Vol. 79 Wednesday, 

No. 170 September 3, 2014 

Part II 

Environmental Protection Agency 

40 CFR Part 52 

Promulgation of Air Quality Implementation Plans; Arizona; Regional Haze 

and Interstate Visibility Transport Federal Implementation Plan; Final Rule 


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52420 Federal Register / Vol. 79, No. 170 / Wednesday, September 3, 2014 / Rules and Regulations 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 52 

[EPA–R09–OAR–2013–0588; FRL–9912–97– 

OAR] 

Promulgation of Air Quality 

Implementation Plans; Arizona; 

Regional Haze and Interstate Visibility 

Transport Federal Implementation Plan 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Final rule. 

SUMMARY: This final action promulgates 

a Federal Implementation Plan (FIP) 

addressing 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 a final rule published in 

the Federal Register on July 30, 2013. In 

that action, we partially approved and 

partially disapproved the State’s plan to 

implement the regional haze program 

for the first planning period. This final 

action includes our responses to 

comments on our proposed FIP 

published in the Federal Register on 

February 18, 2014. This final rule, 

together with a final rule published in 

the Federal Register on December 5, 

2012, completes our FIP for the 

disapproved portions of Arizona’s RH 

SIP. This final rule addresses the RHR’s 

requirements for Best Available Retrofit 

Technology (BART), Reasonable 

Progress (RP), and a Long-term Strategy 

(LTS) as well as the interstate visibility 

transport requirements of the Clean Air 

Act (CAA) for pollutants that affect 

visibility in Arizona’s 12 Class I areas 

and areas in nearby states. The BART 

sources addressed in this final FIP are 

Tucson Electric Power (TEP) Sundt 

Generating Station Unit 4, Lhoist North 

America (LNA) Nelson Lime Plant Kilns 

1 and 2, ASARCO Incorporated Hayden 

Smelter, and Freeport-McMoRan 

Incorporated (FMMI) Miami Smelter. 

The reasonable progress sources 

addressed in the FIP are Phoenix 

Cement Company (PCC) Clarkdale Plant 

Kiln 4 and CalPortland Cement (CPC) 

Rillito Plant Kiln 4. EPA is prepared to 

work with the State on a SIP revision 

that would replace some or all elements 

of the FIP. 

DATES: Effective Date: This rule is 

effective October 3, 2014. 

ADDRESSES: EPA has established docket 

number EPA–R09–OAR–2013–0588 for 

this action. Generally, documents in the 

docket are available electronically at 

http://www.regulations.gov or in hard 

copy at EPA Region 9, 75 Hawthorne 

Street, San Francisco, California. Please 

note that while many of the documents 

in the docket are listed at http://

www.regulations.gov, some information 

may not be specifically listed in the 

index to the docket and may be publicly 

available only at the hard copy location 

(e.g., copyrighted material, large maps, 

multi-volume reports, or otherwise 

voluminous materials), and some may 

not be available at either locations (e.g., 

confidential business information). To 

inspect the hard copy materials, please 

schedule an appointment during normal 

business hours with the contact listed 

directly below. 

FOR FURTHER INFORMATION CONTACT: 

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

Planning Office, Air Division, Air-2, 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. Introduction 

II. History of State and Federal Plans 

A. State Submittals and EPA Actions 

B. EPA’s Authority To Promulgate a FIP 

III. Summary of Proposed Rule 

A. Regional Haze 

B. Interstate Transport of Pollutants That 

Affect Visibility 

IV. Overview of Final Action 

A. BART Determinations 

B. Reasonable Progress Determinations 

C. Reasonable Progress Goals and 

Demonstration 

D. Long-Term Strategy 

E. Interstate Visibility Transport 

F. Other Changes From Proposal 

V. Responses to General Comments 

A. Introduction 

B. Comments on State and EPA Actions on 

Regional Haze 

C. Comments on State and Federal Roles in 

the Regional Haze Program 

VI. Responses to Comments on EPA’s 

Proposed BART Determinations 

A. Comments on Sundt Generating Station 

Unit 4 

B. Comments on Nelson Lime Plant Kilns 

1 and 2 

C. Comments on the Hayden Smelter 

D. Comments on the Miami Smelter 

VII. Responses to Comments on EPA’s 

Proposed Reasonable Progress 

Determinations 

A. Comments on Phoenix Cement 

Clarkdale Plant 

B. Comments on CalPortland Cement 

Rillito Plant 

C. Comments on Other Reasonable Progress 

NOX Point Sources 

D. Comments on Area Sources of NOX and 

SO2

E. Comments on Reasonable Progress Goals 

and Uniform Rate of Progress 

F. Other Comments on Reasonable Progress 

VIII. Responses to Comments on Statutory 

and Executive Order Reviews 

IX. Responses to Other Comments 

A. Comments on Preamble Language 

B. Comments on Rule Language 

C. Comments on Other Benefits of the 

Regional Haze Program 

D. Miscellaneous Comments 

X. Summary of Final Action 

A. Regional Haze 

B. Interstate Transport 

XI. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory 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 

Concerning Regulations 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 

L. Petitions for Judicial Review 

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 initials CAMD mean or refer to 

Clean Air Markets Division at EPA. 

(8) The initials CBI mean or refer to 

confidential business information. 

(9) The term Class I area refers to a 

mandatory Class I Federal area. 

(10) The initials CEMS refers to continuous 

emission monitoring system or systems. 

(11) The initials CRP mean or refer to 

converter retrofit project. 

(12) The initials dv mean or refer to 

deciview, a measure of visual range. 

(13) The initials DOE mean or refer to 

United States Department of Energy. 

(14) The initials ESECA mean or refer to 

Energy Supply and Environmental 

Coordination Act of 1974. 

(15) The words EPA, we, us or our mean 

or refer to the United States Environmental 

Protection Agency. 

(16) The initials FGD mean or refer to flue 

gas desulfurization. 

(17) The initials FIP mean or refer to 

Federal Implementation Plan. 


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1 77 FR 75704, 75707–75702 (December 21, 2012). 2 74 FR 2392. 

(18) The initials FLM mean or refer to 

Federal Land Managers. 

(19) The initials FUA mean or refer to Fuel 

Use Act of 1978. 

(20) The initials IMPROVE mean or refer to 

Interagency Monitoring of Protected Visual 

Environments monitoring network. 

(21) The initials IPM mean or refer to 

Integrated Planning Model. 

(22) The term lb/MMBtu means or refers to 

pounds per one million British thermal units. 

(23) The initials LDSCR and HDSCR mean 

or refer to low and high dust Selective 

Catalytic Reduction, respectively. 

(24) The initials LNB mean or refer to low 

NOX burners. 

(25) The initials LTS mean or refer to Longterm Strategy. 

(26) The initials MACT mean or refer to 

Maximum Achievable Control Technology. 

(27) The initials MW mean or refer to 

megawatts. 

(28) The initials NAAQS mean or refer to 

National Ambient Air Quality Standard or 

Standards. 

(29) The initials NEI mean or refer to 

National Emissions Inventory. 

(30) The initials NESCAUM mean or refer 

to Northeast States for Coordinated Air Use 

Management. 

(31) The initials NESHAP mean or refer to 

National Emission Standards for Hazardous 

Air Pollutants. 

(32) The initials NOX mean or refer to 

nitrogen oxides. 

(33) The initials NP mean or refer to 

National Park. 

(34) The initials NPS mean or refer to the 

National Park Service. 

(35) The initials NSCR mean or refer to 

Non-Selective Catalytic Reduction. 

(36) The initials NSPS mean or refer to new 

source performance standards. 

(37) The initials OFA mean or refer to Over 

Fire Air. 

(38) The initials PM mean or refer to 

particulate matter. 

(39) The initials PM2.5 mean or refer to fine 

particulate matter with an aerodynamic 

diameter of less than 2.5 micrometers. 

(40) The initials PM10 mean or refer to 

particulate matter with an aerodynamic 

diameter of less than 10 micrometers. 

(41) The initials PSD mean or refer to 

Prevention of Significant Deterioration. 

(42) The initials PTE mean or refer to 

potential to emit. 

(43) The initials RH mean or refer to 

regional haze. 

(44) The initials RHR mean or refer to the 

Regional Haze Rule, originally promulgated 

in 1999 and codified at 40 CFR 51.308–309. 

(45) The initials RMC mean or refer to 

Regional Modeling Center. 

(46) The initials RP mean or refer to 

Reasonable Progress. 

(47) The initials RPG or RPGs mean or refer 

to Reasonable Progress Goal(s). 

(48) The initials SCR mean or refer to 

Selective Catalytic Reduction. 

(49) The initials SIP mean or refer to State 

Implementation Plan. 

(50) The initials SNCR mean or refer to 

Selective Non-catalytic Reduction. 

(51) The initials SO2 mean or refer to sulfur 

dioxide. 

(52) The initials SOFA mean or refer to 

Separated Over Fire Air. 

(53) The initials SRP mean or refer to Salt 

River Project Agricultural Improvement and 

Power District. 

(54) The initials tpy mean tons per year. 

(55) The initials TSD mean or refer to 

Technical Support Document. 

(56) The initials TSF mean or refer to tons 

of stone feed. 

(57) The initials ULNB mean or refer to 

ultra-low NOX burners. 

(58) The initials URP mean or refer to 

Uniform Rate of Progress. 

(59) The initials VOC mean or refer to 

volatile organic compounds. 

(60) The initials VRP mean or refer to 

Visibility Restoration Plan. 

(61) The initials WRAP mean or refer to the 

Western Regional Air Partnership. 

I. Introduction 

The purpose of the Federal and state 

regional haze plans is to achieve a 

national goal, declared by Congress, of 

restoring and protecting visibility at 156 

Federal class I areas across the United 

States, most of which are national parks 

and wilderness areas with scenic vistas 

enjoyed by the American public. The 

national goal as described in CAA 

Section 169A is ‘‘the prevention of any 

future, and the remedying of any 

existing, impairment of visibility in 

mandatory class I Federal areas which 

impairment results from man-made air 

pollution.’’ Arizona has 12 Class I areas, 

including some of the most magnificent 

natural areas in our country. Five other 

Class I areas are close by in neighboring 

states. Please refer to our previous 

rulemaking on the Arizona RH SIP for 

additional background information 

regarding the CAA, regional haze and 

EPA’s RHR.1

EPA has previously acted to approve 

a number of elements of the Arizona RH 

SIP, and to disapprove others. In today’s 

final action, EPA is reducing harmful 

emissions from six facilities that 

contribute to visibility impairment in 17 

protected national parks and wilderness 

areas in Arizona and neighboring states. 

Four of the facilities are subject to Best 

Available Retrofit Technology (BART) 

controls for emissions of nitrogen oxides 

(NOX), sulfur dioxide (SO2), and 

particulate matter (PM). The other two 

facilities are subject to limits on their 

NOX emissions pursuant to the 

Reasonable Progress (RP) provisions of 

the Regional Haze Rule (RHR). The 

BART sources are Sundt Generating 

Station Unit 4, Nelson Lime Plant Kilns 

1 and 2, Hayden Smelter, and Miami 

Smelter. The RP sources are the Phoenix 

Cement Clarkdale Plant Kiln 4 and 

CalPortland Cement Rillito Plant Kiln 4. 

EPA is promulgating this partial FIP 

because we found that Arizona had 

failed to submit a complete RH SIP, and 

later disapproved portions of Arizona’s 

RH SIP for not meeting all the 

requirements of the CAA and EPA’s 

RHR. 

EPA has worked with the owners and 

operators of the facilities regulated by 

today’s rule to ensure we have the most 

up-to-date information for making 

decisions on BART, RP, and the LongTerm Strategy (LTS), the three major 

requirements of the RHR. In today’s 

notice, we respond to comments on our 

proposed rule, present our analysis, and 

indicate where we have made 

adjustments based on the comments and 

additional information. The required 

emission limits, compliance methods, 

and deadlines for compliance in our 

final rule are compatible with each 

facility’s operations, and provide 

sufficient flexibility for achieving 

compliance in a reasonable period of 

time. In several instances we have 

adjusted the emission limits, averaging 

times and/or compliance deadlines in 

response to additional information 

supplied by the facilities’ owners or 

operators. Further, in the case of TEP 

Sundt Unit 4, we have included an 

alternative to BART controls suggested 

by the facility’s owner, which provides 

better emission reductions to improve 

visibility. 

Given the combination of State and 

Federal plans to implement the regional 

haze program in Arizona, EPA and the 

Arizona Department of Environmental 

Quality (ADEQ) must continue to rely 

on their historically strong partnership 

under the CAA to protect the 

environment and human health. We 

would welcome a State plan to replace 

some or all of the Federal plan. 

Moreover, we commit our resources to 

ensuring a successful regional haze 

program for Arizona. EPA estimates 

today’s action will result in annual 

emission reductions of about 2,900 tons/ 

year of NOX and 29,300 tons/year of 

SO2. These reductions are expected to 

benefit at least 17 Class I areas in four 

states, including Arizona. 

II. History of State and Federal Plans 

A. State Submittals and EPA Actions 

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.2 Specifically, EPA found 

that Arizona failed to submit the plan 

elements required by 40 CFR 

51.309(d)(4) and (g). In 2011 ADEQ 

submitted a SIP under section 308 of the 


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3 78 FR 48326. 4 ‘‘Arizona State Implementation Plan, Regional 

Haze under Section 308 of the Federal Regional 

Haze Rule,’’ February 28, 2011. 

5 74 FR 2392–93 (January 15, 2009). 

6 79 FR 9318–9378. 

RHR, but did not withdraw its 309 SIP. 

EPA disapproved Arizona’s 309 SIP 

(with the exception of several smoke 

management rules) on August 8, 2013.3

Both of the Arizona RH SIPs are 

available to review in the docket for this 

final rule.4

As shown in Table 1, 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 

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 tpy. 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. Subsequently, ADEQ 

submitted a supplement to the Arizona 

RH SIP (‘‘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 SIP 

Supplement. Our final rule approving in 

part and disapproving in part the 

Arizona RH SIP was published on July 

30, 2013. In the third phase of our 

action, we proposed a FIP on February 

18, 2014, to address the remaining 

disapproved portions of the State’s plan, 

which we are finalizing today. 

TABLE 1—EPA’S ACTIONS ON THE ARIZONA RH SIP AND FIP 

EPA actions Federal Register 

Proposed rule Final rule 

Phase 1: 

SIP, FIP .............. BART determinations for Apache, Cholla 

and Coronado.

July 20, 2012 (77 FR 42834) ....................... December 5, 2012 (77 FR 

72512). 

Phase 2: 

SIP ...................... Partial approval and partial disapproval of 

remaining elements of the SIP, including 

SIP Supplement.

December 21, 2012 (77 FR 75704), May 

20, 2013 (78 FR 29292).

July 30, 2013 (78 FR 

46142). 

Phase 3: 

FIP ...................... FIP for remaining disapproved elements of 

the SIP.

February 18, 2014 (79 FR 9318) ................. Today’s Final Action. 

B. EPA’s Authority To Promulgate a FIP 

Under CAA section 110(c), EPA is 

required to promulgate a FIP at any time 

within 2 years of the effective date of a 

finding that a state has failed to make a 

required SIP submission or has made an 

incomplete submission, or of the date 

that EPA disapproves a SIP. The FIP 

requirement is terminated only if a state 

submits a SIP, and EPA approves that 

SIP as meeting applicable CAA 

requirements before promulgating a FIP. 

Specifically, CAA section 110(c) 

provides that EPA ‘‘shall promulgate’’ a 

FIP ‘‘at any time within 2 years’’ after 

finding that ‘‘a State has failed to make 

a required submission’’ or that the SIP 

or SIP revision submitted by the State 

does not satisfy the minimum criteria 

established under CAA section 

110(k)(1)(A), or after disapproving a SIP 

in whole or in part ‘‘unless the State 

corrects the deficiency’’ EPA approves 

the plan or plan revision before 

promulgating a FIP. 

Section 302(y) defines the term 

‘‘Federal implementation plan’’ in 

pertinent part, as a plan (or portion 

thereof) promulgated EPA ‘‘to fill all or 

a portion of a gap or otherwise correct 

all or a portion of an inadequacy’’ in a 

SIP, 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). 

In the case of the Arizona RH SIP, two 

different triggering events have occurred 

under section 110(c). EPA has made a 

finding that the State failed to make a 

required submission,5 and we have 

partially disapproved the submissions 

that the State subsequently made. 

Therefore, EPA is required under CAA 

section 110(c) to promulgate a FIP for 

the portions of the Arizona RH SIP that 

we disapproved on July 30, 2013. 

III. Summary of Proposed Rule 

In this section, we provide a summary 

of the proposed rule that was published 

in the Federal Register on February 18, 

2014,6 as background for understanding 

today’s final action. 

A. Regional Haze 

Our proposed rule included proposed 

BART determinations for four sources 

and proposed RP determinations for 

nine sources. These determinations 

resulted in proposed emission limits, 

compliance schedules, and other 

requirements for four BART sources and 

two of the RP sources. The proposed 

regulatory language was included under 

Part 52 at the end of that document. We 

also addressed the reasonable progress 

goals (RPGs), as well as the 

requirements of the LTS. Lastly, we 

proposed that the approved measures in 

the Arizona RH SIP, and measures in 

our previously promulgated FIP and 

proposed FIP, would adequately address 

the interstate transport of pollutants that 

affect visibility. 

1. Proposed BART Determinations 

Sundt Generating Station Unit 4: EPA 

proposed to find that Sundt Unit 4 is 

BART-eligible and subject to BART for 

NOX, SO2, and particulate matter of less 

than 10 micrometers (PM10). For NOX, 

we proposed an emission limit of 0.36 

lb/MMBtu as BART, which is consistent 

with the use of Selective Non-Catalytic 

Reduction (SNCR) as a control 

technology. For SO2, we proposed an 

emission limit of 0.23 lb/MMBtu as 

BART on a 30-day boiler operating day 

(BOD) rolling basis, which is consistent 

with the use of dry sorbent injection 

(DSI) as a control technology. For PM10, 

we proposed a filterable PM10 emission 

limit of 0.030 lb/MMBtu as BART based 

on the use of the unit’s existing fabric 

filter baghouse. We also proposed a 

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

controls for all three pollutants. 

Nelson Lime Plant Kilns 1 and 2: EPA 

proposed to find that Nelson Lime Kilns 

1 and 2 are subject to BART for NOX, 

SO2, and PM10. For NOX, we proposed 

a BART emission limit at Kiln 1 of 3.80 


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7National Emission Standard for Hazardous Air 

Pollutants for Primary Copper Smelting at 40 CFR 

Part 63. 

8 40 CFR 51.308(d)(1)(ii). 

9See proposed actions at 77 FR 75727–75730, 78 

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

10 40 CFR 51.308(d)(1)(ii). 

11 78 FR 46172. 

12See 78 FR 46173 (codified at 40 CFR 

52.145(e)(ii)). 

lb/ton of lime and at Kiln 2 of 2.61 lb/ 

ton of lime on a 30-day rolling basis as 

verified by continuous emission 

monitoring systems (CEMS). These 

emission limits are consistent with the 

use of low-NOX burners (LNB) and 

SNCR as control technologies. We 

proposed that BART for SO2 is an 

emission limit of 9.32 lb/ton of lime for 

Kiln 1 and 9.73 lb/ton of lime for Kiln 

2 on a 30-day rolling basis, which is 

consistent with the use of a lower sulfur 

fuel blend. For PM10, we proposed a 

BART emission limit of 0.12 lb/tons of 

stone feed (TSF) at Kilns 1 and 2 based 

on the use of the unit’s existing fabric 

filter baghouses. 

Hayden Smelter: EPA proposed that 

the Hayden Smelter is subject to BART 

for NOX, and we proposed BART 

emission limits for NOX and SO2. We 

previously approved the State’s 

determination that the Hayden Smelter 

is subject to BART for SO2, but 

disapproved the State’s SO2 BART 

determination. For NOX, we proposed 

an annual emission limit of 40 tons per 

year (tpy) of NOX emissions from the 

BART-eligible units, which is consistent 

with current emissions from these units. 

For SO2 from the converters, we 

proposed 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 proposed a work practice 

standard requiring that the furnaces be 

charged only 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 proposed to 

incorporate the emission limits and 

associated compliance requirements of 

the Maximum Achievable Control 

Technology (MACT),7 Subpart QQQ, as 

part of the LTS. 

Miami Smelter: EPA proposed that the 

Miami Smelter is subject to BART for 

NOX, and we proposed BART emission 

limits for NOX and SO2. EPA previously 

approved the State’s determination that 

the Miami Smelter is subject to BART 

for SO2, but disapproved the State’s SO2

BART determination. For NOX, we 

proposed an annual emission limit of 40 

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

current emissions. For SO2 from the 

converters, we proposed 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 Subpart QQQ 

requirements to the capture systems. For 

SO2 emissions from the electric furnace, 

we proposed as BART a work practice 

standard to prohibit active aeration. We 

previously approved Arizona’s 

determination that BART for PM10 at the 

Miami Smelter is the MACT for Primary 

Copper Smelting. We proposed to find 

that the federally enforceable provisions 

of the MACT, which apply to the Miami 

Smelter and are incorporated into its 

Title V Permit, are sufficient to ensure 

the enforceability of this determination. 

2. Proposed RP Determinations 

Point Sources of NOX: EPA conducted 

source-specific RP analyses of potential 

NOX controls for non-BART units at 

nine different sources. Based on these 

analyses, we proposed to require 

controls on two cement kilns: PCC 

Clarkdale Kiln 4 and CPC Rillito Kiln 4. 

Specifically, EPA proposed an emission 

limit of 2.12 lb/ton on Kiln 4 of the 

Clarkdale Plant based on a 30-day 

rolling average, which is consistent with 

SNCR as a control technology. We 

proposed an emission limit of 2.67 lb/ 

ton on Kiln 4 of the Rillito Plant based 

on a 30-day rolling average, which also 

is consistent with SNCR as a control 

technology. We also requested comment 

on the possibility of requiring a rolling 

12-month limit on NOX emissions in 

lieu of a lb/ton emission limit at these 

facilities. For the remaining seven 

sources, as well as other units at CPC, 

we proposed to find that it was 

reasonable not to require NOX controls 

during this planning period. These 

sources are the CPC Rillito Plant (Kilns 

1–3); Arizona Public Service (APS) 

Cholla (Unit 1); El Paso Natural Gas 

(EPNG) Tucson, Flagstaff, and Williams 

Compressor Stations; TEP Sundt (Units 

1–3); Ina Road Sewage Plant; and TEP 

Springerville (Units 1 and 2). 

Area Sources of NOX and SO2: We 

proposed to find that it is reasonable not 

to require additional controls on area 

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. While the 

State’s area sources currently contribute 

a relatively small percentage of the 

visibility impairment at impacted Class 

I areas, we recommended better 

emission inventories and an improved 

RP analysis in the next planning period 

for area sources. 

Reasonable Progress Goals: EPA 

proposed RPGs consistent with a 

combination of control measures that 

include those in the approved portion of 

the Arizona RH SIP and in EPA’s 

finalized and proposed FIPs. While not 

quantifying a new set of RPGs based on 

these control measures, we proposed 

that it is reasonable to assume improved 

levels of visibility at Arizona’s 12 Class 

I areas by 2018 because the measures in 

the FIPs produce emissions reductions 

that are significantly beyond those 

required by the State. 

Demonstration of Reasonable 

Progress: EPA proposed to find that it is 

reasonable not to provide for rates of 

progress at the 12 Class I areas 

consistent with the uniform rate of 

progress (URP) in this planning period.8

We also proposed to find that the RP 

analyses underlying our actions on the 

Arizona RH SIP 9 and FIP are sufficient 

to demonstrate that it is reasonable not 

to provide for rates of progress in this 

planning period that would attain 

natural conditions by 2064.10 Lastly, we 

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 SO2.11

3. Long-Term Strategy 

EPA proposed to find that provisions 

in the Arizona RH SIP and FIP 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 outof-state Class I areas, emission 

limitations and schedules for 

compliance to achieve the RPGs, and 

enforceability provisions for emission 

limitations and control measures.12 We 

proposed to promulgate emission limits, 

compliance schedules, and other 

requirements for four BART sources and 

two RP sources to complete this part of 

the FIP for these requirements. 

