance 

determination for sulfuric acid plants. If 

the owner/operator uses one or more 

double contact acid plants to control 

SO2 from the batch copper converters 

identified in paragraph (m)(1) of this 

section, this paragraph may be used to 

demonstrate compliance with the 

emission limit in paragraph (m)(4)(i) of 

this section. 

(i) Continuous emission monitoring 

system. At all times after the compliance 

date specified in paragraph (m)(5) of 

this section, the owner/operator of each 

batch copper converter identified in 

paragraph (m)(1) of this section shall 

maintain, calibrate, and operate a 

CEMS, in full compliance with the 

requirements found at 40 CFR 60.13 and 

40 CFR part 60, Appendices B and F, to 

accurately measure the mass emission 

rate in pounds per hour of SO2

emissions venting from the converters to 

the atmosphere after passing through a 

control device or an uncontrolled 

bypass stack. The CEMS shall be used 

by the owner/operator to determine 

compliance with the emission limitation 

in paragraph (m)(4) of this section. The 

owner/operator must operate the 

monitoring system and collect data at all 

required intervals at all times that an 

affected unit is operating, except for 

periods of monitoring system 

malfunctions, repairs associated with 

monitoring system malfunctions, and 

required monitoring system quality 

assurance or quality control activities 

(including, as applicable, calibration 

checks and required zero and span 

adjustments). 

(ii) Daily sulfuric acid production 

monitoring. At all times after the 

compliance date specified in paragraph 

(m)(5) of this section, the owner/

operator of each batch copper converter 

subject to this section shall monitor and 

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Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules 9377 

maintain records of sulfuric acid 

production for each calendar day. 

(iii) Compliance determination for 

SO2. The 30-day rolling SO2 emission 

rate for the converters shall be 

calculated for each calendar day in 

accordance with the following 

procedure: Step one, sum the hourly 

pounds of SO2 vented to each 

uncontrolled bypass stack and emitted 

from the release point of each double 

contact acid plant used to control 

emissions from the converters for the 

current calendar day and the preceding 

twenty-nine (29) calendar days, to 

calculate the total pounds of SO2

emissions over the most recent thirty 

(30) calendar day period; Step two, sum 

the total sulfuric acid production in tons 

of pure sulfuric acid for the current 

calendar day and the preceding twentynine (29) calendar days, to calculate the 

total tons of sulfuric acid production 

over the most recent thirty (30) calendar 

day period; Step three, divide the total 

amount of SO2 emissions calculated 

from Step one by the total tons of 

sulfuric acid production calculated from 

Step one to calculate the 30-day rolling 

SO2 emission rate in lbs-SO2 per ton of 

sulfuric acid. An emission rate of 4.06 

or lower shall be deemed to be in 

compliance with the emission limit in 

paragraph (i)(4) of this section. 

(8) Capture system monitoring. For 

each operating limit established under 

the capture system operation and 

maintenance plan required by paragraph 

(m)(4) of this section, the owner/

operator must install, operate, and 

maintain an appropriate monitoring 

device according to the requirements in 

40 CFR 63.1452(a)(1) though (6) to 

measure and record the operating limit 

value or setting at all times the required 

capture system is operating. Dampers 

that are manually set and remain in the 

same position at all times the capture 

system is operating are exempted from 

these monitoring requirements. 

(9) Recordkeeping. The owner/

operator shall maintain the following 

records for at least five years: 

(i) All CEMS data, including the date, 

place, and time of sampling or 

measurement; parameters sampled or 

measured; and results. 

(ii) Records of quality assurance and 

quality control activities for emissions 

measuring systems including, but not 

limited to, any records required by 40 

CFR part 60, appendix F, Procedure 1. 

(iii) Records of all major maintenance 

activities conducted on emission units, 

air pollution control equipment, and 

CEMS. 

(iv) Any other records required by 40 

CFR part 60, Subpart F, or 40 CFR part 

60, Appendix F, Procedure 1. 

(v) Records of all monitoring required 

by paragraph (m)(8) of this section. 

(vi) Records of daily sulfuric acid 

production in tons per day of pure 

sulfuric acid if the owner/operator 

chooses to use the alternative 

compliance determination method in 

paragraph (m)(7) of this section. 

(vii) Records of daily natural gas 

consumption in each units identified in 

paragraph (m)(1) and all calculations 

performed to demonstrate compliance 

with the limit in paragraph (m)(4)(iv). 