B. Interstate Transport of Pollutants 

That Affect Visibility 

We have proposed 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 


emcdonald on DSK67QTVN1PROD with RULES2
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13 78 FR 46142 (July 30, 2013). 

14 79 FR 9318 (February 18, 2014). 15 40 CFR part 63 subpart QQQ. 

provisions to prohibit emissions that 

will interfere with other states’ required 

measures to protect visibility. We refer 

to this as the interstate transport 

visibility requirement. 

IV. Overview of Final Action 

We are promulgating a FIP to address 

the remaining disapproved portions of 

the Arizona RH SIP.13 We include in 

Section V below a summary of our 

responses to comments on our proposed 

FIP,14 and describe where comments 

resulted in revisions to the proposal. In 

this section, we provide a summary of 

the final BART determinations, RP 

determinations, RPGs and 

demonstration, LTS provisions, and 

interstate transport provisions of the 

FIP. This final FIP also includes 

emission limits, compliance schedules 

and requirements for equipment 

maintenance, monitoring, testing, 

recordkeeping, and reporting for all 

affected sources and units. The final 

regulatory language for the FIP is under 

Part 52 at the end of this notice. 

A. BART Determinations 

EPA conducted BART analyses and 

determinations for four sources: Sundt 

Generating Station Unit 4, Nelson Lime 

Plant Kilns 1 and 2, the Hayden 

Smelter, and the Miami Smelter. The 

final BART determinations are listed in 

Table 2, comparing the final limits to 

the proposed limits with short 

descriptions of changes in the footnotes. 

The exact compliance deadlines will be 

calculated based upon the date that this 

document is published in the Federal 

Register, which we anticipate will occur 

sometime in July 2014. 

Sundt Generating Station: In this final 

rule, we have retained the BART 

determination and the final BART 

emission limits as proposed, as well as 

the option of a better-than-BART 

alternative that was submitted by TEP. 

Although the final BART determination 

and limits are the same, we have made 

some changes to the better-than-BART 

alternative based on comments and 

additional information. 

Regarding BART, we are finalizing 

our determination that Sundt Unit 4 is 

BART-eligible and subject to BART for 

SO2, NOX, and PM10. The final BART 

emission limits are the same as 

proposed. The NOX emission limit is 

0.36 lb/MMBtu, which is equivalent to 

using SNCR with the existing LNB as 

control technologies. The SO2 emission 

limit is 0.23 lb/MMBtu on a 30-day BOD 

rolling basis, which is consistent with 

using DSI as a control technology. The 

PM10 emission limit is 0.030 lb/MMBtu 

based on the use of the existing fabric 

filter baghouse. Compliance is required 

within three years of the publication of 

this notice in the Federal Register, also 

as proposed. 

Regarding the better-than-BART 

alternative to switch to natural gas, we 

are finalizing the proposed emission 

limit for NOX of 0.25 lb/MMBtu, but 

revising the SO2 and PM10 emission 

limits. The final SO2 limit is increased 

from 0.00064 to 0.054 lb/MMBtu to 

allow for continued co-firing with 

landfill gas that has a higher sulfur 

content than pipeline natural gas. The 

final PM10 limit relies on a performance 

test due to the uncertainties related to 

switching from coal to gas, which now 

includes measuring condensable, in 

addition to filterable, PM10. Further, we 

have extended the final compliance 

deadline by six months to December 31, 

2017, consistent with the date that TEP 

initially included in its better-thanBART proposal. TEP is required to 

notify EPA regarding its selection of 

BART or the alternative by March 2017. 

Nelson Lime Plant: EPA is finalizing 

its determination that Nelson Lime 

Plant Kilns 1 and 2 are subject to BART 

for NOX, SO2, and PM10. We have 

revised the final emission limits for 

NOX and SO2 to account for startup and 

shutdown emissions, which were not 

considered in LNA’s original BART 

analysis that was submitted to EPA for 

consideration. This change to the 

emission limits for NOX and SO2 does 

not change the corresponding control 

technologies, which are still SNCR and 

lower sulfur fuel, respectively. The final 

BART emission limit for PM10 is 0.12 lb/ 

ton for each kiln as proposed, 

equivalent to using the existing 

baghouse. 

We are making the following revisions 

to the NOX limits in response to 

comments received on our proposal. 

First, we are revising the averaging time 

for the lb/ton limits to a 12-month 

rolling average instead of a 30-day 

rolling average. The longer 12-month 

averaging time should even out the 

emission spikes from startup and 

shutdown events that would more 

significantly influence a 30-day average. 

Second, we are requiring an 

optimization plan to assess the final 

BART emission limit for NOX based on 

a 12-month rolling average, which is 

3.80 lb/ton for Kiln 1 and 2.61 lb/ton for 

Kiln 2. Third, we are adding a combined 

limit for Kilns 1 and 2 of 3.27 tons/day 

on a 30-day rolling average to ensure 

short-term visibility protection. Both 

compliance methods (lb/ton at each kiln 

as optimized and tons/day for both 

kilns) are equivalent to using SNCR 

control technology. The compliance 

deadline for the final NOX emission 

limit is three years from the publication 

date, as proposed. 

We are making the following revisions 

to the SO2 limits in response to 

comments received on our proposal. 

First, as with the final limit for NOX, we 

are revising the averaging time for the 

lb/ton limits to a 12-month rolling 

average instead of a 30-day rolling 

average to account for emission spikes 

from startup and shutdown events that 

would more significantly influence a 30- 

day average. The final BART emission 

limits for SO2 are 9.32 lb/ton for Kiln 1 

and 9.73 lb/ton for Kiln 2, as proposed. 

Second, we are adding a combined limit 

for Kilns 1 and 2 of 10.1 tons/day to 

ensure short-term visibility protection. 

Both compliance methods (lb/ton at 

each kiln and tons/day at both kilns) are 

equivalent to using lower sulfur fuel, as 

proposed. Finally, we have extended the 

compliance deadline for meeting the 

final limit for SO2 from six to 18 months 

to allow sufficient time for installation 

of monitoring equipment to demonstrate 

compliance with the new limits. 

Hayden Smelter: EPA is finalizing its 

determination that the Hayden Smelter 

is subject to BART for NOX. We 

previously approved the State’s 

determination that the Hayden Smelter 

is subject to BART for SO2 and PM10, 

and the State’s determination that BART 

for PM10 is equivalent to existing 

controls. The final BART emission limit 

for NOX is 40 tpy and applies to the 

converters and anode furnaces. The 

NOX limit is consistent with current 

emissions and is the same as proposed. 

The final BART emission limit for SO2

from the anode furnaces is equivalent to 

existing controls, as proposed. For PM10, 

we are incorporating by reference 

provisions of the National Emission 

Standards for Hazardous Air Pollutants 

(NESHAP) for primary copper 

smelters 15 to ensure that Arizona’s 

BART determination is made 

enforceable, as part of the LTS. 

We are making a number of revisions 

to the proposed SO2 emission limits 

from the converters in response to 

comments. For SO2 emissions from the 

converters, the final BART emission 

limits are a 99.8 percent control 

efficiency on a 365-day rolling average 

for the primary capture system, and a 

98.5 percent control efficiency on a 365- 

day rolling average for the secondary 

capture system. The BART limit for the 

primary capture system corresponds to 

the existing double contact acid plant, 

whereas the limit for the secondary 

capture system is equivalent to a new 


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16 40 CFR part 63 subpart QQQ. 

amine scrubber as a control technology. 

We have revised our proposal by 

applying separate limits to the primary 

and secondary capture systems in 

recognition of significant differences in 

flow volume and SO2 concentration 

between the two systems. We revised 

the averaging time from 30 to 365 days 

for the primary capture system in 

recognition that the control efficiency is 

based on annual acid production and 

annual SO2 emissions. In addition, we 

are finalizing a work practice standard 

requiring that the primary and 

secondary capture systems be designed 

and operated to maximize capture of 

SO2 emissions from the converters. 

The final compliance deadline for the 

primary capture and control system to 

meet the SO2 limit is three years from 

publication, as proposed. The final 

deadlines for the NOX and PM10 limits 

are also three years from publication. 

However, we extended the final 

compliance deadline to meet the SO2

limit for the secondary capture and 

control system from three to four years 

from publication to provide sufficient 

time to plan and build a new amine 

scrubber. 

Miami Smelter: EPA is finalizing its 

determination that the Miami Smelter is 

subject to BART for NOX. We previously 

approved the State’s determination that 

the Miami Smelter is subject to BART 

for SO2 and PM10, and the State’s 

determination that BART for PM10 is 

equivalent to the National Emission 

Standard for Hazardous Air Pollutants 

(NESHAP) for primary copper smelters. 

The final BART emission limit for NOX

is 40 tpy that applies to the converters 

and electric furnace. The NOX limit 

represents current emissions and is the 

same as proposed. For SO2 from the 

electric furnace, the final BART 

emission limit is the existing work 

practice standard to prohibit active 

aeration. For PM10, we are incorporating 

by reference provisions of the NESHAP 

for primary copper smelters 16 to ensure 

that Arizona’s BART determination is 

made enforceable, as part of the LTS. 

For SO2 from the converters, the final 

BART emission limit is a control 

efficiency of 99.7 percent on a 365-day 

rolling average applied to the combined 

primary and secondary capture systems 

on a cumulative mass basis. While the 

control efficiency of 99.7 percent is the 

same as proposed, we revised the 

compliance method from a 30-day 

average to a 365-day rolling average. We 

revised the averaging time in response 

to FMMI’s comment that the control 

efficiency is based on annual acid 

production and annual SO2 emissions. 

The 99.7 percent control efficiency is 

equivalent to improvements to the 

primary control system (existing acid 

plant with a tailstack scrubber) and 

construction of new secondary capture 

and control systems. In addition, we are 

finalizing a work practice standard 

requiring that the primary and 

secondary capture systems be designed 

and operated to maximize capture of 

SO2 emissions from the converters. 

The final compliance deadlines for 

SO2 from the electric furnace as well as 

the NOX and PM10 limits, are two years 

from the date of the document’s 

publication. However, we extended the 

final compliance deadline for SO2 from 

the converters to January 1, 2018, to 

provide sufficient time to plan and 

build a new secondary capture and 

control system. We also added a 

compliance option for the secondary 

capture system to use either CEMS or to 

calculate emissions based on the 

amount of reagent added to the 

scrubber, because it may be impractical 

to operate CEMS on the inlet of a new 

scrubber. 

TABLE 2—FINAL EMISSION LIMITS ON BART SOURCES

Source Units Pollutants Proposed 

limit 

Final 

limit Measure Corresponding control technology 

Sundt Generating 

Station.

Unit 4 ....................... NOX

SO2

PM10

0.36 

0.23 

0.030 

Same ..........

Same ..........

Same ..........

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 

Same ..........

0.054.a

Test.b

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

Nelson Lime Plant ... Kiln 1 ....................... NOX 3.80 Same c ........

3.27 ............

lb/ton d ...............

tons/day e

Selective Non-Catalytic Reduction. 

SO2 9.32 Same ..........

10.1 ............

lb/ton.d ..............

tons/day.e

Lower sulfur fuel. 

PM10 0.12 Same .......... lb/ton ................. Fabric filter baghouse (existing). 

Kiln 2 ....................... NOX 2.61 Same c ........

3.27 ............

lb/ton d ...............

tons/day.e

Selective Non-Catalytic Reduction. 

SO2 9.73 Same ..........

10.1 ............

lb/ton d ...............

tons/day.e

Lower sulfur fuel. 

PM10 0.12 Same .......... lb/ton ................. Fabric filter baghouse (existing). 

Hayden Smelter ....... All BART Units ......... NOX 40 Same .......... tpy ..................... None. 

Converters 1, 3–5 .... SO2 99.8 99.8 ............ Control efficiency.Primary capture: Double contact 

acid plant (existing). 

98.5 f ........... ........................... Secondary capture: New amine 

scrubber. 

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

Miami Smelter .......... All BART Units ......... NOX 40 Same .......... tpy ..................... None. 

Converters 2–5 ........ SO2 99.7 Same .......... Control efficiency.Improve primary and new secondary capture systems, additional controls as needed. 

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

aFinal limit revised to accommodate co-firing with landfill gas that has higher sulfur content. 

bFinal limit is based on result of initial performance test. 

cFinal limit includes a requirement for SNCR optimization plan. 

dFinal limit is based on rolling 12-month average instead of rolling 30-day average. 

eFinal limit is combined for Kilns 1 and 2 with compliance based on a rolling 30-day average. 

fFinal limit is separate for primary and secondary capture systems. 


emcdonald on DSK67QTVN1PROD with RULES2
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17 40 CFR 51.308(d)(1)(ii). 

18 77 FR 75512–72580, December 5, 2012. 

19 40 CFR 51.308(d)(3)(ii), (v)(C) and (v)(F). 

20See 78 FR 46173 (codified at 40 CFR 

52.145(e)(ii)). 

B. Reasonable Progress Determinations 

Point Sources of NOX: EPA is 

finalizing its determination that PCC 

Clarkdale Plant Kiln 4 and CPC Rillito 

Plant Kiln 4 are subject to NOX emission 

controls under the RP requirements of 

the RHR as shown in Table 3. We also 

are finalizing our determination that it 

is reasonable not to require controls at 

this time on NOX emissions from the 

other seven sources that we evaluated 

for RP as well as other units at the 

Rillito Plant. These sources are the CPC 

Rillito Plant (Kilns 1–3); APS Cholla 

(Unit 1); El Paso Natural Gas (EPNG) 

Tucson, Flagstaff, and Williams 

Compressor Stations; TEP Sundt (Units 

1–3); Ina Road Sewage Plant; and TEP 

Springerville (Units 1 and 2). 

Clarkdale Plant Kiln 4: PCC has two 

options for meeting the RP 

requirements. It can choose to meet 

either a lb/ton limit or tons/year limit 

for NOX. The final NOX limit for the first 

option is the proposed 2.12 lb/ton with 

a requirement for an SNCR optimization 

plan. The final lb/ton NOX limit is based 

on a 30-day rolling average consistent 

with SNCR as a control technology. The 

second option is an 810 tons/year NOX

limit that is achievable by installing 

SNCR or maintaining clinker production 

at current levels. The 810 tons/year 

limit is based on a 12-month rolling 

average equivalent to a 50 percent 

reduction in baseline emissions. PCC 

must notify EPA of the option it has 

selected no later than July 2018 with a 

compliance deadline of December 31, 

2018. 

Rillito Plant Kiln 4: The final RP 

emission limit for NOX is 3.46 lb/ton 

based on a 35 percent control efficiency. 

We have increased the final limit from 

the proposed 2.67 lb/ton that was based 

on a 50 percent control efficiency in 

response to additional information from 

CPC regarding constraints on efficiency 

due to the kiln design. In addition, we 

are requiring implementation of an 

SNCR optimization plan to determine if 

a higher control efficiency is achievable. 

The final NOX limit is based on a 30- 

day rolling average and is consistent 

with SNCR as a control technology. The 

compliance deadline is December 31, 

2018, the same as proposed. 

TABLE 3—FINAL EMISSION LIMITS ON RP SOURCES

Source Units Pollutants Proposed 

limit Final limit Measure Corresponding control technology 

Clarkdale Plant ...... Kiln 4 ................ NOX .................. 2.12 Same a ............. lb/ton ................ Selective Non-Catalytic Reduction. 

810 Same b ............. tons/year .......... Current Production Levels. 

Rillito Plant ............. Kiln 4 ................ NOX .................. 2.67 3.46 c ................ lb/ton ................ Selective Non-Catalytic Reduction. 

aFinal limit includes a requirement for SNCR optimization plan. 

bFinal limit for second option is in tons/year in lieu of lb/ton. 

cFinal limit includes a requirement for SNCR optimization plan. 

Area Sources of NOX and SO2: EPA is 

finalizing its determination that it is 

reasonable not to require additional 

controls on Arizona’s area sources at 

this time. Area source categories such as 

distillate fuel oil combustion in boilers 

and internal combustion engines as well 

as residential natural gas combustion 

currently contribute a relatively small 

percentage of the visibility impairment 

at Class I areas, but should be 

considered for controls in future 

planning periods. 

C. Reasonable Progress Goals and 

Demonstration 

Reasonable Progress Goals: EPA is 

quantifying our proposed RPGs (in 

deciviews) for the 20 percent worst days 

and 20 percent best days in 2018. The 

RPGs for Arizona’s 12 Class I areas 

account for the emission reductions 

from BART and RP control measures in 

the final RH FIP. The RPGs reflect the 

results of our BART analyses and our RP 

analysis of point sources of NOX and 

area sources of NOX and SO2 as 

described in our proposal and in 

response to comments in today’s final 

rule. The RPGs also include the effects 

of the three BART determinations 

finalized in our Phase 1 FIP and the 

effects of other existing State and 

Federal controls. Today’s final RPGs 

provide for an improvement in visibility 

on the worst days and no degradation in 

visibility on the best days during this 

planning period. 

Demonstration of Reasonable 

Progress: EPA’s final determination is 

that it is not reasonable to provide for 

rates of progress at Arizona’s 12 Class I 

areas that would attain natural visibility 

conditions by 2064 (i.e., the URP).17 Our 

demonstration that a slower rate of 

progress is reasonable is based on the 

RP analyses performed by us and the 

State that considered the four statutory 

RP factors. Although progress is slower 

than the URP, the FIP provides for RPGs 

that reflect an improved rate of progress 

and a significantly shorter time period 

to reach natural visibility conditions at 

each of Arizona’s Class I areas, 

compared with the RPGs in the Arizona 

RH SIP. 

D. Long-Term Strategy 

EPA is finalizing its determination 

that provisions in this final rule in 

combination with provisions in the 

approved Arizona RH SIP and the Phase 

1 Arizona RH FIP 18 fulfill the 

requirements for the LTS.19 In this final 

rule, we are promulgating emission 

limits, compliance schedules and other 

requirements for four BART sources and 

two RP sources. This final action 

completes the LTS measures needed to 

achieve emission reductions for out-ofstate Class I areas, emission limitations 

and schedules for compliance to achieve 

the RPGs, and enforceability of emission 

limitations and control measures.20 In 

particular, as explained above, we are 

incorporating by reference provisions of 

the NESHAP for primary copper 

smelters to ensure that Arizona’s BART 

determinations for PM10 at the Hayden 

and Miami Smelters are made 

enforceable and are included in the 

applicable implementation plan. 

E. Interstate Visibility Transport 

EPA is finalizing its determination 

that the control measures in the Arizona 

RH SIP and FIP are adequate to prevent 

Arizona’s emissions from interfering 

with other states’ required measures to 

protect visibility. Thus, the combined 

measures from both plans satisfy the 

interstate transport 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. In our final rule published on 

July 30, 2013, EPA disapproved these 


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Federal Register / Vol. 79, No. 170 / Wednesday, September 3, 2014 / Rules and Regulations 52427 

21 78 FR 46142, July 30, 2013. 

22NRDC v. EPA, 2014 U.S. App. LEXIS 7281 (D.C. 

Cir.). 

23 Id. at 24 (arguments that violations were caused 

by unavoidable technology failure can be made to 

the courts in future civil cases when the issue 

arises). 

24Comments were provided by Earthjustice on 

behalf of the National Parks Conservation 

Association, Sierra Club, San Juan Citizens 

Alliance, and Arizona Chapter of Physicians for 

Social Responsibility. 

25 78 FR 46142. 

26 78 FR 48326. 

SIP submittals with respect to the 

interstate transport visibility 

requirement for each of these NAAQS, 

triggering the obligation for EPA to 

promulgate a FIP.21

F. Other Changes From Proposal 

Our proposed regulatory text 

incorporated by reference certain 

provisions of the Arizona 

Administrative Code that establish an 

affirmative defense for excess emissions 

due to malfunctions. We did not receive 

any comments on this aspect of our 

proposal. Following the close of the 

public comment period, the United 

States Court of Appeals for the D.C. 

Circuit issued a decision concerning 

various aspects of the NESHAP for 

Portland cement plants issued by EPA 

in 2013, including the affirmative 

defense provision of that rule.22 The 

court found that EPA lacked authority to 

establish an affirmative defense for 

private civil suits and held that under 

the CAA, the authority to determine 

civil penalty amounts lies exclusively 

with the courts, not EPA. The court did 

not address whether such an affirmative 

defense provision could be properly 

included in a SIP. However, the court’s 

holding makes it clear that the CAA 

does not authorize promulgation of such 

a provision by EPA. In particular, the 

court’s decision turned on an analysis of 

CAA sections 113 (‘‘Federal 

enforcement’’) and 304 (‘‘Citizen suits’’). 

These provisions apply with equal force 

to a civil action brought to enforce the 

provisions of a FIP. The logic of the 

court’s decision thus applies to the 

promulgation of a FIP and precludes 

EPA from including an affirmative 

defense provision in a FIP. Therefore, 

we are not including an affirmative 

defense provision in the final FIP. 

We note that, if a source is unable to 

comply with emission standards as a 

result of a malfunction, EPA may use 

case-by-case enforcement discretion, as 

appropriate. Further, as the D.C. Circuit 

recognized in an EPA or citizen 

enforcement action, the court has the 

discretion to consider any defense 

raised and determine whether penalties 

are appropriate.23

V. Responses to General Comments 

A. Introduction 

EPA provided 60 days for the public 

to submit comments on the proposed 

rule, with the comment period 

concluding on March 31, 2014. We held 

two public hearings in Arizona, one on 

February 25, 2014, in Phoenix and 

another on February 26, 2014, in 

Tucson. The deadline for public 

comments was March 31, 2014. 

Certified records of the public hearings, 

written comments (excluding any 

confidential business information (CBI) 

materials), a summary of comments, and 

a list of commenters are available in the 

docket for this final action. We received 

a total of 24 written comments from 

industry or industrial associations (13), 

environmental groups (6), citizens (3), a 

state agency (1), and a federal agency 

(1). In addition, 14 individuals 

presented oral testimony at the two 

hearings. Summaries of significant 

comments and EPA’s responses, 

organized by subject matter, are 

provided in the following sections. 

Because we received no comments 

regarding the LTS or interstate transport 

provisions of the FIP, there is no section 

in this notice addressing comments on 

these topics. 

We are using the following acronyms 

to refer to representatives of the 

following entities who submitted 

comments to us: 

• ACCCE—American Coalition for 

Clean Coal Energy 

• ADEQ—Arizona Department of 

Environmental Quality 

• AMA—Arizona Mining Association 

• ANGA—America’s Natural Gas 

Alliance 

• ASARCO—American Smelting and 

Refining Company 

• CPC—CalPortland Company 

• Earthjustice 24

• EPNG—El Paso Natural Gas Company 

• FMMI—Freeport-McMoRan Miami, 

Inc. 

• LNA—Lhoist North America of 

Arizona 

• NMA—National Mining Association 

• NPS—National Park Service 

• PCC—Phoenix Cement Company 

• PSR—Physicians for Social 

Responsibility 

• TEP—Tucson Electric Power 

• TPMEC—Tucson Pima Metropolitan 

Energy Commission 

B. Comments on State and EPA Actions 

on Regional Haze 

Comment: One commenter, a former 

member of the Technical Oversight 

Committee of the Western Regional Air 

Partnership (WRAP), recounted the 

history of the Grand Canyon Visibility 

Transport Commission and the WRAP, 

and their efforts under section 309 of 

the original RHR to develop emission 

reduction milestones through 2018 for 

SO2 emissions from large industrial 

sources in the nine-state Commission 

Transport Region that affects the 

Colorado Plateau. The commenter noted 

that Arizona ultimately withdrew from 

the section 309 process, but asserted 

that the State’s withdrawal should not 

negate the effort of setting the 

milestones and the agreements reached 

during that process. The commenter 

asserted that by rejecting Arizona’s SIP 

and proposing a FIP, EPA has gone 

beyond what was agreed on as a 

reasonable expectation of BART for 

specific groups of sources, such as 

smelters, utilities, and cement plants. 

The commenter added that the new SO2

NAAQS will require plants to make 

changes that go well beyond BART. 

Therefore, BART should be set at a level 

no more stringent than what WRAP 

proposed so as not to interfere with any 

plans for the nonattainment areas to 

come into compliance with the new SO2

standard. 

Response: These comments largely 

pertain to EPA’s partial disapproval of 

Arizona’s 308 RH SIP and are therefore 

untimely, as EPA has already taken final 

action on the SIP.25 Furthermore, EPA 

has already disapproved the majority of 

Arizona’s 309 RH SIP.26 As explained 

further below in response to similar 

comments regarding the Hayden and 

Miami Smelters, this FIP will not 

adversely impact the smelters’ ability to 

come into compliance with the 1-hour 

SO2 NAAQS. 

C. Comments on State and Federal 

Roles in the Regional Haze Program 

Comment: Several commenters 

(ADEQ, FMMI, AMA, ACCCE and 

NMA) do not agree with EPA’s partial 

disapproval of Arizona’s RH SIP, 

asserting that EPA has overstepped its 

boundaries by unnecessarily imposing a 

FIP. Some of the commenters contend 

that states are best suited to make BART 

determinations, not EPA. 

ADEQ noted that the RHR is not 

intended to protect public health, but to 

address visibility problems. In the 

commenter’s opinion, EPA should have 

given the State of Arizona the 


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52428 Federal Register / Vol. 79, No. 170 / Wednesday, September 3, 2014 / Rules and Regulations 

27 77 FR 72568–69 (December 5, 2012). 

28Brief of Respondent, Arizona v. EPA, No. 13– 

70366 (9th Cir. Dec. 12, 2013) (EPA Phase 1 Brief) 

at 66–77. 

29 74 FR 2392–93 (January 15, 2009). 

30National Parks Conservation Association v. 

Jackson (D.D.C. Case 1:11–cv–01548). 

31Nat’l Parks Conservation Ass’n 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), Minute 

Order (February 15, 2013), Order (September 6, 

2013), and Stipulation to Amend Consent Decree 

(November 14, 2013). On appeal, the D.C. Circuit 

upheld the District Court’s finding that it lacked 

jurisdiction over Arizona’s objections. Nat’l Parks 

Conservation Ass’n v. EPA, 43 ELR 20266 (D.C. Cir. 

2013). 

32 77 FR 72512 (December 5, 2012). 

33 77 FR 75704 (December 21, 2012). 

34 78 FR 29292 (May 20, 2013). 

35 78 FR 46142 (July 30, 2013). 

36 78 FR 48326 (August 8, 2013). 

37See EPA v. EME Homer City Generation, 134 

S. Ct. 1584 (2014), Slip. Op. at 16 (‘‘After EPA has 

disapproved a SIP, the Agency can wait up to two 

years to issue a FIP . . . But EPA is not obliged to 

wait two years or postpone its action even a single 

day: The Act empowers the Agency to promulgate 

a FIP ‘at any time’ within the two-year limit.’’). 

opportunity to correct specific issues in 

the SIP, instead of proceeding with a 

FIP. Citing to CAA section 110(c), ADEQ 

asserted that EPA should end this 

rulemaking and allow ADEQ a period of 

up to two years to correct any 

deficiencies in its RH SIP. ACCCE 

discussed the history of the regional 

haze program and emphasized the 

discretion provided to states under the 

CAA and the RHR. FMMI stated that 

EPA lacks the authority to disapprove a 

SIP and promulgate the proposed FIP 

based on its policy disagreements with 

a state. AMA and NMA asserted that 

EPA had overstepped its boundaries and 

should leave the decision of what 

constitutes BART and reasonable 

progress to the State of Arizona. NMA 

proceeded to argue that this is not the 

first example of EPA going beyond its 

authority as it relates to regional haze, 

since it has replaced the regional haze 

determinations of 14 states with its own 

federal requirements. NMA went on to 

say that in the case of the Arizona RH 

SIP, EPA disapproved parts of the plan 

due to its own subjective opinion and 

not because the SIP was inconsistent 

with the requirements of the CAA. 

Response: To the extent these 

comments pertain to EPA’s partial 

disapproval of the Arizona RH SIP or 

other previous SIP actions, they are 

untimely. To the extent that the 

comments are relevant to the proposed 

FIP, we do not agree with their 

substance. While it is our strong 

preference that state plans implement 

CAA requirements, there are 

circumstances in which a FIP is 

required by the Act. As explained in 

response to comments on the Phase 1 

Final Rule 27 and our legal brief 

responding to petitions for review of 

that rule,28 we are required by the CAA 

to issue a FIP to meet all requirements 

of the RHR not addressed by an 

approved SIP revision. In particular, 

CAA section 110(c) requires EPA to 

promulgate a FIP at any time within two 

years of (1) finding that a State has 

failed to make a required submission, or 

(2) disapproving a State submission in 

whole or in part. This obligation is 

eliminated only if ‘‘the State corrects the 

deficiency, and the Administrator 

approves the plan or plan revision, 

before the Administrator promulgates 

such Federal Implementation plan.’’ In 

this instance, two different triggering 

events under section 110(c) have 

occurred: EPA has made a finding that 

the State failed to make a required 

submission and has partially 

disapproved the submissions that the 

State subsequently made. 

EPA found that Arizona had failed to 

submit a comprehensive regional haze 

SIP in January 2009, which triggered an 

obligation for EPA to promulgate a FIP 

within two years, unless the State first 

submitted and EPA approved a regional 

haze SIP.29 When EPA failed to either 

approve a SIP or promulgate a FIP by 

the January 2011 deadline, we were 

sued by a group of conservation 

organizations.30 In order to resolve this 

lawsuit, EPA entered into a Consent 

Decree that established deadlines for 

action on regional haze plans for various 

states, 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.31 Under the terms of the 

Consent Decree, as amended, EPA was 

subject to three sets of deadlines for 

taking action on the Arizona RH SIP as 

listed in Table 4. The specific 

deficiencies that commenters claim to 

have identified in EPA’s proposal are 

addressed in subsequent responses. 

TABLE 4—CONSENT DECREE DEADLINES FOR EPA TO ACT ON THE ARIZONA RH SIP AND FIP 

EPA actions Proposed rule 

signature date 

Final rule signature 

date 

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

Phase 2—All remaining elements of the Arizona RH SIP .............................................................. December 8, 2012 c .. July 15, 2013.d

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

aPublished in the Federal Register on July 20, 2012, 77 FR 42834. bPublished in the Federal Register on December 5, 2012, 77 FR 72512. cPublished in the Federal Register on December 21, 2012, 77 FR 75704. dPublished in the Federal Register on July 30, 2013, 78 FR 46142. Also addresses supplemental proposal published in the Federal Register 

on May 20, 2013, 78 FR 29292. ePublished in the Federal Register on February 18, 2014. 

In Phase 1, EPA approved in part and 

disapproved in part Arizona’s BART 

determinations for Apache Generating 

Station, Cholla Power Plant, and 

Coronado Generating Station, and 

promulgated a FIP addressing the 

disapproved portions of the SIP.32 In 

our initial Phase 2 proposal, EPA 

proposed to approve in part and 

disapprove in part the remainder of the 

Arizona RH SIP.33 In May 2013, ADEQ 

submitted a SIP Supplement that 

addressed some of the elements that 

EPA had proposed to disapprove. We 

then proposed to approve in part and 

disapprove in part the SIP 

Supplement.34 We finalized our partial 

approval and partial disapproval on July 

30, 2013.35 We have also disapproved 

the majority of Arizona’s submittal 

under Section 309 of the RHR.36 Given 

these disapprovals, and our previous 

finding of failure to submit, EPA is 

required under CAA section 110(c) to 

promulgate a FIP for the disapproved 

portions of the SIP. Indeed, even if we 

had not previously found that Arizona 

failed to submit a comprehensive 

regional haze SIP, we nonetheless 

would be authorized to promulgate a 

partial FIP following our partial 

disapprovals of Arizona’s 308 and 309 

RH SIPs.37 As noted above, however, 


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38 78 FR 46142. 

39 78 FR 75722 and TEP Sundt Unit I4 BART 

Eligibility Memo (November 21, 2012) (Sundt 

Memo). 

40See 45 FR 80084, 64 FR 35714. 

41 70 FR 39160. 

42 70 FR 39111. 

43 42 U.S.C. 7411(a)(8) (emphasis added). 

44 42 U.S.C. 7411(a)(2) and (4). 

EPA remains willing to work with 

ADEQ on a SIP that would be designed 

to replace this FIP once such a SIP was 

submitted and approved by us. 

VI. Responses to Comments on EPA’s 

Proposed BART Determinations 

A. Comments on Sundt Generating 

Station Unit 4 

1. BART Eligibility 

Comment: Three commenters (ADEQ, 

TEP, and ACCCE) argued against EPA’s 

proposed finding that Sundt Unit 4 is 

BART-eligible, and two commenters 

(Earthjustice and NPS) supported EPA’s 

finding. ADEQ asserted that EPA has no 

authority to impose BART on Sundt 

Unit 4 because ADEQ determined that 

the unit is not BART-eligible. ADEQ 

noted that under CAA section 

169(b)(2)(A), major sources that existed 

as of August 7, 1962, are considered 

BART-eligible. However, the statute 

does not address sources that existed 

during that time, but were reconstructed 

after 1977 (Sundt Unit 4 was 

reconstructed in 1987). According to 

ADEQ, ‘‘EPA filled that gap by adopting 

regulations treating ‘reconstructed’ units 

as ‘new’ units.’’ 

ADEQ further noted that the BART 

Guidelines provide that ‘‘any emissions 

unit for which a reconstruction 

‘commenced’ after August 7, 1977, is 

not BART-eligible’’ and argued that 

ADEQ’s determination that Sundt Unit 

4 is not BART-eligible was consistent 

with EPA’s regulations. ADEQ asserted 

that EPA rejected the determination on 

the basis that EPA is not bound by its 

own guidelines and argued that that it 

was inappropriate for EPA to fault 

ADEQ for following guidance that EPA 

maintains is ‘‘persuasive’’ evidence of 

the requirements of the CAA. The 

commenter further argued that the 

BART Guidelines are clear that any unit 

that was reconstructed after 1977 is not 

BART-eligible, but that despite this, 

EPA has indicated that it does not 

interpret the BART Guidelines to apply 

to Sundt Unit 4 because the unit never 

went through prevention of significant 

deterioration (PSD) permitting. ADEQ 

argued that ‘‘EPA is not authorized, in 

the guise of ‘interpreting’ its BART 

Guidelines, to engage in what amounts 

to post-hoc rulemaking, by amending its 

BART Guidelines to make units that are 

reconstructed after 1977, but which did 

not obtain PSD permits BART-eligible.’’ 

ADEQ also commented that EPA has 

ignored the policy reasons that Congress 

had for excluding reconstructed units 

such as Sundt Unit 4 from PSD and 

other requirements. The commenter 

noted that the Power Plant and 

Industrial Fuel Use Act of 1978 (FUA), 

which amended the Energy Supply and 

Environmental Coordination Act of 

1974 (ESECA), authorized the 

Department of Energy (DOE) to require 

electric utilities to convert generating 

stations using oil and natural gas to 

using coal to reduce the Unites States’ 

dependency on foreign oil and increase 

its use of indigenous energy resources. 

ADEQ stated that because Congress 

wished to ensure the conversion took 

place, these units were exempted from 

‘‘environmental requirements.’’ 

Therefore, BART should not be required 

for Sundt Unit 4. 

TEP, the owner of the Sundt facility, 

incorporated by reference the comments 

it submitted on EPA’s proposed partial 

disapproval of the Arizona RH SIP, in 

which the commenter opposed EPA’s 

position that Sundt Unit 4 is BARTeligible, and reiterated its position that 

Sundt Unit 4 is not BART-eligible. 

Similarly, ACCCE asserted that, 

‘‘ADEQ’s determination that Sundt Unit 

4 was reconstructed in the 1980s, and 

therefore is not BART-eligible was 

reasonable and should not have been 

disapproved by EPA.’’ In contrast, 

Earthjustice and NPS expressed support 

for EPA’s finding that Sundt Unit 4 is 

BART-eligible because it did not go 

through PSD review when it was 

reconstructed in 1987. Earthjustice 

asserted that a source reconstructed 

after 1977 must install either BART 

controls under the regional haze 

program or Best Available Control 

Technology (BACT) controls under the 

PSD program. 

Response: To the extent that the 

comments concern EPA’s partial 

disapproval of the Arizona RH SIP, they 

are untimely, as EPA has already taken 

final action on the SIP.38 Further, we 

have already addressed many of the 

commenters’ assertions in our proposed 

and final actions on the SIP and in the 

Sundt Memo,39 all of which are 

included in the docket for this action. 

To the extent the comments raise new 

issues, we address them here. 

Contrary to ADEQ’s assertion, the 

RHR does not indicate that 

‘‘reconstructed’’ units are to be treated 

as ‘‘new’’ units for all purposes. In 

particular, the RHR does not indicate 

that a source that is reconstructed after 

1977 is considered BART-ineligible. 

Likewise, nothing in the preamble to the 

1980 rule regarding Reasonably 

Attributable Visibility Impairment 

(RAVI), in which EPA promulgated the 

definition of ‘‘BART-eligible,’’ or the 

preamble to the 1999 RHR itself suggests 

that a post-1977 reconstruction would 

exempt a source from BART.40 The 

BART Guidelines do state that ‘‘any 

emissions unit for which a 

reconstruction ‘commenced’ after 

August 7, 1977, is not BART-eligible.’’ 41

However, this statement in the BART 

Guidelines must be read in the context 

of the applicable regulatory 

requirements and associated preambles, 

none of which even mention such an 

exemption for post-1977 

reconstructions. In particular, the 

preamble to the BART Guidelines 

indicates that the post-1977 

reconstruction exemption set out in the 

BART Guidelines is limited to ‘‘sources 

reconstructed after 1977, which 

reconstruction had gone through NSR/

PSD permitting.’’ 42 Although not 

binding, this statement in the preamble 

confirms that EPA did not intend to 

create a blanket exemption for all post1977 reconstructions in the BART 

Guidelines. Indeed, it would only make 

sense to exempt a reconstructed unit 

from BART if that unit had gone 

through NSR/PSD permitting to ensure 

that its emissions were subject to 

modern-day pollution controls. Sundt 

Unit 4 never went through such 

permitting. Thus, we do not agree that 

we are effectively amending the BART 

Guidelines or engaging in post hoc 

rulemaking by applying an 

interpretation that is consistent not only 

with the CAA and RHR, but also with 

the preamble to the BART Guidelines 

themselves. 

We also do not agree that Congress 

intended to provide a general exemption 

from all ‘‘environmental requirements’’ 

for units that were converted to coal 

under the FUA and ESECA. The 

relevant section of FUA, codified in 

CAA section 111(a)(8), provides that 

‘‘[a] conversion to coal . . . by reason of 

an order under section 2(a) of the 

[ESECA] or any amendment thereto, or 

any subsequent enactment which 

supersedes such Act . . . shall not be 

deemed to be a modification for 

purposes of paragraphs (2) and (4) of 

[CAA subsection 111(a)].’’ 43 Paragraphs 

(2) and (4), in turn, contain the 

definitions of ‘‘new source’’ and 

‘‘modification’’ that apply to the Act’s 

new source performance standards 

(NSPS) requirements.44 The definition 

of ‘‘modification’’ in paragraph 111(a)(4) 

also applies for purposes of the PSD 


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45 42 U.S.C. 7479(2)(C). 

46CAA section 169A(g)(2), 40 CFR 

51.308(e)(1)(ii)(A). 

47 70 FR 39129. 

48See 79 FR 9329. 

49See, e.g., BART EGU FIP Summary. 

50 Id. The only example with a higher incremental 

cost-effectiveness value is Dave Johnston Unit 3 in 

Wyoming ($7,583/ton based on a remaining useful 

life of 20 years). 

provisions of the Act.45 However, 

nothing in the Act indicates that 

Congress intended the exemption in 

section 111(a)(8) to extend to other 

provisions of the Act, such as the 

visibility protection provisions of 

Section 169A. If Congress had intended 

to provide such an exemption from 

BART eligibility for units that were 

converted to coal under the FUA and 

ESECA, it could have added such an 

exemption to section 169A. It did not do 

so. Thus, for the reasons set out in the 

Sundt Memo, in our Phase 2 proposed 

and final rulemakings, and in this 

response, we are finalizing our proposed 

determination that Sundt 4 is BARTeligible. 

2. BART Analysis and Determination for 

NOX

Comment: ADEQ indicated that it 

does not support EPA’s proposed limit 

for NOX that is based on SNCR control 

technology. ADEQ asserted that the 

significant cost of installing and 

operating SNCR ($3 million in 

construction and $1 million in annual 

operating costs) does not justify the 

limited visibility improvement that 

would result from adding this control 

technology. ADEQ said that EPA’s 

analysis, which ADEQ described as 

suspect, shows an improvement of only 

0.5 dv. ACCCE also objected to EPA’s 

decision to require SNCR, arguing that 

it is costly and results in no perceptible 

improvement in visibility. ACCCE 

discussed the installation costs and the 

cost-effectiveness of SNCR on Unit 4, 

and stated that none of the Class I areas 

affected by Sundt Unit 4 will experience 

a greater than a 1.0 dv improvement 

from the installation of SNCR. This 

‘‘modest’’ improvement is inconsistent, 

ACCCE said, with EPA’s position that 

considers 1.0 dv change or more from an 

individual source as causing visibility 

impairment and a 0.5 dv change as 

contributing to impairment. 

Response: We disagree with these 

comments. Regarding the costs of 

compliance, although the installation 

and operation of SNCR will result in 

TEP incurring certain initial 

investments and ongoing operational 

costs, we consider the total annualized 

cost warranted based on the amount of 

NOX removed and the expected 

visibility benefits. As noted in our 

proposed rule, SNCR at this source has 

a cost-effectiveness of about $3,200/ton, 

which we consider very cost-effective. 

With regard to visibility improvement, 

we do not agree that only visibility 

improvements that by themselves result 

in humanly perceptible changes are 

relevant. The CAA and RHR require, as 

part of each BART analysis, 

consideration of ‘‘the degree of 

improvement in visibility which may 

reasonably be anticipated to result from 

the use of such technology.’’ 46 The Act 

and RHR do not require that the 

improvement from a single source be 

perceptible in order to be meaningful. 

As EPA explained in the preamble to 

the BART Guidelines: ‘‘Even though the 

visibility improvement from an 

individual source may not be 

perceptible, it should still be considered 

in setting BART because the 

contribution to haze may be significant 

relative to other source contributions in 

the Class I area.’’ 47 Thus, we disagree 

that the degree of visibility 

improvement should be contingent 

upon perceptibility. 

In our visibility improvement 

analysis, we have not considered 

perceptibility as a threshold criterion for 

considering improvements in visibility. 

Rather, we have considered visibility 

improvement in a holistic manner, 

taking into account all reasonably 

anticipated improvements in visibility 

expected to result at all Class I areas 

within 300 kilometers of each source. 

Improvements smaller than 0.5 dv may 

be warranted considering the number of 

Class I areas involved and the baseline 

contribution to impairment of the 

source in question. For example, a 

source with a 0.5 dv impact at a Class 

I area ‘‘contributes’’ to visibility 

impairment and must be analyzed for 

BART controls. Controlling such a 

source will not result in perceptible 

improvement in visibility, but Congress 

nevertheless determined that such 

contributing sources should 

nevertheless be subject to the BART 

requirement. In the aggregate, small 

improvements from controls on 

multiple BART sources and other 

sources will lead to visibility progress. 

As a result, although we described the 

anticipated visibility benefits from the 

installation of SNCR as ‘‘modest,’’ we 

still consider those benefits sufficient to 

justify SNCR as BART in light of the fact 

that SNCR will be highly cost-effective 

and has no substantial adverse energy or 

non-air quality environmental impacts. 

This has been EPA’s consistent 

interpretation in many regional haze 

determinations. 

Comment: ADEQ indicated that it 

supports EPA’s rejection of an emission 

limit equivalent to SCR as BART for 

NOX at Sundt Unit 4 due to costs. In 

contrast, Earthjustice asserted that EPA 

should have set a BART emission limit 

that reflects the use of SCR at Sundt 

Unit 4, rather than the less effective 

SNCR technology. Earthjustice stated 

that EPA erred when it concluded that 

the visibility benefits of SCR were not 

worth the costs after EPA acknowledged 

that SCR provides substantially greater 

visibility improvements than SNCR. 

Earthjustice stressed that EPA’s 

calculated cost-effectiveness value of 

$5,176 per ton of NOX removed for SCR 

is within the range of what has been 

deemed cost-effective in many other 

instances, based on examples provided 

in Exhibit 33 submitted with the 

comments. Earthjustice added that EPA 

provided no justifiable rationale for 

rejecting the overall cost-effectiveness 

value and relying on the incremental 

cost-effectiveness value for the rejection. 

Earthjustice also contended that EPA 

improperly rejected SCR based on 

numerous erroneous assumptions in its 

cost analysis that increased the costeffectiveness values (i.e., $/ton) for SCR. 

In particular, Earthjustice asserted that 

EPA used an unreasonably low capacity 

factor of 0.49, even though a higher and 

more appropriate capacity factor would 

have made the SCR controls more costeffective. Earthjustice also noted that 

EPA used a retrofit factor for SCR of 1.5, 

instead of the standard retrofit factor of 

1.0, but asserted that EPA did not 

provide a sufficient reason to enhance 

the retrofit factor. According to 

Earthjustice, correcting these two 

assumptions would make SCR costeffective to control NOX at Sundt Unit 

4 at an emission rate of 0.05 lb/MMBtu. 

Response: We disagree that we 

improperly rejected SCR. In reaching 

our BART determination, we have 

considered both average and 

incremental costs as well as expected 

visibility benefits.48 In particular, we 

estimate the average cost-effectiveness 

of SCR to be $5,176/ton. EPA has not 

previously required installation of 

controls with an average costeffectiveness value this high for 

purposes of BART.49 Similarly, the 

estimated incremental cost-effectiveness 

for SCR (compared to SNCR) of $6,174/ 

ton is on the high end of what we have 

required for purposes of BART.50 Such 

cost values might be warranted if the 

expected visibility benefits were very 

high (i.e., over one deciview at a single 

Class I area or several cumulative 

deciviews across multiple affected Class 


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51This emission and generation data was 

contained in the docket for our proposal, E–45— 

TEP Sundt4 2001–12 Emission Calcs 2014–01– 

24.xlsx. 

52See 70 FR 39167. 

53TEP’s May 10, 2013 letter describing this 

information was contained in the docket for our 

proposal, C–37 Letter from Erik Bakken, TEP, to 

Greg Nudd, EPA, re TEP Sundt Modeling & Cost 

Information.pdf. 

54Our cost calculations, which note these upward 

revisions, were contained in the docket for our 

proposal, E–05 TEP Sundt4 Control Costs (final for 

NPRM docket).xlsx. 

I areas). However, we do not consider 

this level of cost to be justified here by 

the expected visibility benefits for SCR 

of 0.78 dv for the most improved Class 

I area and 1.6 dv cumulative for all 

affected Class I areas. 

The information provided by 

Earthjustice regarding the range of $/ton 

values considered cost-effective is 

derived from other regulatory programs 

such as Best Available Control 

Technology (BACT) determinations for 

construction of new sources in 

attainment areas, and Lowest 

Achievable Emission Rate 

determinations for construction of new 

sources in nonattainment areas. The 

statutory requirements, calculation 

methodology, and regulatory drivers 

that may inform a determination of 

emission reductions appropriate for 

these programs are not necessarily 

comparable to those of the Regional 

Haze program, which is a retrofit 

program where older sources are 

required to add pollution controls. We 

therefore do not consider it appropriate 

simply to conclude that costs found to 

be acceptable in other programs are 

necessarily appropriate in a BART 

determination. 