(10) Reporting. All reports required 

under this section shall be submitted by 

the owner/operator to the Director, 

Enforcement Division (Mail Code ENF– 

2–1), U.S. Environmental Protection 

Agency, Region 9, 75 Hawthorne Street, 

San Francisco, California 94105–3901. 

All reports required under this section 

shall be submitted within 30 days after 

the applicable compliance date in 

paragraph (m)(5) of this section and at 

least semiannually thereafter, within 30 

days after the end of a semiannual 

period. The owner/operator may submit 

reports more frequently than 

semiannually for the purposes of 

synchronizing reports required under 

this section with other reporting 

requirements, such as the title V 

monitoring report required by 40 CFR 

70.6(a)(3)(iii)(A), but at no point shall 

the duration of a semiannual period 

exceed six months. 

(i) The owner/operator shall promptly 

submit excess emissions reports for the 

SO2 limit. Excess emissions means 

emissions that exceed the emissions 

limit specified in paragraph (d) of this 

section. The reports shall include the 

magnitude, date(s), and duration of each 

period of excess emissions, specific 

identification of each period of excess 

emissions that occurs during startups, 

shutdowns, and malfunctions of the 

unit, the nature and cause of any 

malfunction (if known), and the 

corrective action taken or preventative 

measures adopted. For the purpose of 

this paragraph, promptly shall mean 

within 30 days after the end of the 

month in which the excess emissions 

were discovered. 

(ii) The owner/operator shall submit 

CEMS performance reports, to include 

dates and duration of each period 

during which the CEMS was inoperative 

(except for zero and span adjustments 

and calibration checks), reason(s) why 

the CEMS was inoperative and steps 

taken to prevent recurrence, and any 

CEMS repairs or adjustments. The 

owner/operator shall submit reports 

semiannually. 

(iii) The owner/operator shall also 

submit results of any CEMS 

performance tests required by 40 CFR 

part 60, appendix F, Procedure 1 

(Relative Accuracy Test Audits, Relative 

Accuracy Audits, and Cylinder Gas 

Audits). 

(iv) When no excess emissions have 

occurred or the CEMS has not been 

inoperative, repaired, or adjusted during 

the reporting period, the owner/operator 

shall state such information in the 

semiannual report. 

(v) When performance testing is 

required to determine compliance with 

an emission limit in paragraph (m)(4) of 

this section, the owner/operator shall 

submit test reports as specified in 40 

CFR part 63, subpart A. 

(11) Notifications. (i) The owner/

operator shall notify EPA of 

commencement of construction of any 

equipment which is being constructed 

to comply with the capture or emission 

limits in paragraph (m)(3) or (4) of this 

section. 

(ii) The owner/operator shall submit 

semiannual progress reports on 

construction of any such equipment. 

(iii) The owner/operator shall submit 

notification of initial startup of any such 

equipment. 

(12) Equipment operations. At all 

times, including periods of startup, 

shutdown, and malfunction, the owner 

or operator shall, to the extent 

practicable, maintain and operate the 

unit including associated air pollution 

control equipment in a manner 

consistent with good air pollution 

control practices for minimizing 

emissions. Pollution control equipment 

shall be designed and capable of 

operating properly to minimize 

emissions during all expected operating 

conditions. Determination of whether 

acceptable operating and maintenance 

procedures are being used will be based 

on information available to the Regional 

Administrator which may include, but 

is not limited to, monitoring results, 

review of operating and maintenance 

procedures, and inspection of the unit. 

(13) Enforcement. Notwithstanding 

any other provision in this 

implementation plan, any credible 

evidence or information relevant as to 

whether the unit would have been in 

compliance with applicable 

requirements if the appropriate 

performance or compliance test had 

been performed, can be used to establish 

whether or not the owner or operator 

has violated or is in violation of any 

standard or applicable emission limit in 

the plan. 

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9378 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules 

(14) Affirmative defense for 

malfunctions. The following provisions 

of the Arizona Administrative Code are 

incorporated by reference and made part 

of this federal implementation plan: 

(i) R–18–2–101, paragraph 65; 

(ii) R18–2–310, sections (A), (B), (D) 

and (E) only; and 

(iii) R18–2–310.01. 

[FR Doc. 2014–02714 Filed 2–14–14; 8:45 am] 

BILLING CODE 6560–50–P 

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