We also disagree with Earthjustice’s 

assertion that our cost analysis for SCR 

is based on faulty assumptions. We 

recognize that a higher capacity factor 

would result in an increase in the 

calculated amount of NOX reduced. We 

also recognize that, historically, Sundt 

Unit 4 operated at higher capacity 

factors, ranging from 0.60 to 0.75. 

However, a review of data from EPA’s 

Clean Air Markets Division (CAMD) 

Acid Rain Program database indicates 

that, starting in 2009 and continuing 

into the present, Sundt Unit 4 has 

consistently operated at substantially 

lower capacity factors.51 Our use of a 

0.49 capacity factor is therefore not 

based on a single, abnormal year of low 

capacity, but rather represents an 

average of multiple, recent years of low 

capacity at Sundt Unit 4. Given the 

length of time that Sundt Unit 4 has 

operated at these low capacity levels, 

we consider our use of a 0.49 capacity 

factor in emission calculations to be a 

‘‘realistic depiction of anticipated 

annual emissions.’’ 52

Moreover, we disagree with the 

Earthjustice’s assertion that our use of a 

1.5 retrofit factor is unsupported in the 

record. Although the factors 

contributing to retrofit difficulty were 

summarized as ‘‘certain difficulties’’ in 

our TSD, this information is described 

in detail in the modeling and cost 

information provided by TEP on May 

10, 2013.53 Our cost calculations 

specifically noted the changes we made 

to account for these factors.54

Specifically, a detailed description of 

these issues is contained on page 6, 

Attachment C, in TEP’s letter dated May 

10, 2013. These issues include 

interference from existing boiler 

structures and material handling 

equipment that makes the most common 

SCR reactor impractical, the need for 

substantial modifications to the existing 

air preheater, and site congestion 

around the boiler that complicates siting 

of an SCR system. We consider these 

issues sufficient to warrant a higher 

retrofit factor. 

Comment: In response to EPA’s 

request for comment on whether EPA 

should use a less stringent SCR 

emission limit in its NOX BART analysis 

for Sundt Unit 4, Earthjustice responded 

in the negative. According to the 

commenter, EPA’s use of a 0.05 lb/

MMBtu limit for SCR is consistent with 

EPA’s BART determinations for other 

coal-fired power plants for which EPA 

has repeatedly concluded that a 0.05 to 

0.055 lb/MMBtu emission limit is 

BART. In addition, citing reports 

submitted with the comments, 

Earthjustice asserted that SCRs often 

achieve more stringent emission rates 

and control efficiencies than EPA 

assumed SCR would achieve at Sundt 

Unit 4. Earthjustice stated that because 

a 0.05 lb/MMBtu emission rate is 

achievable with SCR at Sundt Unit 4, 

EPA should not use a less stringent 

emission limit in its BART analysis. 

Response: We agree that our use of a 

0.05 lb/MMBtu annual average design 

value for SCR is consistent with other 

BART determinations for coal-fired 

power plants. 

Comment: Earthjustice stated that if 

EPA does not revise its BART 

determination to require SCR, it should 

set a more stringent emission limit that 

more accurately reflects the emission 

reductions achievable with SNCR. 

Earthjustice quoted the BART 

Guidelines as requiring EPA to ‘‘take 

into account the most stringent emission 

control level that the technology is 

capable of achieving,’’ which 

Earthjustice said EPA has not done in 

this case. Earthjustice asserted that EPA 

should select a level of NOX reduction 

for SNCR in the range of 50 percent over 

and above the existing combustion 

controls, rather than the level of 30 

percent above current controls that was 

selected. As support, Earthjustice noted 

that SNCR is required by the pending 

SIP revision (prepared by ADEQ to 

replace the FIP) for Apache Unit 3 to 

reduce NOX from 0.43 lb/MMBtu down 

to 0.23 lb/MMBtu, or roughly 50 

percent. Earthjustice recommended that 

EPA set an emission limit for SNCR in 

the range of 0.22 lb/MMBtu, reflecting 

50 percent reduction from the baseline 

level of 0.445 lb/MMBtu of NOX in 

2011. In addition, Earthjustice disagreed 

with EPA’s inflation of the NOX

emission limit by 17 percent to account 

for variability. According to 

Earthjustice, EPA assumed without 

justification that the observed variability 

without SNCR would be the same as 

variability with SNCR. 

Response: We disagree with this 

comment. The Apache Unit 3 example 

cited by Earthjustice does not support a 

50 percent SNCR control efficiency. The 

0.43 lb/MMBtu emission rate on Apache 

Unit 3 noted by Earthjustice reflects the 

use of over fire air (OFA) only. The 0.23 

lb/MMBtu emission rate on Apache 

Unit 3 noted by Earthjustice reflects the 

use of LNB with OFA and SNCR. The 

approximate 50 percent reduction from 

0.43 to 0.23 is not solely attributable to 

SNCR, but rather is the result of the 

application of LNB and SNCR. Since 

Sundt Unit 4 already operates with LNB 

and OFA, we do not consider it 

appropriate to assume that application 

of SNCR will result in an additional 50 

percent NOX reduction. 

With regard to our upward revision to 

the annual emission rate to develop a 

rolling 30 day emission limit, we 

acknowledge that observed variability 

without SNCR might not be the same as 

variability with SNCR. We note, 

however, that even emission units with 

well-operated controls will experience 

some degree of emissions variability. As 

noted in our proposed rule, we 

developed this upward revision based 

on site-specific emission data reported 

to the CAMD for Sundt Unit 4. Given 

the site-specific basis for our upward 

revision, we consider it a reasonable 

estimate of emission variability. We 

acknowledge that there might be other 

methods of accounting for this 

variability. However, we did not receive 

any comments that described or 

proposed any such alternate 

methodology. Accordingly, we are 

finalizing the emission limit as 

proposed. 


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55As opposed to capital costs, which are incurred 

only once, at the start of the project. 

56BART Guidelines, 40 CFR Part 51, Appendix Y, 

section IV.D.4.a. 

57TSD for the Proposed Phase 3 FIP, January 27, 

2013, Page 19 of 233. 58See 79 FR 9332–33. 

Comment: NPS indicated that it 

agrees with the design emission rate of 

0.050 lb/MMBtu that EPA used to 

estimate the control effectiveness of 

SCR. However, NPS did not agree with 

the cost of catalyst for SCR of $8,000 per 

cubic meters (m3), and cited to a recent 

report indicating the costs are around 

$5,000/m3. NPS also said that EPA did 

not consider using regenerated catalyst 

at a cost of $5,500/m3, which it did in 

the recent Wyoming RH FIP. 

NPS also stated that instead of relying 

only on the Integrated Planning Model 

(IPM) to estimate the costs of SCR, NPS 

used a method similar to what EPA 

Region 8 used for Colstrip in Montana. 

In NPS’s opinion, using IPM to calculate 

capital costs and EPA’s Control Cost 

Manual (CCM) to calculate operating 

costs provides more flexibility, provides 

greater transparency and is more in line 

with the BART Guidelines that 

recommend following EPA’s CCM as 

much as possible. 

Response: We disagree with the 

NPA’s assertion that $8,000/m3 is an 

unreasonable cost estimate for catalyst. 

Since catalyst prices fluctuate, we 

recognize that recent prices may be 

lower than the value used in our cost 

calculations. However, given that 

catalyst is an operating cost that will be 

periodically incurred over the entire 

useful life of the equipment,55 we 

consider it appropriate to use a catalyst 

price that reflects more than just recent 

price levels. The BART Guidelines state, 

‘‘In order to maintain and improve 

consistency, cost estimates should be 

based on the OAQPS Control Cost 

Manual, where possible’’ and that ‘‘[w]e 

believe that the Control Cost Manual 

provides a good reference tool for cost 

calculations, but if there are elements or 

sources that are not addressed by the 

Control Cost Manual or there are 

additional cost methods that could be 

used, we believe that these could serve 

as useful supplemental information.’’ 56

As noted in our proposed rule and 

TSD,57 EPA has used IPM in multiple 

regulatory actions, and considers it an 

appropriate source of supplemental 

information. 

3. BART Analysis and Determination for 

SO2

Comment: ACCCE opposed EPA’s 

proposal to require DSI for the control 

of SO2 emissions at Sundt Unit 4. The 

ACCCE asserted that this requirement 

will have no humanly perceptible 

visibility improvement, so the proposal 

must be withdrawn. According to 

ACCCE, the highest visibility 

improvement expected from this 

requirement is 0.20 dv at Saguaro 

National Park. At the other nine affected 

Class I areas, the visibility improvement 

is expected to range from only 0.04 to 

0.10 dv. ACCCE contended that 

requiring costly controls with no 

humanly perceptible visibility 

improvement is unjustified. 

Response: As noted in our response to 

a similar comment regarding our NOX

BART determination, we have not 

considered perceptibility as a threshold 

criterion for considering improvements 

in visibility. Rather, we have considered 

visibility improvement in a holistic 

manner, taking into account all 

reasonably anticipated improvements in 

visibility expected to result at all Class 

I areas within 300 kilometers of each 

source. Improvements smaller than 0.5 

dv may be warranted considering the 

number of Class I areas involved and the 

initial contribution to impairment of the 

source in question. For example, a 

source with a 0.5 dv impact at a Class 

I area ‘‘contributes’’ to visibility 

impairment and must be analyzed for 

BART controls. While controlling such 

a source will not result in perceptible 

improvement in visibility, Congress 

determined that such contributing 

sources should nevertheless be subject 

to the BART requirement. In the 

aggregate, small improvements from 

controls on multiple BART sources and 

other sources will lead to visibility 

progress. As a result, although the 

anticipated visibility benefit attributable 

to DSI is not humanly perceptible, we 

consider those benefits sufficient to 

justify DSI as BART in light of the fact 

that DSI will be highly cost-effective 

and has no substantial adverse energy or 

non-air quality environmental impacts. 

Comment: Earthjustice stated that 

EPA should revise its BART analysis for 

SO2 to reflect more stringent emission 

rates achievable with wet flue gas 

desulfurization (FGD) and dry FGD 

because the BART Guidelines require 

EPA to analyze the most stringent 

emission control level that the 

technology is capable of achieving. 

According to Earthjustice, EPA assumed 

that wet FGD would achieve a 0.06 lb/ 

MMBtu emission rate (92 percent 

control efficiency) and dry FGD would 

achieve a 0.08 lb/MMBtu emission rate 

(89 percent control efficiency). 

Earthjustice argued that these figures 

were cited despite EPA’s 

acknowledgment that both wet FGD and 

dry FGD are capable of achieving more 

stringent emission rates. Earthjustice 

added that reports submitted with its 

comments show that both wet and dry 

FGD can achieve emission rates of 0.04 

lb/MMBtu or lower along with control 

efficiencies of 95 to 99 percent. 

Response: We disagree that we 

underestimated the SO2 emission 

reductions achievable with dry or wet 

FGD. In our proposed rule, and in the 

TSD for our proposed rule, we stated 

that: 

[B]oth dry and wet FGD have very high 

incremental cost-effectiveness values, 

indicating that while they are more effective 

than the preceding control, this additional 

degree of effectiveness comes at a substantial 

cost. 

The incremental cost-effectiveness of 

dry FGD, in relation to DSI, is 

approximately $17,000/ton. Assuming a 

more stringent dry or wet FGD emission 

rate of 0.04 lb/MMBtu, the incremental 

cost-effectiveness of FGD, relative to 

DSI, is approximately $13,000/ton, 

which is still not within a range that 

EPA or states have considered costeffective, especially given that FGD (dry 

or wet) is expected to result in less 

visibility improvement than DSI.58 As a 

result, a more stringent FGD emission 

rate would not alter our SO2 BART 

determination. 

Comment: Earthjustice asserted that 

EPA improperly raised the proposed 

SO2 limit (based on use of DSI) from 

0.21 to 0.23 lb/MMBtu. Earthjustice said 

that this increase was inappropriate, as 

it was based on SO2 emission data that 

did not account for controls. Since 

proper controls dampen the variability 

of emissions, Earthjustice said that the 

emission limit should not be raised to 

account for variability. 

Response: As noted in a response to 

a similar comment regarding our NOX

BART determination, we acknowledge 

that observed emissions variability at 

Sundt Unit 4 without SO2 controls may 

not be the same as its emissions 

variability when operating with DSI. We 

note, however, that even emission units 

with well-operated controls will 

experience some degree of emissions 

variability. As noted in our proposed 

rule, we developed this upward revision 

based on site-specific emission data 

reported to EPA’s CAMD for Sundt Unit 

4. Given the site-specific basis for our 

upward revision, we do not consider it 

as an unreasonable estimate of 

emissions variability. We acknowledge 

that there might be other methods of 

accounting for this variability. However, 

we did not receive any comments that 

described or proposed any such 

alternate methodology. Therefore, we 

are finalizing the SO2 emission limit of 

0.23 lb/MMBtu as proposed. 


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Federal Register / Vol. 79, No. 170 / Wednesday, September 3, 2014 / Rules and Regulations 52433 

59The original Method 5 test results are included 

as Docket Item F–28—TEP Sundt4 Test Results.pdf. 

60 42 U.S.C. 7602(k) (definition of ‘‘emission 

limitation’’); 40 CFR 51.301 (definition of ‘‘BART’’). 

61 233 lb/hour, per page 2 of the TSD. The BART 

limit would be equivalent to approximately 41 lb/ 

hour. 

62BART Guidelines, Section IV.C. ‘‘How does a 

BART review relate to Maximum Achievable 

Control Technology (MACT) Standards under CAA 

section 112, or to other emission limitations 

required under the CAA?’’ 63BART Guidelines, Section IV.D.1.5. 

4. BART Analysis and Determination for 

PM10

Comment: ADEQ indicated that it 

supports EPA’s decision to require 

BART for particulate matter (PM) in 

terms of a PM10 limit of 0.03 lb/MMBtu. 

While agreeing that fabric filter 

baghouses are the best technology for 

PM reductions from Sundt Unit 4, 

Earthjustice asserted that EPA should 

set a lower emission limit as BART. 

According to Earthjustice, stack test 

results for PM10 show that the existing 

baghouses at Sundt Unit 4 can achieve 

lower emission rates than the 0.03 lb/

MMBtu rate that EPA proposed as BART 

(citing the TSD at 23). Earthjustice 

stated that there are hundreds of 

instances of coal units with baghouses 

achieving emission rates lower than 

0.03 lb/MMBtu, citing the docket for the 

Mercury Air Toxics Standards (MATS). 

Response: We disagree that the 

proposed 0.030 lb/MMBtu emission 

limit for filterable PM10 is too high. The 

0.022 lb/MMBtu emission rate 

summarized on page 23 of the TSD is 

the average of multiple test runs that 

range from 0.016 lb/MMBtu to 0.039 lb/ 

MMBtu.59 Emission limitations under 

the CAA must be continuous and BART 

must be an emission limitation that is 

achievable.60 Thus, a BART emission 

limitation should be one that a facility 

can continuously achieve. The 

performance test data indicate that a PM 

emission limit of 0.030 lb/MMBtu is 

achievable by the facility, and will also 

result in actual emission reductions. In 

addition, the BART limit is substantially 

lower than the PM limit contained in 

the facility’s current operating permit,61

substantially decreasing the PM 

emissions authorized at the facility. 

MATS establishes an emission limit 

of 0.030 lb/MMBtu for filterable PM (as 

a surrogate for toxic non-mercury 

metals) as representing MACT for coalfired electric generating units (EGUs). 

The BART Guidelines provide that 

‘‘unless there are new technologies 

subsequent to the MACT standards 

which would lead to cost-effective 

increases in the level of control, you 

may rely on the MACT standards for 

purposes of BART.’’ 62 We consider 

baghouses to be the most stringent PM 

control technology for coal-fired EGUs. 

Moreover, the commenter has not 

identified a new or more stringent 

technology. As a result, we consider 

0.030 lb/MMBtu to be an appropriate 

continuously achievable BART limit for 

Sundt Unit 4. 

5. Better-than-BART Alternative 

Comment: Multiple commenters 

expressed support for the ‘‘better-thanBART alternative’’ for Sundt Unit 4. 

Sierra Club stated that overall, EPA has 

done an excellent job in its FIP. 

However, Sierra Club also asserted that 

substituting coal with natural gas is not 

the ultimate solution. The fuel 

substitution will address the pollution 

problem associated with coal 

combustion, but Sierra Club argued that 

TEP should transition toward renewable 

energy sources, and be a leader in 

developing solar, wind, and other 

renewable sources for the purpose of 

energy generation. 

TEP noted that a fuel change to 

natural gas meets the RHR’s 

requirements for alternative measures in 

lieu of BART in that it will achieve 

greater reasonable progress than the 

implementation of BART. TEP added 

that because emissions under BART or 

the alternative would emanate from the 

same stack (and therefore the 

distribution of emissions is not 

significantly different), the alternative 

achieves greater reasonable progress 

simply because it will result in greater 

emissions reductions. In addition, TEP 

noted that EPA’s finding that ‘‘natural 

gas provides better visibility 

improvement than the proposed BART 

determination’’ is consistent with the 

results of modeling performed by a 

contractor (AECOM) for TEP. Several 

other commenters (ADEQ, ANGA, 

Earthjustice, NPS, TPMEC, Friends of 

Saguaro National Park and a private 

individual) expressed general support 

for the better-than-BART alternative. 

Response: We acknowledge the 

commenters’ support of the proposed 

BART alternative. Today’s final rule 

provides TEP with the option to comply 

either with the BART limits within 

three years of publication of the final 

rule or with the requirements of the 

BART alternative by December 31, 2017. 

With regard to the comments 

concerning renewable energy, we note 

that the BART Guidelines indicate that 

‘‘[w]e do not consider BART as a 

requirement to redesign the source 

when considering available control 

alternatives.’’ 63 We therefore consider a 

requirement for TEP to transition to 

renewable energy to be beyond the 

scope of what the RHR requires. 

Comment: ACCCE said that the BART 

alternative should be rejected because it 

does not lead to an improvement in 

humanly perceptible visibility. 

According to ACCCE, EPA stated that 

switching from coal to natural gas under 

the better-than-BART alternative will 

lead to a higher visibility improvement 

than the combination of SNCR and DSI 

together. Yet, with one exception, the 

areas affected by Sundt Unit 4 will not 

see a greater than 1.0 dv improvement. 

Again, ACCCE made the case that it is 

up to the states to make BART-eligibility 

determinations, but if it is determined 

that EPA has correctly classified Sundt 

Unit 4 as BART-eligible, it is Arizona, 

not EPA, that must finalize a BART 

determination for the unit. However, if 

this does not occur, ACCCE reiterated 

that it disagrees with EPA’s analysis to 

require BART, since it does not result in 

humanly perceptible visibility 

improvement. 

Response: As explained in response to 

similar comments on our BART 

analyses above, visibility improvement 

is not required to be humanly 

perceptible in order for a control to be 

required as BART. Arizona did not 

include a BART analysis and 

determination for TEP Sundt 4 in any of 

its RH SIP submittals. If Arizona 

submits such a determination in the 

future, we will give it due consideration 

under the requirements of the CAA and 

EPA’s implementing regulations. 

Comment: TEP stated that the facility 

has been co-firing landfill gas in the 

Sundt Unit 4 boiler since 1999, and that 

this has been an integral part of the 

company’s strategy for complying with 

Arizona’s Renewable Energy Standard 

and Tariff, as it is among the most costeffective renewable resources in its 

portfolio. TEP added that, through the 

direct displacement of heat input 

otherwise provided by coal, co-firing 

landfill gas has resulted in significant 

avoided emissions of carbon dioxide, 

SO2, PM, and other pollutants. TEP 

asserted that it must be allowed to 

continue an environmentally beneficial 

program. 

TEP further stated that its current 

tariff agreement with El Paso Natural 

Gas Company for natural gas deliveries 

to Sundt Unit 4 does not meet the fuelsulfur specification in the definition of 

‘‘pipeline natural gas’’ in 40 CFR 72.2, 

but the tariff agreement does meet the 

sulfur specifications in the definition of 

‘‘natural gas’’ in 40 CFR 72.2. TEP 

indicated that it has no direct control 

over the sulfur content of the natural gas 

delivered to Sundt, and limiting the fuel 

burned at Sundt Unit 4 to ‘‘pipeline 


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52434 Federal Register / Vol. 79, No. 170 / Wednesday, September 3, 2014 / Rules and Regulations 

64See spreadsheet titled ‘‘Revised BART 

Alternative Emission Calculations.xls.’’ 

Specifically, the SO2 emission factor for natural gas was revised from 0.00064 lb/MMBtu to 0.057 lb/

MMBtu. 

natural gas’’ would prohibit TEP’s 

ability to select the alternative to BART, 

which TEP and many other stakeholders 

view as the preferred choice. 

Accordingly, TEP recommended several 

revisions to the regulatory language for 

the better-than-BART alternative that 

would revise the SO2 emission limit and 

fuel restriction to correspond to the 

definition of ‘‘natural gas’’ rather than 

‘‘pipeline natural gas’’ and provide for 

co-firing of landfill gas. TEP noted that 

regardless of the SO2 emission limit that 

EPA selects for the alternative to BART, 

or the method identified to demonstrate 

compliance with that limit, SO2

emissions from Sundt Unit 4 under the 

alternative to BART will be orders of 

magnitude lower than SO2 emissions 

would be through the application of 

BART. 

Response: We agree that the 

continued co-firing of landfill gas does 

not adversely affect whether the fuel 

switch to natural gas achieves greater 

emissions reductions than the aggregate 

BART determinations for Sundt Unit 4. 

We are therefore revising the regulatory 

language to provide for the co-firing of 

landfill gas. In addition, we are revising 

the SO2 emission limit in the betterthan-BART alternative (and the 

emissions value used to evaluate 

whether the alternative is better-thanBART) to correspond to the definition of 

‘‘natural gas’’ per 40 CFR 72.2. These 

revised emission calculations are 

contained in our docket, and are 

summarized in our response to the 

following comment.64

Comment: TEP stated that stack 

testing to demonstrate compliance with 

the PM10 limit while burning natural gas 

is unnecessary. According to TEP, the 

PM10 emission limit of 0.010 lb/MMBtu 

that EPA proposed under the alternative 

to BART was developed based on a 

calculation using an AP–42 emission 

factor, but the proposal requires a 

compliance demonstration by 

conducting performance stack testing 

using EPA Method 201A and Method 

202, per 40 CFR part 51, Appendix M. 

TEP stated that stack testing is a suitable 

method of determining compliance with 

an emission limit when either (1) it is 

necessary to verify that required 

controls are in place and operating 

correctly, or (2) to verify that a source 

is designed and constructed (in the case 

of a new unit) to meet a particular 

performance standard. However, 

according to TEP, neither of those 

situations applies to implementation of 

the alternative to BART on Sundt Unit 

4, which is essentially a fuel-use 

limitation. TEP indicated that, while it 

has no reason to conclude that Sundt 

Unit 4 could not meet the standard, it 

has no experience measuring PM10

emission levels while burning natural 

gas. Thus, the inclusion of Method 202 

for condensable PM10 presents some 

risk. TEP encouraged EPA to modify the 

compliance demonstration requirement 

for PM10 to a calculation using AP–42 

(as EPA did to set the standard), 

combined with a demonstration that 

natural gas is the primary fuel. 

Response: We partially agree with this 

comment. The BART alternative PM10

emission limit in the proposed rule 

(0.01 lb/MMBtu) is based on AP–42 

emissions factors for natural gas usage. 

This factor is based on information that 

might not represent the emission 

characteristics of Sundt Unit 4 (i.e., a 

coal-burning unit that is converted to 

natural gas). We do not agree, however, 

that it is appropriate to eliminate 

entirely the performance test 

requirement, but recognize that there is 

a lack of experience and history 

regarding condensable PM10 test results 

at the Unit. As a result, we are revising 

the PM10 compliance determination to a 

‘‘test and set’’ approach. An initial 

performance test for PM10, based on the 

results of Method 202 plus either 

Method 5 or Method 201A, is still 

required along with subsequent 

performance tests if requested by the 

Regional Administrator. The results of 

the initial performance test will 

establish the PM10 limit with which 

subsequent performance tests must 

demonstrate compliance. For purposes 

of evaluating the better-than-BART 

alternative, our estimate of PM10

emissions is based upon this 0.30 lb/ton 

PM10 BART limit. Although this results 

in PM10 emissions equivalent to BART, 

the natural gas fuel switch still results 

in a net decrease in both NOX and SO2

relative to the respective BART 

determinations. As a result, this 

approach does not alter our 

determination that the natural gas fuel 

switch is better-than-BART. A 

comparison of emissions between the 

BART determination and the revised 

better-than-BART alternative is 

summarized in Table 5. 

TABLE 5—COMPARISON OF BART DETERMINATION TO BETTER THAN BART ALTERNATIVE

Parameters Units BART determination BART alternative 

(natural gas fuel switch) 

Emission 

reduction 

(tpy) 

Heat Duty ............................... MMBtu/hour ........................... 1,371 ...................................... 1,820 ...................................... ........................

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

NOX ........................................ Control Technology ................ SNCR+LNB+OFA .................. LNB+OFA ............................... ........................

lb/MMBtu ................................ 0.31 ........................................ 0.25 ........................................ ........................

TPY ........................................ 912 ......................................... 737 ......................................... 175 

SO2 ......................................... Control Technology ................ Dry Sorbent Injection ............. None ...................................... ........................

lb/MMBtu ................................ 0.18 ........................................ 0.057 ...................................... ........................

TPY ........................................ 530 ......................................... 169 ......................................... 361 

PM .......................................... Control Technology ................ Fabric Filter ............................ None ...................................... ........................

lb/MMBtu ................................ 0.03 ........................................ 0.03 ........................................ ........................

TPY ........................................ 88 ........................................... 88 ........................................... 0 

6. Other Comments on Sundt Unit 4 

Comment: TEP stated that it generally 

supports EPA’s BART determinations 

for Sundt Unit 4 because the control 

technologies selected as BART are 

available and technically feasible for the 

control of the respective pollutants. 

Furthermore, while TEP asserts that the 

level of visibility improvement achieved 

by application of these technologies is 

marginal, they conclude that the 

identified controls can be installed and 

operated at Sundt Unit 4 without a 

significant impact on reliability or 

customer rates. 


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Federal Register / Vol. 79, No. 170 / Wednesday, September 3, 2014 / Rules and Regulations 52435 

65CAA section 169A(g)(4), 42 U.S.C. 7491(g)(4), 

40 CFR 51.308(e)(1)(iv). 

Response: We acknowledge TEP’s 

support. 

Comment: TEP agreed with EPA’s 

selection of 2011 as the baseline year for 

Sundt Unit 4’s emissions and operating 

characteristics. In contrast, Earthjustice 

stated that EPA’s BART analyses are 

flawed due to errors in EPA’s emissions 

baseline and baseline capacity factor. 

Earthjustice noted that EPA considered 

Sundt Unit 4’s historical emissions from 

2008 to 2012, and selected 2011 as the 

baseline because Sundt Unit 4 

predominantly burned coal that year. 

However, according to Earthjustice, 

Sundt Unit 4 also burned large amounts 

of coal in 2008, making it unclear why 

EPA did not use 2008 instead of, or in 

addition to, 2011 when determining the 

baseline (e.g., by creating a baseline 

averaging 2008 and 2011 emissions). 

Response: We disagree with 

Earthjustice’s comment. In 2008, Sundt 

Unit 4 operated at a much higher 

capacity factor than in subsequent years. 

As discussed in a response to a previous 

comment, we do not consider the higher 

capacity factors observed during the 

pre-2009 period to be a realistic 

depiction of anticipated annual 

emissions. As a result, we do not 

consider it appropriate to incorporate 

2008 annual emissions into the 

development of baseline emissions. 

Comment: Earthjustice stated that 

EPA should set a one-year compliance 

deadline to install BART controls, rather 

than the proposed three-year deadline. 

Earthjustice noted that the CAA requires 

sources to install BART controls as 

‘‘expeditiously as practicable,’’ and 

judicial opinions interpreting similar 

compliance deadlines in the CAA read 

this language to require compliance as 

soon as possible. According to 

Earthjustice, EPA set a three-year 

compliance deadline to install both DSI 

and SNCR based on EPA’s conclusion 

that it will take three years to install 

DSI. The commenter asserted that DSI 

can be installed in just one year based 

on the record established for the MATS 

rulemaking and the rulemaking docket 

for this action. Earthjustice also noted 

that EPA has recognized that typical 

SNCR retrofits take ten to 13 months. 

Earthjustice stated that it is not aware of 

any circumstances at Sundt that would 

require additional time to install DSI 

and SNCR. Accordingly, the commenter 

suggested that because the CAA requires 

BART to be installed as quickly as 

possible and the record shows that both 

DSI and SNCR can be installed in one 

year, EPA should set a one-year 

compliance deadline for both controls. 

Response: We disagree with this 

comment. Although we agree that either 

control technology can be installed in as 

little as one year, we do not consider it 

reasonable to require installation of both 

technologies, in parallel, within a single 

year. The CAA and the RHR require 

compliance with the BART emission 

limit as expeditiously as possible, but in 

no event later than five years after 

promulgation of the FIP.65 The threeyear time frame in our proposed rule is 

consistent with this requirement. 

Comment: A private citizen indicated 

support for the proposal to end coal 

burning at the Sundt facility by the end 

of 2017 and requested that Sundt 

implement the requirement sooner. 

Specifically, the commenter 

recommended that TEP, the owner of 

the Sundt facility, use up the existing 

supply of coal and not purchase any 

additional coal. TPMEC similarly asked 

that TEP use up the coal it has on site 

and not buy any more, but proceed with 

the conversion. In contrast, TEP stressed 

that the timing of the elimination of coal 

is an integral part of the alternative to 

BART and should not be adjusted. TEP 

stated that because EPA may not 

consider a fuel switch as a control 

option for determining BART for a 

source (citing section IV.D.1.5 of the 

BART Guidelines), the decision whether 

to implement the alternative to BART is 

at the sole discretion of TEP. TEP added 

that because (1) the alternative was 

originally developed by TEP and (2) it 

clearly meets the requirements for 

‘‘better than BART,’’ EPA is limited in 

its ability to make changes to certain 

aspects of TEP’s approach. 

TEP asserted that it will need until 

December 31, 2017, to burn the existing 

fuel on site, ensure an adequate natural 

gas supply, and make the operational 

and mechanical changes necessary to 

achieve the proposed NOX emission 

rate. According to TEP, since the 

alternative to BART results in lower 

emissions on an annual basis, the timing 

for implementation is inconsequential 

relative to the long-term visibility goals 

of the RHR and should remain as 

originally outlined by TEP. TEP added 

that EPA has no obligation or authority 

to arbitrarily make a better-than-BART 

alternative even better by adjusting the 

timing for implementation, and 

therefore the timing for implementation 

of the alternative should not be 

adjusted. 

Response: We have considered TEP’s 

request to revise the compliance 

deadline to December 31, 2017. We 

agree with TEP that this deadline is 

reasonable, given that the alternative 

results in greater emission reductions 

than BART on a lb/MMBtu basis for 

NOX, SO2, and PM and meets the other 

requirements for a better-than-BART 

alternative under 40 CFR 51.308(e)(2) 

and (3). Therefore, we are setting a 

compliance deadline of December 31, 

2017. 

Comment: TEP asserted that EPA 

underestimates the costs of controlling 

NOX and SO2 emissions from Sundt 

Unit 4. TEP indicated that it hired a 

professional engineering and 

construction firm, Burns and 

MacDonnell (BMD), to review the cost 

estimates developed by EPA as part of 

its five-factor BART analysis and to 

provide new cost estimates for the 

installation and operation of various 

control technologies on Sundt Unit 4. 

The results of BMD’s analysis are in 

Table 6. TEP further noted that the 

BART Guidelines provide for 

incorporation of site-specific factors or 

‘‘elements . . . that are not addressed by 

the Cost Control Manual,’’ and stated 

that the most significant site-specific 

factors for Sundt Unit 4 have been 

identified by BMD in the report attached 

to the comments. TEP asserted that 

these factors should be incorporated 

into the final BART determination for 

the facility. 

TABLE 6—COMPARISON OF EPA’S AND BMD’S BART ANALYSIS RESULTS

[All values are in $/ton of pollutant removed] 

Control technology EPA 

(proposed) TEP Difference (percent) 

NOX Control Technology 

Selective Non-Catalytic Reduction .............................................................................................. $3,222 $3,637 13 


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52436 Federal Register / Vol. 79, No. 170 / Wednesday, September 3, 2014 / Rules and Regulations 

66We also note that it is unusual for controls at 

two different sources to have similar visibility 

benefits across all affected Class I areas. 

67See e.g. 70 FR 39167 (‘‘For purposes of air 

pollutant analysis, ‘effectiveness’ is measured in 

terms of tons of pollutant emissions removed, and 

‘cost’ is measured in terms of annualized control 

costs.’’) 68CAA section 169A(a)(1). 

TABLE 6—COMPARISON OF EPA’S AND BMD’S BART ANALYSIS RESULTS—Continued 

[All values are in $/ton of pollutant removed] 

Control technology EPA 

(proposed) TEP Difference (percent) 

Selective Catalytic Reduction ...................................................................................................... 5,176 7,874 52 

SO2 Control Technology 

Dry Sorbent Injection ................................................................................................................... 1,857 3,088 66 

Dry Flue Gas Desulfurization ...................................................................................................... 5,090 9,359 84 

Wet Flue Gas Desulfurization ...................................................................................................... 5,505 8,229 50 

Response: As noted in our proposed 

rule and TSD, we revised upwards our 

contractor’s original control cost 

estimates based on certain site-specific 

factors noted by TEP in its letter dated 

May 10, 2013. We incorporated many, 

but not all, of the factors raised in that 

letter. In its comment letter on our 

proposed rule, TEP raised additional 

factors and asserted that the cost 

estimates for each of the control options 

is underestimated. In the case of SCR, 

dry FGD, and wet FGD, we stated in our 

proposed rule that we consider these 

control options to not be cost-effective, 

either in general or in relation to their 

anticipated visibility benefits. In the 

case of SNCR and DSI, even if we were 

to accept all of TEP’s revisions included 

in the comment letter, we would still 

consider these options to be costeffective generally and to be BART 

based on our consideration of costs and 

visibility benefits. 

Comment: NPS commented that that 

although EPA has not stated the 

reasonable level of cost-effectiveness, it 

assumes that the Agency typically uses 

$5,000/ton and 0.5 deciviews (dv) as 

thresholds. Yet, NPS has seen higher 

cost-effectiveness thresholds from EPA 

and other states. While NPS commends 

EPA for its presentation of cumulative 

visibility impacts and cumulative 

visibility benefits of reducing emissions, 

NPS also requested that EPA work with 

NPS to develop a consistent and 

transparent method to relate cost to 

visibility improvement. 

Response: As noted in responses to 

other comments, we have not 

established specific thresholds for the 

cost and visibility factors for BART. 

NPS is therefore correct to note that 

BART determinations made by EPA may 

not precisely align along a specific set 

of $/ton or deciview improvement 

values. Further, even where the costs of 

compliance and expected degree of 

visibility improvement are similar at 

two different sources, consideration of 

other statutory factors may result in 

different outcomes.66 With regard to 

determinations made by state agencies, 

we note that the RHR provides states 

with significant discretion in 

considering and weighing the five BART 

factors, so long as the factors are 

appropriately evaluated and the state’s 

determination is supported by reasoned 

explanations for adopting the 

technology-based limits selected as 

BART. As a result, while a direct 

comparison of $/ton and deciview 

improvement values associated with 

BART determinations from multiple 

state agencies and EPA is informative 

and should carry weight in the ultimate 

decision, such comparisons are not 

outcome determinative. 

Comment: NPS indicated that it has 

collected and reviewed close to 100 

BART determinations for EGUs and has 

found that the average cost per deciview 

for NOX reductions at EGUs is $14 

million and the maximum cost per 

deciview is $34 million based on the 

Class I area with highest visibility 

improvement. NPS asserted that the $14 

million figure is a good indication of the 

value states have placed upon reducing 

NOX for visibility purposes. 

Response: We agree with NPS that 

cost per deciview improvement is 

informative as a cost-effectiveness 

metric, including comparing the effect 

of controls on sources located in 

different parts of the country. We 

provided calculations of this metric in 

our proposal for this action. However, 

consistent with the BART Guidelines,67

we have relied more heavily on costeffectiveness calculated as cost per 

pollutant ton reduced and related 

visibility improvements in deciviews 

(both at individual areas and as a 

cumulative sum over all affected areas) 

as opposed to the cost per deciview 

metric. 

Comment: NPS expressed support for 

EPA’s inclusion of the cumulative 

visibility impacts and improvements 

associated with the control scenarios 

that were considered, noting that the 

EGUs evaluated are unusual because 

they impact from ten to 15 Class I areas 

within 300 kilometers (km). 

Response: We agree with NPS that it 

is important to account for visibility 

impacts at multiple Class I areas, given 

that the goal of the visibility program is 

to remedy visibility impairment at all 

Class I areas.68 The cumulative sum, 

while not the only means of analyzing 

benefits across multiple Class I areas, is 

an easily understood and objective 

method of weighing cumulative 

visibility improvement, and is useful as 

part of the overall BART determination. 

Comment: TEP stated that EPA should 

adopt version 6.42 of CALPUFF as the 

approved regulatory version for 

modeling regional haze, since this 

version corrects deficiencies in the 

chemistry and the dispersion functions 

of CALPUFF version 5.8. TEP indicated 

that several studies conducted over the 

last few years demonstrate that the 

deficiencies in version 5.8 result in 

over-estimation of the visibility impacts 

of NOX emissions in Class I areas. This 

causes erroneous over-estimation of the 

visibility improvements from proposed 

BART controls leading to biased costbenefit values. 

Response: We disagree with TEP for 

two reasons. First, CALPUFF 5.8 is 

approved as a regulatory model for use 

by EPA in regional haze determinations. 

CALPUFF version 5.8 has been 

thoroughly tested and evaluated, and 

has been shown to perform consistently 

with the initial 2003 version in the 

analytical situations for which 

CALPUFF has been approved. 

CALPUFF 6.42 is not an approved 

regulatory model because CALPUFF 

6.42 has not yet undergone adequate 

review. We relied on version 5.8 of 


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69Memorandum in docket, ‘‘Full Technical 

Response to Modeling Comments for June 2014 

Final Arizona Regional Haze FIP (Phase III),’’ 

Colleen McKaughan and Scott Bohning, EPA, June 

16, 2014. 

70 Interagency Work Group on Air Quality 

Modeling (IWAQM) Phase 2 Summary Report And 

Recommendations For Modeling Long Range 

Transport Impacts (EPA–454/R–98–019), EPA 

OAQPS, December 1998, http://www.epa.gov/

scram001/7thconf/calpuff/phase2.pdf. 

71Memorandum in docket, ‘‘Full Technical 

Response to Modeling Comments for June 2014 

Final Arizona Regional Haze FIP (Phase III),’’ 

Colleen McKaughan and Scott Bohning, EPA, June 

16, 2014. 

72 78 FR 46142. 

73 40 CFR part 51, appendix Y, section III.A.3. 

74Federal Land Managers’ Air Quality Related 

Values Work Group (FLAG) Phase I Report— 

Revised (2010) (FLAG 2010) at 23; National Park 

Service Comments on EPA Review of Arizona 

Department of Environmental Quality (ADEQ) 

Determinations of Best Available Retrofit 

Technology (BART) at 2–3, and Reasonable Progress 

(RP) March 6, 2013. 

75 40 CFR part 51, appendix Y, section III.A.3. 

CALPUFF because it is the EPAapproved version in accordance with 

the Guideline on Air Quality Models 

(‘‘GAQM’’, 40 CFR part 51, Appendix 

W, section 6.2.1.e). We updated the 

specific version to be used for regulatory 

purposes on June 29, 2007, including 

minor revisions as of that date. Second, 

EPA took into account limitations with 

Version 5.8 when it suggested use of the 

98th percentile day versus the 

maximum day.69

Comment: TEP commented that the 

background ammonia concentration 

used in visibility modeling is critical 

because ammonia is a precursor to 

particulate ammonium nitrate. EPA’s 

use of 1.0 parts per billion (ppb) for 

ammonia background concentration for 

all months of the year will tend to 

overestimate the visibility benefits 

associated with reductions of NOX, 

particularly in the winter months. TEP 

noted that monthly ammonia 

measurement data from the IMPROVE 

monitoring network site in southern 

Arizona (Chiricahua) indicate that 

ammonia concentrations below 1.0 ppb 

(e.g., 0.5 ppb) are present at this site 

during the winter months. TEP asserted 

that use of those values will more 

accurately predict the visibility 

improvements expected from the 

reductions in NOX emissions. Although 

TEP did not perform any new modeling 

for comparison to EPA’s results in the 

proposal, TEP sent a letter to EPA in 

May 2013 that provided clarification 

regarding certain modeling parameters 

and the results of modeling performed 

by TEP’s contractor (AECOM). 

According to TEP, the modeling 

performed by AECOM included a BART 

control scenario involving SNCR and 

DSI, similar to EPA’s proposed BART 

determination for Sundt Unit 4. The 

results of AECOM’s modeling was a 

maximum visibility improvement of 

0.16 dv at Saguaro National Park East 

compared to the baseline case. The TEP 

noted that EPA’s modeling representing 

the same control configuration (SNCR 

and DSI) reported a maximum visibility 

improvement of 0.49 dv. TEP 

acknowledged that these differences in 

modeling results have little practical 

effect, as EPA has proposed that its 

results support a BART determination 

involving application of SNCR and DSI 

on Sundt Unit 4, and TEP does not 

dispute that overall finding. However, 

should EPA find a need to do additional 

modeling to support its final BART 

determination for Sundt Unit 4, TEP 

recommended that EPA incorporate the 

modeling improvements suggested in 

TEP’s letter of May 10, 2013. 

Response: We disagree that the 1.0 

ppb ammonia background we assumed 

for CALPUFF modeling is too high. It is 

consistent with EPA guidance given that 

some ammonia measurements are 

higher than 1.0 ppb, and the available 

ammonia data is variable over the areas 

included in the visibility modeling. The 

uncertainty over appropriate ammonia 

values leaves us without a reasonable 

basis for choosing a different constant 

value, or a more complex monthly 

varying scheme as recommended by the 

commenter. Ambient ammonia 

measurements for use as input to 

modeling are scarce, and measurements 

that include it in the form of ammonium 

still scarcer. In the absence of 

compelling ammonia background 

estimates, the EPA Interagency Work 

Group on Air Quality Modeling 

(IWAQM) Phase 2 guidance 

recommends the use of a 1.0 ppb 

ammonia background for arid lands, 

which includes Arizona.70 This is the 

only guidance available on this issue. It 

is worth noting that there are 

measurements of gaseous ammonia 

(NH3) that by themselves are close to or 

greater than 1.0 ppb, even in winter.71

Therefore, we consider the 1.0 ppb 

ammonia background that we used to be 

appropriate for this action. Finally, we 

agree with the commenter that the 

recommended modeling changes would 

have little practical effect on the BART 

determination for Sundt Unit 4. 

B. Nelson Lime Plant Kilns 1 and 2 

1. Subject to BART Determination 

Comment: ADEQ asserted that EPA 

improperly disapproved ADEQ’s finding 

that Nelson Lime Plant is not subject to 

BART. ADEQ argued that ADEQ’s use of 

a three-year average 98th percentile 

value ‘‘appropriately recognizes the 

highly variable visibility conditions that 

prevail in western states due to periodic 

wildfires that can result in short-term 

spikes in visibility impairment’’ and is 

consistent with how EPA determines 

compliance with certain NAAQS. 

Response: These comments largely 

pertain to EPA’s partial disapproval of 

the Arizona RH SIP and are therefore 

untimely, as EPA has already taken final 

action on the SIP.72 To the extent that 

the comments dispute EPA’s proposed 

determination that the Nelson Lime 

Plant is subject to BART under the FIP, 

we disagree with the substance of their 

argument. The BART Guidelines 

recommend use of the 98th percentile 

modeled visibility impact across 

multiple years of modeling in order to 

identify sources that cause or contribute 

to visibility impairment in a Class I 

area.73 There are at least three different 

ways to determine the 98th percentile 

impact across three years of modeling: 

The maximum 8th high in any one year, 

the 22nd high impact over all three 

years, or the three-year average of the 

8th high impacts from each year. Of 

these three methods, the three-year 

average is the least conservative way of 

determining the 98th percentile impact. 

Depending on the yearly distribution of 

the results, the most conservative 98th 

percentile impact may come from the 

maximum 8th highest value for each of 

the three years or the 22nd highest value 

for all years merged. While the BART 

Guidelines do not specify which value 

to use, given that the subject-to-BART 

determination is a screening test, EPA’s 

position is that a more conservative 

approach, i.e., the 22nd high of three 

merged years or the maximum 8th high 

of any one year, is more appropriate for 

this screening test. The FLMs also 

recommend a more conservative 

approach and have noted that other 

states have used such an approach.74

We also do not agree with ADEQ that 

a three-year average approach 

‘‘appropriately recognizes the highly 

variable visibility conditions that 

prevail in western states due to periodic 

wildfires that can result in short-term 

spikes in visibility impairment.’’ The 

visibility impacts of individual sources, 

including the Nelson Lime Plant, are 

determined by calculating the change in 

deciviews caused by the source 

compared to natural visibility 

conditions.75 While natural conditions 

could include short-term spikes from 

wildfires, the effect of such a spike in 

the background level of pollution is to 

decrease the relative deciview impact of 


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76See 70 FR at 39124 (‘‘as a Class I area becomes 

more polluted, any individual source’s contribution 

to changes in impairment becomes geometrically 

less’’). 

77Arizona Regional Haze SIP at 152–53, Table 

10.9 and Table 10.10. 

78See 78 FR at 46154. 

79BART Five Factor Analysis, Lhoist North 

America Nelson Lime Plant; Prepared by Trinity 

Consultants in conjunction with Lhoist North 

America of Arizona, Inc. (Public version dated 

September 27, 2013), Table 4–7. As explained in 

our proposal, these results are conservative (i.e., 

tending to overestimate rather than underestimate 

the impacts), but appropriate for purposes of a 

subject-to-BART determination. 

80 ‘‘Comments on Draft NOX Control Measure 

Summary for Lime Kilns’’, National Lime 

Association, March 30, 2006; AP–42, Section 11.6, 

Portland Cement Manufacturing; AP–42, Section 

11.17, Lime Manufacturing. 

81Non CBI—Summary of LNA Nelson March, 

May and June 2013 CEMS Testing.xlsx. 

a given source.76 Thus, the possibility of 

short-term spikes from wildfires would, 

if anything, argue for a more 

conservative approach to evaluate an 

individual source’s contribution. 

Moreover, we do not agree that the use 

of a three-year average is appropriate 

here simply because certain NAAQS use 

a three-year averaging period. Thus, 

consistent with the FLMs’ 

recommendation and with the approach 

used by EPA and other states for making 

subject-to-BART determinations, we 

find that use of the 98th percentile 

impact of any one year is appropriate for 

making subject-to-BART determinations 

for purposes of this action. 

With regard to the modeling 

performed for the Nelson Lime Plant, 

ADEQ’s comments refer to three 

different modeling analyses: (1) The 

initial modeling performed by LNA; (2) 

the refined modeling analysis performed 

by LNA using the revised IMPROVE 

equation; and (3) an additional analysis 

referred to by LNA in its comments on 

the Phase 2 proposal. ADEQ included 

the results of the first two analyses in 

the Arizona RH SIP. Both sets of results 

showed that for a single year, 2003, the 

Nelson plant’s 8th high visibility impact 

exceeded 0.5 dv.77 Under EPA’s 

interpretation of the 0.5 dv threshold, 

this makes the facility subject to BART. 

The complete results of the third 

analysis performed by LNA were not 

submitted to EPA.78 However, more 

recent modeling performed by LNA 

shows that the 98th percentile impact of 

the facility exceeds 0.5 dv in each of the 

three years modeled.79 Thus, even 

under the three-year averaging approach 

preferred by the State, the Nelson Lime 

Plant is subject to BART, according to 

the most recent modeling performed by 

the facility’s owner. As explained above, 

under EPA’s interpretation of the 0.5 dv 

threshold, the Nelson Lime Plant is 

subject to BART based on prior 

modeling. Therefore, for the reasons set 

out in our Phase 2 proposed and final 

rulemakings and in this response, we 

are finalizing our determination that the 

Nelson Lime Plant is subject to BART. 

2. BART Analysis and Determination for 

NOX

Comment: NPS indicated that it 

agrees with EPA that visibility 

improvements expected as a result of 

applying SNCR support this technology 

as BART for NOX.

Response: We agree with NPS, and 

acknowledge its support on this issue. 

Comment: ADEQ asserted that the 

three-year compliance time provided in 

the rule does not provide enough time 

to retrofit SNCR on Kilns 1 and 2 

because of the difficulty of installing 

such controls. In contrast, Earthjustice 

argued that EPA should set a one-year 

compliance deadline for the installation 

of SNCR at the plant. According to 

Earthjustice, EPA recognized in the 

proposal that SNCR can be installed in 

one year, but speculated without any 

support that it might take longer at the 

Nelson Lime Plant because of a ‘‘lack of 

information regarding SNCR installation 

schedules on lime kilns.’’ The 

commenter stated that allowing an extra 

two years without any supporting 

record violates the CAA’s requirement 

that BART be installed as expeditiously 

as practicable. 

Response: We disagree with ADEQ’s 

assertion that a three-year compliance 

schedule is too short and with 

Earthjustice’s assertion that it is too 

long. ADEQ has not provided any 

support for its assertion that three years 

is an insufficient period of time for 

installation, nor has the facility’s owner 

made such an assertion. Regarding 

Earthjustice’s contention that a shorter 

deadline is required, we note that the 

examples cited are for SNCR 

installations on cement kilns. There are 

multiple operational and design 

differences between cement and lime 

production.80 Cement and lime 

production processes are sufficiently 

different that it is not appropriate to 

assume that SNCR installation times for 

cement kilns are directly transferable to 

the application of SNCR on lime kilns. 

To our knowledge, SNCR has never 

been installed on a lime kiln. Given that 

this control technology will be 

retrofitted to a new source category for 

the first time, it is not unreasonable to 

expect unforeseen challenges and 

delays. EPA’s timeline is conservative 

and takes into account this possibility. 

Therefore, we find that a requirement to 

install SNCR within three years is 

consistent with the provisions of the 

CAA and the RHR requiring compliance 

with BART emission limits as 

expeditiously as practicable. 

Comment: Earthjustice agreed that 

SNCR is a technically feasible control 

technology at the Nelson Lime Plant, 

but disagreed that the control efficiency 

for SNCR should be limited to 50 

percent. Earthjustice stated that EPA’s 

analysis must include the most stringent 

emissions reductions possible with 

SNCR (citing the BART Guidelines), and 

asserted that SNCRs can achieve control 

efficiencies significantly higher than 50 

percent for the reasons discussed by 

Earthjustice in relation to the Clarkdale 

and Rillito cement plants. Earthjustice 

added that higher NOX reductions are 

especially appropriate at Nelson Lime 

Plant given the facility’s high baseline 

NOX emissions. Earthjustice also noted 

that EPA provided no support in the 

record for the CEMS emissions data 

used in the development of the NOX

emissions baseline. 

Response: We disagree with this 

comment. The information provided by 

Earthjustice consists of examples of 

SNCR on cement kilns. There are 

substantial differences between cement 

kilns and lime kilns that do not allow 

for direct comparisons of technical 

feasibility or control effectiveness. As 

noted previously, neither we nor the 

commenter were able to identify an 

instance of a lime kiln operating with 

SNCR in the United States. In addition, 

Earthjustice has not provided any 

information supporting an SNCR control 

efficiency more stringent than 50 

percent on a lime kiln. 

LNA has provided a summary of 

CEMS emission data, but considers it 

CBI since it also includes lime 

production data. We have included a 

summary of the lb/ton values from the 

testing period in our docket for the final 

rule because the BART limit is 

established in terms of lb/ton.81 We 

have not included the mass emission 

rates from the testing period, since 

including both the lb/hour and lb/ton 

data in the docket would allow for the 

back-calculation of the lime production 

data. 

3. BART Analysis and Determination for 

SO2

Comment: Earthjustice disagreed with 

EPA’s rejection of DSI technology based 

on cost considerations, and with EPA’s 

BART reduction approach that relies on 

a change in fuels. Earthjustice disagreed 

with what it considers EPA’s uncritical 

agreement with the company (i.e., DSI at 

40 percent reduction) and asserted that, 

given the almost 4,000 tpy of SO2


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Federal Register / Vol. 79, No. 170 / Wednesday, September 3, 2014 / Rules and Regulations 52439 

82 ‘‘LNA Nelson Control Costs (revised for Final 

Rule).xlsx.’’ 83See 79 FR 9341, Table 26. 84 77 FR 72578. The Cholla Power Plant SO2

BART limit required installation of inlet CEMS, 

with a twelve-month compliance deadline. 

85 ‘‘LNA Nelson Control Costs (revised for Final 

Rule).xlsx’’. 

emitted from the two kilns, EPA’s 

determination of the most stringent 

control efficiencies achievable should 

have been more thorough and 

technically grounded. Earthjustice 

asserted that a DSI can be optimized and 

can achieve far greater than 40 percent 

reduction, as the company’s own tests 

show (i.e., short-term efficiencies 

ranging from 17 to 84 percent). 

Earthjustice also asserted that even with 

what it considers a flawed analysis, the 

calculated cost-effectiveness value of 

about $4,000/ton reduced is well within 

acceptable ranges. As a result, 

Earthjustice disagreed with the weight 

that EPA gave to the incremental costeffectiveness values and urged EPA to 

reconsider its SO2 BART determination 

for the Nelson Lime Plant in the final 

rule. 

By contrast, NPS said that it supports 

EPA’s conclusion, noting that it is most 

important to reduce process emissions 

before adding expensive emissions 

controls. NPS indicated support for 

EPA’s decision because it generally 

favors moving toward cleaner fuels. 

After changing the fuel at the plant, 

however, NPS noted that it may be 

appropriate to revisit requiring 

emissions controls at that time. 

Response: We acknowledge NPS’s 

support on this issue. We disagree with 

Earthjustice that a more stringent DSI 

control efficiency is appropriate. 

Although the commenter notes that sitespecific test data suggest short-term 

control efficiencies as high as 84 

percent, there is no evidence that the 

upper range of short-term control 

efficiencies is sustainable over longer 

periods. As a result, when calculating 

annual emissions reductions in tpy, 

which is performed on an annual 

average basis, we do not consider it 

appropriate to use a control efficiency 

achieved over a short-term period 

because it might not achievable over a 

long-term annual average. Although 

Earthjustice asserted that the 

determination of a DSI control 

efficiency in our proposed rule should 

be more thorough and technically 

grounded, it has not provided any 

information regarding how, specifically, 

we should revise our analysis or that 

supports a more stringent control 

efficiency. 

Furthermore, as explained in more 

detail in a response to a comment from 

LNA below, the total cost figures in our 

proposed rule inadvertently omitted 

annual indirect costs. Correcting this 

error results in approximate average and 

incremental cost-effectiveness values of 

$4,800/ton and $10,200/ton for Kiln 1 

and $4,500/ton and $9,500/ton for Kiln 

2.82 The largest incremental visibility 

benefit of DSI relative to the visibility 

benefit of the proposed fuel mixture 

change at a single Class I area is 0.11 dv 

at Grand Canyon National Park.83 We do 

not consider this level of incremental 

cost to be warranted by the incremental 

visibility benefit of DSI relative to the 

fuel mixture change. However, 

additional controls for the Nelson Lime 

Plant, such as DSI, should be considered 

for purposes of ensuring reasonable 

progress in future planning periods. 

Comment: LNA determined that 

compliance with the SO2 emission 

limits within six months after the 

effective date of the final rule in the 

Federal Register, likely in July 2014, is 

not feasible. Therefore, the proposed 

six-month compliance window is 

unreasonable. Compliance with the SO2

emission limits is based on a two-step 

process: (1) Use of a CEMS to determine 

actual SO2 emissions from each kiln; 

and (2) use of daily production tonnage. 

LNA estimated that an 18-month period 

is a more reasonable compliance 

timeframe for a system that supports 

both NOX and SO2 CEMS as well as new 

weigh scales on lime storage silo 

transfer belts. 

Response: We agree that a six-month 

time period is an insufficient amount of 

time for the design, installation, and 

optimization of an SO2 CEMS in this 

case. In other cases in which 

compliance with a BART limit does not 

involve construction of add-on controls, 

but does involve installation of CEMS, 

we have provided a twelve-month 

window for compliance.84 In this case, 

taking into account that multiple CEMS 

(NOX and SO2) will need to be installed, 

and the fact that the facility does not 

currently operate with CEMS, may not 

have existing systems or infrastructure 

in place, and is replacing lime weigh 

scales, we consider an 18-month 

compliance time frame to be as 

expeditious as practicable. Therefore, 

we are revising the compliance deadline 

for SO2 at Nelson Lime Plant to eighteen 

months from the effective date for the 

final rule in the Federal Register. 

Comment: LNA stated that in its 

BART analysis submitted to EPA, the 

fuel mixture control option was based 

upon a maximum of 6.5 percent ash 

content in the proposed fuel mixture. 

LNA asserted that it did not choose this 

value arbitrarily, but based the value on 

operational knowledge and on 

information provided by the 

manufacturer of the kilns, Kennedy Van 

Saun (KVS). 

Response: As noted in the proposed 

rule, we used a fuel mixture consistent 

with a maximum 6.5 percent ash 

content in the SO2 BART analysis. We 

have not received any other comments 

regarding this issue, and the final SO2

limits finalized in today’s rule reflect 

this maximum ash content. 

Comment: LNA asserted that EPA’s 

estimate of the costs for DSI is 

unrealistic because EPA did not use 

site-specific input values. In addition, 

LNA said that there are errors in EPA’s 

cost calculations. LNA noted various 

issues with EPA’s cost analysis for DSI 

and asserted that the value of $4,200/ton 

of SO2 removed is too low. 

Response: We agree that our cost 

calculations contain an error in the 

‘‘cost summary’’ tab, which is also 

reflected in the TSD and in the Federal 

Register preamble to our proposed rule. 

The total annual cost for DSI should 

represent the sum of annual direct and 

annual indirect costs, but did not 

include the annual indirect cost. We 

corrected this error in a new version of 

the spreadsheet for today’s final rule.85

As a result, the average costeffectiveness values for DSI on kilns 1 

and 2 increase to about $4,800/ton and 

$4,500/ton (from $4,174/ton and $4,085/ 

ton, respectively). The incremental costeffectiveness values of DSI, relative to 

the fuel mixture change, are about 

$10,200/ton and $9,500/ton (from 

$8,803/ton and $8,576/ton, 

respectively). As noted in the proposed 

rule, we did not consider DSI to be costeffective on an incremental basis 

relative to the fuel mixture change, 

given the relatively small visibility 

benefits expected from DSI (0.10 dv at 

the most improved class I area and 0.29 

dv cumulative). Therefore, we do not 

consider DSI to be cost-effective, 

relative to the fuel mixture change, 

based on these revised and even higher 

dollar/ton values. 

LNA provided EPA with a detailed 

version of DSI cost calculations that was 

designated as CBI along with a public 

version with most of the calculations 

redacted. Because we are generally 

prohibited from disclosing CBI, we 

relied on the publicly available 

information to develop a separate set of 

calculations for the proposed rule. 

While there are several elements of our 

cost estimates that differ from LNA’s 

CBI-protected cost calculations, these 

differences are immaterial in light of our 

finding that DSI is not a cost-effective 

control option relative to the fuel 


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52440 Federal Register / Vol. 79, No. 170 / Wednesday, September 3, 2014 / Rules and Regulations 

86 42 U.S.C. 7602(k). 

87Phone call between Colleen McKaughan, EPA, 

and Ed Barry, LNA, on April 10, 2014. 

88Letter from Ed Barry, LNA, to Colleen 

McKaughan, EPA (April 29, 2014). 89Conference calls between EPA and LNA, May 

2 and 7, 2014. 90Letter from Ed Barry, LNA, to Colleen 

McKaughan, EPA (May 9, 2014). 

91 Id. 

mixture change. Therefore, we have not 

further revised our cost analysis for DSI 

based on LNA’s comments because the 

changes suggested by LNA would not 

alter our determination that DSI is not 

cost-effective for either kiln on an 

incremental basis. 

4. BART Analysis and Determination for 

PM10

Comment: ADEQ expressed support 

for EPA’s determination that the 

existing baghouse at the Nelson Lime 

Plant is BART for PM10.

Response: We acknowledge ADEQ’s 

support on this issue. 

5. Other Comments 

Comment: LNA asserted that EPA’s 

BART proposal does not provide for 

differing emission rates during startup, 

shutdown, and malfunction (SSM), and 

stated that EPA should reconsider this 

decision that is not supported by the 

available information. The CEMS data 

for NOX and SO2 that LNA submitted in 

its BART analysis is based on periods of 

steady-state operation that does not 

include periods of startup and 

shutdown. Since the CEMS data do not 

include these emissions, LNA did not 

consider it appropriate for the proposed 

limits to include emissions from startup 

and shutdown. LNA proposed that the 

rolling 30-day limits in the proposed 

rule should apply only during periods 

of normal operation, and proposed 

establishing separate emission limits 

during periods of startup and shutdown. 

LNA provided emissions data for each 

of the various types of startup and 

shutdown events. 

Response: We agree that the emission 

limits in the proposed rule did not 

account for emissions from periods of 

startup and shutdown and we agree that 

the emission limits should include such 

periods. Because Section 302(k) of the 

CAA requires emission limits such as 

BART to be continuous,86 BART 

emission limits must apply at all times, 

including during periods of startup, 

shutdown, and malfunction. We 

therefore consider it appropriate to 

revise the proposed emission limits for 

NOX and SO2 to account for emissions 

from periods of startup and shutdown. 

In order to revise the emission limits to 

appropriately account for startup and 

shutdown emissions, we sought 

additional information from LNA 

following the close of the public 

comment period.87 In response, LNA 

suggested retaining the rolling 30-day 

limits that would apply at all times, but 

revising them upward to accommodate 

startup and shutdown emissions.88

Following further discussions between 

EPA and LNA,89 LNA proposed revising 

the rolling 30-day limit to an annual 

average limit that would apply at all 

times.90 LNA also proposed establishing 

short-term ton/day limits for the Kilns, 

which would correspond to the shortterm 24-hour average emission rates 

used in the visibility modeling.91

Based on our evaluation of the 

additional information provided by 

LNA, we are making the following 

revisions to the proposed emission 

limits. First, we are revising the lb/ton 

limits from a rolling 30-day basis to a 

rolling 12-month basis. As described in 

LNA’s comments, periods of startup can 

exhibit substantial emissions, but with 

little to no lime production. While these 

startup emissions are not higher than 

those observed during normal operation 

on a simple mass basis (e.g., lb/hour, or 

ton/day), the fact that there is no 

production associated with these 

emissions complicates their inclusion 

when determining compliance with a 

lb/ton limit. As a result, the particular 

day(s) during which a startup event 

occurs will appear as a short-term spike 

in the kiln’s emission rate (lb/ton). 

When combined with the preceding 29 

days of emission data, this emission 

spike has the effect of driving the rolling 

30-day emission rate (lb/ton) upwards. 

It may then be necessary for the unit to 

operate at a much lower rate of 

emissions over the next 29 days in order 

to ensure compliance with the 30-day 

limit, which may not be technically 

feasible. By establishing the limit on a 

rolling 12-month basis, such short-term 

spikes are averaged with data values 

from over an entire year, making its 

impact on the rolling emission rate less 

pronounced. 

Second, in order to ensure that 

performance of the SNCR system 

installed at the Nelson Lime Plant is 

optimized, we are including in the final 

rule a series of control technology 

demonstration requirements. In 

particular, LNA is required to prepare 

and submit to EPA: (1) A design report 

describing the design of the ammonia 

injection system to be installed as part 

of the SNCR system; (2) data collected 

during a baseline period; (3) an 

optimization protocol; (4) data collected 

during an optimization period; (5) an 

optimization report establishing 

optimized operating parameters; and (6) 

a demonstration report including data 

collected during a demonstration 

period. While this type of control 

technology demonstration is not 

typically required as part of a regional 

haze plan, we consider it to be 

appropriate here, given the minimal 

data available about the performance of 

SNCR at lime kilns. Based upon the data 

collected during this process, EPA may 

revise the rolling 12-month average for 

the NOX emission limit in a future 

notice-and-comment rulemaking action. 

Third, we are establishing short-term 

24-hour average emission limits (ton/

day) consistent with the emission rate 

used in the visibility modeling for each 

respective control option. As noted 

above, revising the averaging period to 

an annual basis minimizes the effect of 

short-term spikes in emissions over a 

greater data set. In effect, this allows the 

Nelson Plant greater short-term 

emissions variability while still 

demonstrating compliance with the 

BART limit. To ensure that this 

variability does not interfere with the 

modeled visibility benefit, which is 

based upon reductions from the highest 

24-hour average emission rate, we are 

establishing short-term ton/day 

emission limits. These limits are 

combined limits that apply across both 

Kiln 1 and 2, on a rolling 30-kiln 

operating day basis. We are finalizing a 

combined Kilns 1 and 2 NOX limit of 

3.20 tons/day and SO2 limit of 10.10 

tons/day. 

C. Comments on the Hayden Smelter 

1. General Comments 

Comment: ASARCO agreed with the 

BART Guidelines ‘‘that BART is not ‘to 

redesign the source,’ ’’ and stated this 

understanding is inherent in Congress’ 

denomination of the technology as ‘‘best 

available retrofit technology.’’ 

Response: We agree that BART does 

not require redesign of the source. 

Comment: ASARCO noted that the 

BART Guidelines are not ‘‘mandatory’’ 

as applied to the Hayden Smelter, and 

that EPA must depart from them if 

presented with sound technical 

justification. 

Response: We agree that the BART 

Guidelines are not binding with respect 

to the Hayden Smelter, but note that the 

BART Guidelines serve as persuasive 

guidance for all BART sources. 

Comment: ASARCO stated that, as 

further changes to air pollution controls 

at the Hayden Smelter will be required 

to demonstrate attainment of the 1-hour 

SO2 NAAQS, ASARCO supports EPA’s 

proposal to promulgate ‘‘a performance 

standard as BART rather than 


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92 78 FR 46142. 

93 40 CFR part 51, appendix Y, section IV.D.2. 

94 Id. 

95See Id. 

96 1984 NSPS Review at 4–3. 

97This is the name of the company. 

98See Letter from Steven Puricelli, MECS, to Matt 

Russell, GCT (March 5, 2014)(‘‘MECS Letter’’) (‘‘A 

double acid plant could operate with this low 

secondary gas concentration . . .’’); Letter from 

Matt Russell, GCT, to Jack Garrity, ASARCO (‘‘GCT 

Letter’’)(February 12, 2014) at 2 (‘‘it may be 

technically feasible to operate an acid plant on the 

converter secondary gases . . .’’). 

prescribing a particular method of 

control,’’ if EPA determines additional 

controls are needed. ASARCO stated 

that reconfiguration of the smelter might 

be required to attain the 1-hour SO2

NAAQS in the form of a ‘‘converter 

retrofit project’’ or CRP. ASARCO 

argued that while detailed engineering 

of the CRP is substantially completed, 

details must be worked out before the 

final project can be permitted. Thus, 

ASARCO concluded that it is critical for 

EPA not to finalize a BART FIP for SO2

that interferes with the Hayden area’s 

attainment of the SO2 NAAQS. 

Similarly, ADEQ urged EPA to 

reevaluate its SO2 BART decision for the 

Hayden Smelter and align it with 

controls that ASARCO has to implement 

in order to comply with the 1-hour SO2

NAAQS. 

Response: Following the close of the 

public comment period, ASARCO 

provided us with additional information 

concerning the CRP, including a 

description of plans to replace the 

BART-eligible Peirce-Smith converters 

with new converters. If the BARTeligible converters are replaced prior to 

the BART compliance deadline, then 

the BART requirements would no longer 

apply. Accordingly, there is no basis to 

expect that the RH FIP will interfere 

with ASARCO’s ability to ensure 

attainment of the SO2 NAAQS. We also 

agree that a performance standard rather 

than a particular method of control is 

appropriate for BART. As explained 

further below and in a revised BART 

determination included in the docket 

for this final rule, ASARCO has 

demonstrated that separate levels of 

control are necessary for the primary 

and secondary capture systems. 

Therefore, we are setting the level of 

control to 99.8 percent (equivalent to 

the existing double contact acid plant) 

for the primary capture system and 98.5 

percent for the secondary capture 

system. These limits only apply if 

ASARCO does not replace the BARTeligible converters prior to the BART 

compliance deadline. 

2. BART Analysis and Determination for 

SO2 From Converters 

Comment: ADEQ said that EPA’s 

disapproval of ADEQ’s SO2 BART 

determination for the Miami and 

Hayden Smelters is unsupported. 

Similarly, AMA requested that EPA 

reconsider its decision to disapprove 

parts of the Arizona RH SIP because the 

State should make a BART 

determination for the smelters according 

to the CAA. 

Response: These comments concern 

EPA’s partial disapproval of the Arizona 

RH SIP and are therefore untimely, as 

EPA has already taken final action on 

the SIP.92 The commenters have 

provided no legal basis for EPA to 

reconsider that action. 

Comment: NPS expressed support for 

EPA’s decisions based on the expected 

substantial visibility improvements 

associated with installing a new acid 

plant as BART for SO2 at the Hayden 

Smelter. In particular, NPS agreed with 

EPA’s decisions to protect many Class I 

areas. 

Response: We appreciate NPS’s 

support and note that the BART level of 

control for the converters is a 

performance standard and not any 

particular method of control. 

Comment: ASARCO, ADEQ, and 

AMA expressed doubt over the 

technical feasibility of a double contact 

acid plant for controlling secondary 

ventilation gases. ASARCO asserted that 

acid plants are not an ‘‘applicable’’ 

technology, and therefore, not an 

‘‘available’’ technology for controlling 

secondary ventilation gases because of 

low concentrations of SO2 and high 

variability in the exhaust gas stream. 

ASARCO stated that EPA failed to 

evaluate the technical feasibility of 

double contact acid plants when 

applied to these low-strength gases, 

which is the second step of a BART 

analysis. ASARCO argued that, had EPA 

conducted an adequate analysis, it 

would have concluded that double 

contact acid plants are not an 

‘‘applicable’’ technology because they 

do not have a ‘‘practical potential for 

application’’ to the secondary 

ventilation gases and hence are not an 

‘‘available’’ technology. ADEQ and 

AMA echoed ASARCO’s comments, 

urging EPA to look at the information 

submitted by ASARCO and reconsider 

its proposal. 

Response: We do not agree that a 

double contact acid plant is technically 

infeasible for the secondary gas stream 

at the Hayden Smelter. As explained in 

the BART Guidelines, control 

technologies are technically feasible if 

either (1) they have been installed and 

operated successfully for the type of 

source under review under similar 

conditions, or (2) the technology could 

be applied to the source under review.93

The BART Guidelines further explain 

that the regulatory authority must 

exercise technical judgment in 

determining whether a control 

alternative is applicable to the source 

type under consideration. In most cases, 

a commercially available control option 

is presumed applicable if it has been 

used on the same or a similar source 

type. Absent a showing of this type, one 

must evaluate technical feasibility by 

examining the physical and chemical 

characteristics of the pollutant-bearing 

gas stream, and comparing them to the 

gas stream characteristics of the source 

types to which the technology had been 

applied previously.94 In this instance, a 

double contact acid plant is already in 

use at the Hayden Smelter. Therefore, it 

is presumed to be an applicable 

technology, absent a demonstration that 

specific circumstances preclude its 

application to a particular emission 

unit. Generally, such a demonstration 

involves an evaluation of the 

characteristics of the pollutant-bearing 

gas stream and the capabilities of the 

technology.95 No such demonstration of 

technical infeasibility has been made 

here. On the contrary, the record 

establishes that a double contact acid 

plant is feasible for the secondary gas 

stream at the Hayden Smelter. 

In particular, while the secondary gas 

stream has a lower SO2 concentration 

and higher volumetric flow rate than the 

primary gas stream, these differences do 

not render a double contact acid plant 

technically infeasible. Indeed, EPA 

concluded more than 30 years ago that 

‘‘[i]t is technically feasible . . . to 

design acid plants that will operate 

auto-thermally on feed streams that 

exhibit SO2 concentrations below the 

3.5 to 4.0 percent range.’’ 96 The 

commenters have offered no evidence to 

refute this conclusion. Contrary to the 

commenters’ suggestions, ASARCO’s 

contractors, Gas Cleaning Technologies 

(GCT) and MECS,97 have not stated that 

use of a double contact acid plant is 

technically infeasible.98 Rather, they 

have indicated that use of this 

technology would present additional 

technical challenges that would make it 

more costly and less effective than 

estimated by EPA. In particular, GCT 

states that ‘‘[a] more realistic 60 ppmv 

[parts per million by volume] outlet 

concentration would mean only 96 

[percent] SO2 removal efficiency by 

such an acid plant at ASARCO. . . . 

when a realistic capital cost and 

removal efficiency is used for the acid 

plant, the $/ton SO2 removed estimate 

will be more than double the $872/ton 


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52442 Federal Register / Vol. 79, No. 170 / Wednesday, September 3, 2014 / Rules and Regulations 

99 GCT Letter at 2 (‘‘A more realistic 60 ppmv 

outlet concentration would mean only 96% SO2

removal efficiency by such an acid plant at 

ASARCO . . . when a realistic capital cost and 

removal efficiency is used for the acid plant, the 

$/ton SO2 removed estimate will be more than 

double the $872/ton SO2 indicated by EPA.’’). 

100 40 CFR part 51, appendix Y, section IV.D.2. 

101The original comment referred to a ‘‘0–0.1’’ 

percent concentration for secondary ventilation 

gases. ASARCO Comment Letter at 9. However, this 

appears to be an error, as the same letter also states 

that ‘‘[a]t the Hayden Smelter, the SO2 content of 

secondary ventilation gas ranges from 0 to 1 

[percent] SO2 or approximately 0 to 10,000 ppm, 

and averages 1580 ppm.’’ ASARCO Commenter 

Letter at 5. 

102MECS Letter at 1; GCT Letter at 2. 

103Revised BART Analysis for SO2 at ASARCO 

Hayden—Converters 1, 3, 4, and 5 (June 2014). 

104 GCT Letter at 4. 

105 ‘‘AP 42’’ refers to EPA’s Compilation of Air 

Pollutant Emission Factors. See http://

www.epa.gov/ttnchie1/ap42/. 

SO2 indicated by EPA.’’ 99 However, as 

explained in the BART Guidelines, 

where the resolution of technical 

difficulties is merely a matter of 

increased cost, you should consider the 

technology to be technically feasible.100

Therefore, in this instance, EPA 

considers a double contact acid plant to 

be a technically feasible option for 

control of the secondary gas stream. 

ASARCO’s assertions regarding costeffectiveness are addressed below. 

Comment: ASARCO stated that there 

are deficiencies in EPA’s cost analysis 

for an acid plant. First, ASARCO 

asserted that EPA cannot rely upon the 

cost formula from the 1984 NSPS 

Review for an acid plant without 

validating current costs and, as a result, 

has substantially underestimated the 

cost of the proposed acid plant for the 

secondary ventilation gases. ASARCO 

stated that the equation that EPA used 

was derived from double-contact acid 

plants that were processing primary 

ventilation gases with significantly 

higher SO2 concentration (4.5 percent to 

8.0 percent) and flow rates up to 

140,000 standard cubic feet per minute 

(scfm). This compared to rates for 

secondary ventilation gases at 0 to1 

percent SO2 and 275,000 scfm.101

ASARCO stated that EPA’s 

extrapolation to lower concentrations 

cannot be justified because none of the 

data points included double-contact 

acid plants treating secondary 

ventilation gases, for which MECS gave 

a significantly higher cost estimate. 

Second, ASARCO stated that 

supplemental heating of the acid plant 

influent gas is required, but there is no 

supplemental heat available to reduce 

heat load requirements as suggested by 

EPA. ASARCO noted that GCT 

evaluated the potential for using 

existing sources for heat and concluded 

that it ‘‘does not expect any available 

heat source to be able to provide more 

than a small percentage of the heat 

required.’’ ASARCO added that EPA 

does not appear to have accounted for 

the additional heat required after the 

interpass absorption process, nor the 

additional electrical energy associated 

with handling this larger volume of 

secondary ventilation gases. 

Third, ASARCO stated that EPA failed 

to account for other costs including 

dehumidification, which is expensive 

due to equipment installation and 

maintenance costs as well as the energy 

required to run the refrigeration system. 

ASARCO also stated that the incoming 

gas stream will require added 

compensatory preheating of the gas 

stream, which is an additional energy 

requirement that EPA does not appear to 

have addressed. Finally, ASARCO 

stated that EPA cannot reduce the cost 

to control secondary ventilation gas by 

shifting additional gas to the primary 

acid plant because the existing plant 

does not have the capacity to take any 

secondary gases without converter 

retrofit. 

Based on the foregoing, ASARCO and 

ADEQ asserted that EPA had 

underestimated the cost of a new acid 

plant by at least a factor of two. 

Response: We do not agree that the 

cost estimates provided by MECS and 

GCT are more accurate than EPA’s cost 

estimates because both contractors 

characterized their estimates as 

‘‘ballpark,’’ ‘‘approximate,’’ and ‘‘orderof-magnitude.’’ 102 Nonetheless, we note 

that, even if our original cost estimate 

for an acid plant of $872/ton is 

increased by a factor of two, as 

suggested by the commenter, this would 

result in control costs of about $1,800/ 

ton of SO2. We consider $1,800/ton of 

SO2 to be very cost-effective, especially 

in light of the large visibility benefits 

that are expected to result from these 

controls. However, based on additional 

information provided by ASARCO, we 

have revised our BART analysis in 

several respects, including the addition 

of an amine scrubber as a third control 

option. As explained in a revised BART 

analysis included in the docket for the 

final rule,103 we find that an amine 

scrubber would result in greater 

emission reductions and would be even 

more cost-effective than an acid plant. 

Therefore, we are revising our BART 

determination to reflect use of an amine 

scrubber rather than an acid plant for 

the secondary stream. 

Comment: ASARCO stated that EPA 

underestimated the costs of wet 

scrubbing. For example, ASARCO 

asserted that the TSD does not address 

the technical feasibility of applying 

caustic wet scrubbing to the 

characteristics of the secondary 

ventilation gases at the Hayden Smelter 

compared to other applications for 

caustic wet gas scrubbing. ASARCO 

asserted that these differences affect the 

design basis and capital and operating 

costs associated with caustic wet 

scrubbing. ASARCO further noted that 

EPA omitted the cost of treating or 

landfilling the sludge from the caustic 

wet scrubbers, installing and operating 

a booster fan, and possible stack 

modifications. ASARCO stated that its 

own estimates for treating and 

landfilling the sludge are more than 

double EPA’s total annual cost estimate. 

Response: In the proposed FIP, we 

estimated an annual cost of $972/ton to 

control SO2 from the secondary gas 

stream using a caustic wet scrubber. 

This estimate is based on cost 

information provided by ASARCO. If we 

increase the sludge disposal costs to the 

degree that ASARCO proposes while 

simultaneously increasing the control 

efficiency from 85 to 90 percent as 

ASARCO suggested,104 our estimate of 

annual costs range from $909/ton, if the 

sludge is treated as solid waste, to 

$1,291/ton, if all sludge is treated as 

hazardous waste. We consider any cost 

in this range to be highly cost-effective. 

However, as explained in our revised 

BART analysis, use of a wet scrubber is 

more expensive on a $/ton basis and 

would result in fewer emissions 

reductions than an amine scrubber. 

Therefore, we consider a control 

efficiency of 98.5 percent, achievable 

with an amine scrubber, to constitute 

BART. 

Comment: ASARCO stated that EPA 

failed to properly consider the energy 

and non-air quality environmental 

impacts of compliance, which is the 

second BART factor. ASARCO asserted 

that the energy requirements for the 

proposed acid plants for the secondary 

ventilation gases are excessive and 

would require additional heat 

supplementation and additional 

electrical energy associated with 

handling the larger volume of secondary 

ventilation gases compared to primary 

ventilation gases. ASARCO also stated 

that the collateral emissions from 

preheating would be excessive. 

ASARCO provided a table using AP– 

42105 for large boilers and assuming low 

NOX burners, which shows that the acid 

plant will cause a net increase in 

pollutants. This increase, according to 

ASARCO, would be greater than the 

actual NOX emissions from the BARTeligible units. 


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106Letter from Jack Garrity, ASARCO to Thomas 

Webb, EPA, July 11, 2013 at 15. 

Response: We do not agree that we 

failed to properly consider the energy 

and non-air quality environmental 

impacts of compliance. We have 

weighed these impacts along with the 

other four BART factors in reaching a 

BART determination. In particular, we 

do not agree that the energy 

requirements for the proposed double 

contact acid plant for secondary 

ventilation gases are excessive. On the 

contrary, we consider these impacts to 

be reasonable given the significant 

emission reductions and associated 

visibility benefits. Finally, we expect 

that any new combustion equipment 

required to heat the secondary stream 

will emit well below the AP–42 levels, 

which were published in 1998. 

However, if they were to emit at the 

levels claimed by the commenter, these 

emissions would have a far lower 

impact on visibility than the thousands 

of tons of SO2 presently emitted 

annually through the annular stack. In 

particular, the increases in the major 

visibility-impairing pollutants cited by 

the commenter (68.5 tpy of NOX, 0.29 

tpy of SO2 and 3.7 tpy of PM) are quite 

modest in comparison to the projected 

reductions in SO2 of about 20,000 tpy 

resulting from these controls. 

Comment: ASARCO stated that the 

volume of wet scrubber sludge creates 

collateral environmental impacts, such 

as increased truck emissions, truck 

traffic, risks of accidents, and 

consumption of landfill space. 

Response: Most of the impacts noted 

by ASARCO are either air impacts (e.g., 

increased truck emissions) or nonenvironmental impacts (e.g., risk of 

accidents), and therefore do not fall 

within the scope of ‘‘energy and non-air 

quality environmental impacts.’’ With 

regard to the consumption of landfill 

space, we consider this impact to be 

reasonable in relation to the large 

visibility benefits and modest costs of 

control. As noted above, even if we were 

to double the sludge disposal costs, our 

estimate of annualized costs would not 

increase significantly. 

Comment: ASARCO stated that EPA 

has not demonstrated that its proposed 

SO2 removal rate (52.145(l)(4)(i)) is 

achievable in practice by the existing 

primary acid plant. ASARCO asserted 

that EPA cannot use a 365-day average 

performance estimate as a 30-day limit 

because the 99.8 percent estimate is 

based on what the acid plant will 

achieve on average over the course of a 

year. ASARCO stated that a 30-day limit 

forces the existing acid plant to perform 

better than an annual limit even though 

EPA did not undertake a BART analysis 

to support the lower 30-day limit. 

Further, ASARCO stated that the 

proposed removal rate applies to 

periods that contain SSM events, which 

typically are not included in annual 

acid plant performance estimates or 

vendor guarantees. Therefore, ASARCO 

concluded that no data exists to support 

EPA’s inclusion of SSM emissions in 

the proposed limit. ADEQ also 

suggested that EPA may have 

misinterpreted information provided by 

ASARCO concerning the performance of 

the primary acid plant, converting the 

annual design value to a rolling 30-day 

limit. 

Response: We agree that the control 

efficiency was determined using annual 

production and emissions data. Based 

on this information, we have modified 

the final determination so that the limit 

on the double contact acid plant is a 

rolling 365-day average rather than a 

rolling 30-day average. This revision 

also addresses ASARCO’s concern 

regarding SSM emissions because the 

99.81 percent control efficiency estimate 

provided by ASARCO includes all 

emissions going to the acid plant and 

therefore accounts for startup and 

shutdown emissions.106 Furthermore, 

excess emissions from malfunctions are, 

by definition, unforeseeable and 

therefore cannot be accounted for 

within an emission limit. 

Comment: ASARCO stated that EPA’s 

proposed method for the determination 

of compliance with the proposed limit 

is subject to significant error. 

Specifically, ASARCO stated that the 

measurement error in its tailstack CEMS 

is ‘‘sufficient to vary calculated results 

a full 0.1 [percent]’’ and ‘‘[t]he 

measurement error on the strong gas 

analyzer is nearly as great as the span 

of the tail gas CEMS.’’ ASARCO added 

that its measurements of sulfuric acid 

production also ‘‘lack the precision and 

accuracy needed for continuous 

demonstration of compliance.’’ AMA 

also asserted that it is not technically 

feasible to continuously measure SO2 in 

order to demonstrate compliance with 

the requirement contemplated by EPA. 

Response: We do not agree with these 

comments. Because compliance with 

the emission limit is determined on a 

cumulative mass basis over a rolling 

365-day period, it is measurable as a 

practical matter. The difference in scale 

between the inlet and outlet CEMS is 

not relevant because control efficiencies 

are calculated based on the ratio of the 

data from the two CEMS, not the 

difference. 

For example, consider a situation 

where 1,000 pounds of SO2 enters the 

acid plant and is controlled by 99.8 

percent, resulting in emissions of 2 

pounds of SO2. The inlet measurement 

could vary by 10 percent (i.e., the CEMS 

could read anything from 900 to 1,100 

pounds, which is +/- 100 pounds) 

without affecting the compliance 

measurement, which is rounded to the 

tenths place. The following sample 

calculations with varying inlet CEMS 

readings demonstrate this concept: 

The control efficiency is calculated 

using the following equation: 

(1 ¥ (SO2-out/SO2-in)) * 100 percent = 

Control efficiency as a percent 

If the inlet CEMS provides a true 

measurement, the control efficiency 

would be: 

(1 ¥ (2/1000)) * 100 percent = 99.8 

percent 

If the inlet CEMS reads 100 pounds 

low, the control efficiency would be: 

(1 ¥ (2/900)) * 100 percent = 99.778 

percent, which rounds to 99.8 

percent 

If the inlet CEMS reads 100 pounds 

high, the control efficiency would be: 

(1 ¥ (2/1100)) * 100 percent = 99.818 

percent, which rounds to 99.8 

percent 

Therefore, even if the inlet 

measurement varied by 100 pounds (10 

percent), it would not affect the control 

efficiency. Thus, the difference in scale 

between the acid plant inlet CEMS and 

tailstack CEMS is not relevant. Finally, 

we note that, while the FIP provides for 

an alternative compliance 

demonstration using acid production 

rates, we are not requiring the use of 

this method. Therefore, ASARCO may 

use the CEMS rather than acid 

production rates to demonstrate 

compliance. 

Comment: ASARCO expressed 

concern that EPA incorrectly 

characterized ASARCO as using 

‘‘limited cesium catalyst,’’ and may not 

recognize that ASARCO has already 

installed cesium-promoted catalyst to 

the extent recommended by MECS. 

Response: Our characterization of 

ASARCO’s use of cesium catalyst as 

‘‘limited’’ was not intended to suggest 

that additional cesium-promoted 

catalyst is necessary or appropriate for 

the existing double contact acid plant at 

the Hayden Smelter. Rather, we noted 

the ‘‘limited’’ use of cesium catalyst at 

the existing double contact acid plant as 

evidence that the 99.8 percent control 

efficiency achieved by the existing 

double contact acid plant is a reasonable 

estimate of the efficiency achievable at 

a new double contact acid plant. 

Comment: ASARCO stated that the 

proposed limit should be adjusted to 


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52444 Federal Register / Vol. 79, No. 170 / Wednesday, September 3, 2014 / Rules and Regulations 

107See Earthjustice Comment Letter at 31, notes 

53–56. 

108 70 FR 39164 (‘‘We do not consider BART as 

a requirement to redesign the source when 

considering available control alternatives.’’) 

109 GCT Letter at 3. 

reflect the realities of metallurgical acid 

plant operation. ASARCO added that a 

simpler measure, similar to the NSPS 

for Primary Copper Smelters’ use of a 

limit on SO2 in the tail gas, is likely a 

better solution, which would 

accommodate the process variation and 

measurement error that will be 

encountered. Until such a standard is 

developed, ASARCO asserted that the 

work practice standard in paragraph 

(l)(12) and the existing NSPS limit of 

650 ppmv, six-hour average, under 

which the smelter already achieves 

substantial emission reductions, 

provides a workable limitation to ensure 

existing emission reductions are 

maintained. 

Response: We recognize the variable 

nature of the process and the difficulty 

involved in measuring a high control 

efficiency. For these reasons, we are 

proposing a rolling 365-day average 

calculated on a cumulative mass basis. 

Furthermore, because the amount of SO2

emitted by the converters is constantly 

varying, a simple concentration-based 

limit cannot be used to demonstrate that 

the process is under control. 

Comment: ASARCO stated that 

caustic wet scrubbing of the acid plant 

tail gas is not cost-effective for BART. 

Response: We agree that adding a wet 

scrubber to scrub the acid plant tail gas 

is not cost-effective for BART. 

Comment: Earthjustice stated that its 

primary concern with EPA’s SO2 BART 

determination for the Hayden Smelter is 

the fate of the ‘‘uncaptured’’ or fugitive 

emissions which, while a large amount 

estimated at 1,209 tpy, are not 

addressed by EPA. Earthjustice 

indicated that EPA should require an 

analysis of shop ventilation using a 

computational fluid dynamic (CFD) 

model that, according to Earthjustice, is 

a common technique used to enhance 

capture of fugitive emissions in older 

shops. Earthjustice stated that requiring 

implementation of the resulting 

recommendations would enhance the 

capture system for the shop so that 

fugitive emissions are captured by a 

modified primary or secondary system, 

which would allow for treatment in the 

current/proposed emissions control 

systems (such as the PM controls and 

the acid plant). 

Response: We recognize that there is 

uncertainty in the determination of 

fugitive emissions from the Hayden 

Smelter. Therefore, rather than specify a 

capture efficiency, we have established 

a work practice standard that requires 

ASARCO to design and operate a 

secondary capture system optimized to 

capture the maximum amount of 

process off-gas vented from each 

converter at all times. In order to 

demonstrate compliance with this 

requirement, ASARCO must submit a 

written operation and maintenance plan 

to EPA for approval 180 days prior to 

the applicable compliance date and 

must comply with this plan thereafter, 

once it is approved by EPA. Since 

ASARCO has performed CFD analyses 

on the Hayden Smelter, we would 

expect the company to submit such 

analyses for review by EPA in 

determining whether the secondary 

capture system is optimized to capture 

the maximum amount of process off-gas. 

Comment: Earthjustice stated that 

EPA’s decision to split emissions 

between the baseline primary, 

secondary, and uncontrolled, 

uncaptured streams might not be 

accurate, because EPA does not provide 

any support for these emissions levels 

other than noting that they are based on 

estimates by the company. 

Response: We disagree with this 

comment, which refers to emissions 

calculations in the Arizona RH SIP and 

a comment letter from ASARCO 

regarding the SIP.107 Our BART analysis 

did not rely on these emissions 

calculations. Rather, we relied upon 

emissions data reported by ASARCO to 

ADEQ, which we consider to be the best 

emissions information available for the 

Hayden Smelter. The data for the 

primary and secondary emissions is 

based on CEMS. While there is 

uncertainty inherent in any calculation 

of uncaptured emissions, Earthjustice 

has not provided any more credible 

emissions information or provided a 

mechanism for decreasing uncertainty 

in the quantification of uncaptured 

emissions. We do not have a copy of the 

1994–1995 fugitive emissions study and 

did not rely directly on this study to 

estimate uncaptured emissions. 

Comment: Earthjustice stated that 

EPA proposed to require a 99.81 percent 

reduction of the Hayden Smelter’s SO2

emissions from the primary and 

secondary capture systems apparently 

based on the fact that the existing plant 

is capable of achieving that level of 

control. However, Earthjustice asserted 

that greater control efficiencies are 

achievable, and that EPA must therefore 

revise its BART analysis to incorporate 

the most stringent emission control 

level that the technology is capable of 

achieving (citing the BART Guidelines). 

Earthjustice, citing a paper regarding the 

Kennecott Smelter, stated that 99.95 

percent control efficiency is achievable. 

Based on another report by the 

technology vendor Cansolv, Earthjustice 

suggested that a 99.93 percent reduction 

is achievable. Earthjustice noted that the 

latter report also states that the 

CANSOLV® SO2 Scrubbing System can 

achieve an outlet SO2 concentration as 

low as 0.15 lb SO2/ton acid, as opposed 

to EPA’s proposed BART level of 2.49 

lb/ton acid. Earthjustice urged EPA to 

increase the requirement for control at 

the acid plant(s) to 99.93 percent or 

greater. 

Response: We do not agree that our 

proposal to require a 99.8 percent 

control efficiency is insufficiently 

stringent. The examples cited by 

Earthjustice are not directly comparable 

to the Hayden Smelter. The Kennecott 

Smelter uses a flash copper converting 

technology that produces copper on a 

continuous basis, unlike the Hayden 

Smelter’s batch-process system. 

Replacing the batch-process converters 

at the Hayden Smelter with continuous 

converters would require a redesign of 

the system, which is not within the 

scope of BART.108 Therefore, we do not 

consider the 99.95 percent control 

efficiency achieved at the Kennecott 

Smelter to be appropriate for 

determining BART at the Hayden 

Smelter. 

The report on the Cansolv system 

provided by Earthjustice is a 

presentation given by Cansolv 

representatives at a trade show for 

fertilizer manufacturers. The figure of 

0.15 lbs SO2 per ton of acid produced 

(10 ppmv SO2) is a low-end estimate 

and is lower than any of the outlet 

concentrations in the table of results 

provided by Earthjustice. The report did 

not provide enough information to 

allow us to determine whether any of 

the facilities listed in the table operate 

a process similar enough to batch 

process copper smelting to be directly 

comparable to the Hayden Smelter. 

However, as explained above, 

ASARCO’s contractors have stated that, 

‘‘for this application, Cansolv has 

indicated that they can achieve close to 

99 [percent] removal efficiency with a 

20 ppmv outlet gas stream.’’109

Therefore, we consider 98.5 percent to 

be a reasonable estimate of the control 

efficiency achievable with Cansolv for 

treatment of the secondary stream at the 

Hayden Smelter. 

Comment: Earthjustice stated that 

EPA should have considered DSI for the 

control of the acid plant tailstack. 

Response: We disagree with this 

comment. DSI is commonly used to 

control SO2 at combustion sources such 

as coal-fired power plants and 


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110See ‘‘Anode Furnace—DSI Cost Calculations.’’ 

We note that these capital costs in these 

calculations are based upon a much lower flowrate 

than that of the anode furnaces, Therefore, we 

consider these estimates to be very conservative 

(i.e., tending to underestimate rather than 

overestimate in this instance). 

111 78 FR 46142. 

112 40 CFR 51.308(e)(ii)(A). 

113BART Guidelines, 40 CFR Part 51, appendix 

Y, section III.A.2. 

114See, e.g. TSD at 68, Table III.D–4 (showing 

base case impact of greater than 0.5 dv at 11 Class 

I Areas). 

115 40 CFR 51.308(e)(1)(ii)(C). 

116 40 CFR 51.301. 

incinerators. DSI requires particulate 

control (e.g., a baghouse or electrostatic 

precipitator) in order to collect the used 

sorbent. Thus, DSI may be a costeffective technology when sorbent can 

be injected upstream of a particulate 

control device that either is already in 

service or otherwise required to meet a 

particulate matter limit. However, we 

are not aware of any facilities in any 

industry that use DSI downstream of an 

acid plant. Therefore, we do not 

consider it a technically feasible 

technology in this case. 

3. BART Analysis and Determination for 

SO2 From the Anode Furnaces 

Comment: Earthjustice asserted that 

the 38 tpy of SO2 emissions from the 

anode furnaces are significant, and that 

EPA has routinely controlled sources 

with this level of SO2 emissions in 

many other instances. Accordingly, 

Earthjustice urged EPA to require DSI 

for SO2 controls for the anode furnaces, 

which typically achieves emissions 

reductions in the range of 50 to 70 

percent or greater depending on process 

conditions. Earthjustice indicated that 

EPA should fully evaluate this option. 

According to Earthjustice, EPA 

suggested a work practice standard 

requiring the use of blister copper or 

higher purity copper. Earthjustice stated 

that it is unclear how this work practice 

standard will help reduce emissions 

(because presumably the anode furnaces 

are currently charged with the 98 to 99 

percent pure blister copper), or how it 

will be enforced. 

Response: At the Hayden Smelter, the 

anode furnaces are charged only with 

blister copper, which is nearly 98 

percent pure copper. While the 

estimated 38 tpy of SO2 emissions from 

the anode furnaces may not be 

‘‘insignificant,’’ they are undoubtedly 

small compared to the more than 20,000 

tpy of uncaptured emissions from the 

converters. Moreover, while Earthjustice 

asserted that ‘‘EPA has routinely 

controlled sources with this level of SO2

emissions in many other instances,’’ it 

has not provided any examples of 

controls on emissions of this level under 

the RHR. Because the potential SO2

emissions from the anode furnaces are 

quite low relative to the airflow, DSI 

would not be cost-effective for SO2

removal at roughly $25,000/ton.110 We 

have included work practice standards 

and recordkeeping requirements in the 

FIP to assure that only blister copper is 

used in the anode furnace. 

Comment: ASARCO stated that EPA 

should clarify that the requirement for 

‘‘charging’’ only high quality copper 

does not preclude fluxes and reducing 

agents such as natural gas and steam. 

ASARCO is concerned that the 

proposed language in 40 CFR 

52.145(l)(4)(v) could be misinterpreted 

to prevent the company from poling 

(i.e., reducing the metal in the furnace 

to remove oxides) or adding any final 

fluxing agents to achieve anode casting 

chemistry requirements. ASARCO 

explained that while the bulk of 

converting occurs in the converters, 

some final refining occurs in the anode 

furnaces prior to anode casting. 

Therefore, ASARCO must be able to 

‘‘pole’’ or reduce the furnace (using 

natural gas and/or steam) and add flux 

agents to achieve final chemistries. 

ASARCO suggested the following 

revision: 

Anode furnaces #1 and #2 shall only be 

charged with blister copper or higher purity 

copper. This charging limitation does not 

extend to the use or addition of poling or 

fluxing agents necessary to achieve final 

casting chemistry. 

Response: We are including this 

language in the final regulatory text 

because we base our cost calculations 

for controlling SO2 emissions from the 

anode furnaces on the current use of the 

anode furnaces, which do not process 

concentrates or matte with significant 

sulfur content. We have modified the 

regulatory language explicitly to allow 

the use of poling and fluxing agents. We 

expect any SO2 emissions resulting from 

the use of such agents to be de minimis 

because of the very low SO2 content of 

natural gas and steam. 

4. BART Analysis and Determination for 

NOX

Comment: ADEQ asserted that EPA’s 

disapproval of ADEQ’s determination 

that the Hayden and Miami Smelters are 

not subject to BART for NOX has no 

statutory basis, and that EPA’s 

imposition of BART for NOX emissions 

on smelters is arbitrary and capricious. 

ADEQ argued that it had correctly 

determined that the smelters are not 

subject to BART for NOX because: 

(1) EPA’s regulations provide that a 

facility whose potential to emit (PTE) a 

particular pollutant is below a certain 

‘‘significance’’ threshold—40 tpy for 

NOX —is automatically not subject to 

BART; and 

(2) the units’ NOX emissions do not 

cause or contribute to regional haze, 

because the modeled impacts for each 

facility’s NOX emissions are less than 

0.5 dv. 

ADEQ said that EPA argued that the 

PTE for the smelters should be 

calculated assuming continuous 

operation at maximum capacity. In 

ADEQ’s opinion, this was inconsistent 

with EPA’s acknowledgement of the 

smelters’ batch process which precludes 

continuous operation. ADEQ further 

reasoned that even if the NOX emissions 

from the smelters were above the 40 tpy 

threshold and considered significant, 

the emissions still would not contribute 

to regional haze because their impact is 

less than 0.5 dv from each of the 

facilities. The estimated visibility 

impacts from NOX emissions are 

expected to be 0.11 dv for the Miami 

Smelter and 0.01 dv from the Hayden 

Smelter, according to ADEQ. 

Response: To the extent that these 

comments concern EPA’s partial 

disapproval of the Arizona RH SIP, they 

are untimely. EPA has already taken 

final action on the SIP.111 To the extent 

that that comments dispute EPA’s 

proposed determination that the copper 

smelters are subject-to-BART for NOX, 

we disagree with their substance. Under 

the RHR, a BART determination is 

required for each ‘‘BART-eligible 

source’’ in the State that emits ‘‘any air 

pollutant’’ which may cause or 

contribute to any impairment of 

visibility in any Class I area. All such 

sources are subject to BART.112 Thus, 

EPA and states ‘‘must look at SO2, NOX, 

and direct PM emissions’’ in 

determining whether sources cause or 

contribute to visibility impairment.113

When all of these emissions are 

accounted for, the Hayden Smelter has 

a total visibility impact greater than 0.5 

dv at multiple Class I areas, and is 

therefore subject to BART.114

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 PTE for that 

pollutant is below a specified de 

minimis level, in this instance, 40 tpy 

for NOX.115 PTE is defined as the 

maximum capacity of a stationary 

source to emit a pollutant under its 

physical and operational design.116

Physical or operational limitations on 

emissions capacity (e.g., restrictions on 

hours of operation) may be taken into 

account, but only if those limitations are 

federally enforceable. 40 CFR 51.301. 

There are currently no federally 


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117See Freeport-McMoRan Copper & Gold, 

Comments on Proposed Federal Implementation 

Plan for Arizona Regional Haze (EPA–R09–OAR– 

2013–0588) and Request for Reconsideration of the 

Partial Disapproval of Arizona State 

Implementation Plan at 14. 

118 40 CFR 51.308(e). 

119BART Guidelines, 40 CFR part 51, appendix 

Y, section V. 

120 79 FR 9347 (citing Letter from Krishna 

Parameswaran, ASARCO, to Gregory Nudd, EPA 

dated March 6, 2013, page 15). 

enforceable physical or operational 

limitations that would limit the PTE of 

the BART-eligible units at either the 

Hayden or Miami Smelters below the 

NOX de minimis threshold of 40 tpy. 

Therefore, we are finalizing our 

determination that both smelters are 

subject to BART for NOX.

Comment: AMA disagreed with EPA’s 

proposed NOX emissions cap. AMA 

asserted that EPA does not have the 

authority to finalize the proposed cap 

on NOX emissions. According to AMA, 

if the source has been determined to be 

subject to BART for a particular 

pollutant, EPA has, according to the 

CAA, the following two options: (1) 

Impose BART controls based on the 

outcome of the five-factor analysis or (2) 

determine that a source’s emissions are 

de minimis and exempt them from the 

BART analysis.117 AMA said that the 

NOX emission caps are arbitrary and 

capricious and should not be included 

in the final rule. 

Response: We do not agree with this 

comment. Regional haze SIPs and FIPs 

must contain ‘‘emission limitations 

representing BART’’ for all subject-toBART sources.118 In particular, either 

the State or EPA must establish an 

enforceable emission limit ‘‘for each 

subject emission unit at the source’’ and 

‘‘for each pollutant subject to review’’ 

that is emitted from the source.119 This 

requirement applies even where BART 

is determined to be an emission limit 

consistent with existing controls. 

Otherwise, emissions could increase to 

a level where additional controls would 

be warranted for BART, but no 

mechanism would exist to require such 

controls. 

Comment: ASARCO commented that 

a traditional low-NOX burner does not 

have practical application to the 

converters. ASARCO noted that EPA 

cites ‘‘AirControlNet, Version 4.1 

documentation report by E.H. Pechan 

and Associates, Inc.’’ dated May 2006, 

section III, page 445, as support for its 

claimed 50 percent control efficiency for 

low-NOX burners in the converters and/ 

or anode furnaces. ASARCO asserted 

that this claim is erroneous because the 

report is based on NOX SIP Call data, 

which did not focus on the primary 

metals industry and is of questionable 

relevance. Further, ASARCO stated that 

EPA would need to demonstrate that 

low-NOX burner flame design and size 

constraints are appropriate for use in the 

converter and anode furnace 

architecture. ASARCO also stated that it 

is likely that low-NOX burners cannot 

achieve 50 percent control at the 

Hayden Smelter. Therefore, EPA has 

underestimated the cost of control and 

must recalculate. 

Response: ASARCO did not provide 

any documentation to support its claims 

regarding control efficiency and cost. 

Therefore, there is no basis in the record 

for EPA to revise our own estimates. In 

any case, any increases in the estimated 

cost-effectiveness of controls would not 

alter the ultimate outcome in this case, 

since we are finalizing our 

determination that BART for NOX is an 

emission limit consistent with no 

additional controls. 

Comment: ASARCO stated that BART 

does not authorize ‘‘precautionary’’ 

limits or other limits to ‘‘ensure the 

enforceability’’ of a determination that 

no controls are required. ASARCO also 

stated that EPA must increase the limit 

to account for any NOX generated by 

EPA-mandated controls. ASARCO 

asserted that EPA does not cite, nor can 

it, any legal basis for imposing an 

‘‘unqualified limit’’ where the BART 

analysis concludes ‘‘no further 

controls.’’ 

Response: We do not agree with this 

comment. RH SIPs and FIPs must 

contain ‘‘emission limitations 

representing BART’’ for all subject-toBART sources. In particular, either the 

State or EPA ‘‘must establish an 

enforceable emission limit for each 

subject emission unit at the source and 

for each pollutant subject to review that 

is emitted from the source.’’ This 

requirement applies even where BART 

is determined to be an emission limit 

consistent with existing controls. As 

explained elsewhere in this notice, we 

are finalizing our determination that the 

Hayden Smelter is subject-to-BART for 

NOX. Therefore, an emission limitation 

representing BART for NOX is required. 

We also do not agree that our 

proposed limit of 40 tpy effectively 

imposes controls. As explained in our 

proposal, the baseline emission rate of 

50 tpy used for purposes of our BART 

analysis ‘‘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.’’ 120 ASARCO has not 

retracted or modified its prior statement 

that actual NOX emissions from the 

Hayden Smelter are below 40 tpy. 

Accordingly, ASARCO should be able to 

meet a limit of 40 tpy without 

installation of any new controls. 

Furthermore, setting an emission limit 

of 40 tpy NOX satisfies the requirements 

of 40 CFR 51.308(e) for NOX and 

ensures that NOX emissions from the 

BART-eligible units will not contribute 

significantly to visibility impairment in 

the future. 

Comment: ASARCO stated that the 

long-term strategy does not require 

emission limits on the smelter, stating 

that NOX emissions from the smelter 

contribute 0.01 dv or less to regional 

haze. As such, ASARCO asserted that 

imposing limits on the smelter is not 

necessary to achieve the RPGs 

established by Arizona and, therefore, 

EPA has no legal basis for imposing a 

40 tpy cap. 

Response: We do not agree with this 

comment. As noted above, the 

promulgation of NOX limits for the 

BART-eligible units at the Hayden 

Smelter is required under 40 CFR 

51.308(e). With regard to the 

requirements of the long-term strategy, 

in addition to the requirement cited by 

ASARCO, 40 CFR 51.308(d)(3)(v)(F) 

requires consideration of the 

‘‘enforceability of emission limitations 

and control measures’’ (including BART 

emission limitations) as part of the longterm strategy. 

Comment: Earthjustice asserted that 

EPA’s analysis and conclusions 

regarding NOX emissions from the 

Hayden Smelter are flawed because EPA 

estimated the Hayden Smelter’s NOX

emissions based solely on the 

consumption of natural gas used as fuel 

in the converters and anode furnaces. 

EPA did not account for process 

emissions of NOX, such as thermal NOX. 

According to ASARCO, EPA did not 

evaluate thermal or process NOX

emissions for any of the converters and 

anode furnaces at the Hayden Smelter, 

and did not address why there would 

not be thermal NOX generation at these 

sources. Earthjustice requested that EPA 

redo its entire NOX analysis, and start 

by requiring NOX test data from the 

smelters for their various sources. 

Earthjustice stated that EPA should then 

properly assess the baseline NOX

emissions and proceed accordingly in 

terms of control technology evaluation 

and modeling, as needed. 

Earthjustice added that even if EPA 

maintains the proposed 12-month 

rolling cap of 40 tpy as BART in the 

final rule, it should require testing to 

demonstrate compliance with the BART 

limit. Earthjustice believes that such 

testing should not only ensure that the 


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121Alternative Control Techniques Document— 

NOX Emissions from Process Heaters (Revised), 

OAQPS (September 1993). 

122See 79 FR 9352. 

123 40 CFR 51.308(e). Alternatively, plans may 

include an emissions trading program or other 

alternative that achieves greater reasonable progress 

toward natural visibility conditions than sourcespecific limits. No such alternative is at issue here. 

124 Id. See also CAA section 302(y), 42 U.S.C. 

7602 (defining FIP 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.’’). 

125See 40 CFR 51.308(e) and BART Guidelines 

section V, 70 FR 39172. 

126SIP Supplement, Appendix D Section IX. This 

language appears to have been excerpted from 

ASARCO’s own BART Demonstration. Compare id. 

with letter from Eric Hiser, Counsel for ASARCO, 

to Balaji Vaidyanathan, ADEQ dated March 20, 

2013 (‘‘ASARCO’ BART Demonstration’’) at 5. 

127 40 CFR 51.301. 

128ASARCO BART Demonstration at 5 (citing 

BART Guidelines section IV.C). 

Hayden Smelter’s NOX emissions stay 

below 40 tpy, but would inform the 

analysis in 2018 for the second 

implementation period. Earthjustice 

stated that for the Hayden Smelter and 

all other sources, it is important to use 

actual emissions data based on sitespecific testing, rather than rough 

emissions estimates based on AP–42 or 

other unsupported emissions factors. 

Finally, Earthjustice stated that in 

order to more accurately determine the 

Hayden Smelter’s NOX emissions, EPA 

should also analyze NOX emissions 

from the flash furnaces which, although 

not BART-eligible, might also be 

significant sources of NOX emissions. 

Even though the flash furnaces are not 

BART-eligible, Earthjustice stated that 

EPA should require reasonable progress 

controls at the flash furnaces to put 

Arizona’s Class I areas closer to the 2064 

glide path. 

Response: We agree that some NOX

emissions might be formed in the 

converters, but we have no reliable 

means of estimating the quantity of such 

thermal NOX. We note that, because of 

the high activation energy of the 

reactions required to form NOX from 

oxygen and nitrogen, the rate of reaction 

is known to increase rapidly at 

temperatures above 1540 °C. This is 

hotter than the temperatures found in a 

Peirce-Smith converter.121

Further, we do not consider an 

evaluation of NOX emissions from the 

flash furnaces to be necessary or 

appropriate for purposes of ensuring 

reasonable progress for this planning 

period. As explained in our proposal, 

we conducted a screening of point 

sources of NOX throughout Arizona to 

determine which sources would be 

potential candidates for RP controls.122

We did not identify the flash furnaces 

at the Hayden Smelter as a potentially 

affected source because they did not 

have any reported NOX emissions. This 

evaluation should be revisited in future 

planning periods. 

5. Comments on Emission Limitations 

for PM10

Comment: Earthjustice noted that 

EPA’s BART analysis only focused on 

SO2 pollution for the various subject-toBART units at the Hayden Smelter and 

suggested that EPA note the availability 

of superior fabric filter products that can 

provide increased PM control 

capabilities. 

Response: This comment is not 

timely. We previously approved ADEQ’s 

determination that BART for PM10 at the 

Hayden Smelter is the existing controls. 

Therefore, we did not conduct a BART 

analysis for PM10.

Comment: ASARCO stated that BART 

does not authorize ‘‘precautionary’’ 

limits or other limits to ‘‘ensure the 

enforceability’’ of a no-control 

determination. ASARCO asserted that 

both ADEQ and EPA have determined 

that PM10 BART requires no more than 

existing controls. Therefore, EPA must 

rely on some legal basis for imposing a 

limit where BART establishes none. 

ASARCO stated that, at most, EPA can 

specify only the existing limits in the 

Hayden Smelter air permit. 

Response: We do not agree with this 

comment. Regional Haze SIPs and FIPs 

must contain ‘‘emission limitations 

representing BART’’ for all subject-toBART sources.123 We previously 

approved Arizona’s determination that 

existing controls constitute BART for 

PM10 at the Hayden Smelter. However, 

the SIP contained no emission 

limitation representing BART. 

Therefore, we are required to 

promulgate an emission limitation 

representing BART for PM10, as well as 

compliance requirements to ensure the 

enforceability of this emission limit as 

part of the FIP.124

Comment: ASARCO stated that EPA’s 

approval of the Arizona RH SIP’s 

‘‘demonstration’’ that no additional 

PM10 controls are warranted is not based 

in any way on 40 CFR part 63, subpart 

QQQ (NESHAP) requirements. ASARCO 

asserted that the PM10 demonstration 

and EPA’s approval of it were based on 

the CALPUFF modeling and cost alone, 

and not in any way on 40 CFR part 63, 

subpart QQQ. Thus, ASARCO stated the 

final FIP should include a 

determination that 40 CFR part 63, 

subpart QQQ requirements are not 

necessary to enforce the PM10 BART 

determination and should exclude any 

40 CFR part 63, subpart QQQ 

requirements accordingly. 

AMA expressed similar opinions and 

asserted that the Arizona RH SIP was 

not based on 40 CFR part 63, subpart 

QQQ, but rather on the determination 

that there was no significant visibility 

impact from PM emissions. AMA 

asserted that for this reason, existing 

emission limits are all that are 

appropriate for the Hayden Smelter. 

Response: We do not agree with these 

comments. As explained in the previous 

response, enforceable emission limits 

are required to implement Arizona’s 

BART determinations for PM10.125

ADEQ made the following BART 

determinations for PM10 at the Hayden 

Smelter: 

Primary Off-gas System: The existing 

combination of cyclones, wet scrubbers, and 

double contact double absorption acid plant 

represents BART for the primary off-gas 

stream because it represents the best current 

technology. BART is therefore selected as no 

further control beyond the cyclones, wet 

scrubbers, double contact double absorption 

acid plant system. 

Secondary Off-gas System: The existing 

secondary hood baghouse is determined to be 

the best retrofit technology for the secondary 

off-gas. BART is therefore selected as no 

further controls beyond the secondary hood 

baghouse. 

Tertiary Ventilation System: Given the 

extremely small visibility impact and the 

magnitude of the costs incurred, ADEQ has 

determined that tertiary ventilation control as 

BART is not a feasible option.126

ADEQ determined that the existing 

controls on the primary and secondary 

off-gas systems are the best available for 

PM10 and that tertiary ventilation 

control is not feasible for purposes of 

BART. ADEQ did not specify what 

emission limits would represent these 

existing controls. Thus, EPA must 

determine what emission limits reflect 

the ‘‘degree of reduction achievable’’ 127

by the selected control technology, in 

this case existing controls, to satisfy the 

regulatory requirements. 

In making this determination, EPA 

considered ASARCO’s own BART 

demonstration, which explicitly relies 

on the emission limits and compliance 

requirements in Subpart QQQ. In 

particular, for both the primary and 

secondary off-gas streams, ASARCO 

stated that, ‘‘[c]onsistent with the 

Guidelines, ASARCO has chosen to use 

the ‘streamlined approach’ by relying on 

the particulate limit set for an acid plant 

in the National Emission Standard for 

Hazardous Air Pollutants (NESHAP) 

Subpart QQQ, Primary Copper Smelting 

. . .’’ 128 For the primary off-gas stream, 

ASARCO explained that Subpart QQQ 

‘‘sets a limit of 6.2 milligrams per dry 


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129 Id. 

130 Id. 

131BART Guidelines section IV.D, 70 FR 39165. 

132 42 U.S.C. 7410(a)(2)(A). See also Montana 

Sulphur & Chemical Co. v. EPA, 666 F.3d 1174, 

1196 (9th Cir. 2012) (‘‘EPA correctly reads 42 U.S.C. 

[ ] 7410(a)(2) as requiring states to include 

enforceable emission limits and other control 

measures in the plan itself.’’). 

133CAA section 169A(b)(2), 42 U.S.C. 7491. 

134 40 CFR 51.308(e)(1)(iv), (v). 

135 § 51.308(d)(3)(v)(C) and (F). 

136 78 FR 46159. 

137 78 FR 46171. 

138See, e.g. 77 FR 57884 (explaining that BART 

emission limits must be established for all 

pollutants subject to review, even where no new 

controls are required); id. at 57916 (establishing an 

SO2 BART limit for Holcim Cement Plant based on 

no new controls). 

139 40 CFR 51.301. 

standard cubic meter (mg/dscm) nonsulfuric acid particulate matter’’ and 

that ‘‘[c]ompliance with this limit 

would be determined by annual testing 

in accordance with Section 63.1450(b) 

and continuous monitoring of scrubbing 

liquid flow rate over the final two 

towers in the acid plant established, 

reestablished and maintained in 

accordance with Section 63.1444(h).’’129

For the secondary off-gas stream, 

ASARCO explained that Subpart QQQ 

‘‘sets limit of 23 mg/dscm PM’’ with 

annual compliance testing in 

accordance with Section 63.1450(a).130

Given that ASARCO relied on the 

Subpart QQQ requirements as the basis 

for its own streamlined BART analysis 

for PM10, EPA considers it appropriate 

to include these requirements in the 

FIP. Incorporating these requirements 

into the FIP also fulfills the 

requirements of 40 CFR 51.308(e) for 

promulgation of BART emission 

limitations and is consistent with the 

BART Guidelines, which allow for 

streamlined BART analyses, such as the 

one EPA approved for PM10 at the 

Hayden Smelter, as long as the ‘‘most 

stringent controls available are made 

federally enforceable for the purpose of 

implementing BART.’’ 131 Therefore, we 

are finalizing the incorporation of the 

requirements of Subpart QQQ into the 

FIP. 

Comment: ASARCO stated that the 

CAA’s general SIP/FIP provisions do not 

support EPA’s argument that sources for 

which there are no additional control 

requirements must nonetheless have 

emission limits established. ASARCO 

also stated that EPA’s proposal is 

unacceptable because it suggests that 

where a state elects not to include a 

source in a SIP, it must include 

emission limits in the SIP that limit the 

non-included source’s emissions to its 

baseline, a requirement not found in the 

CAA and unworkable as a practical 

matter. 

Response: We do not agree with this 

comment. First, we note that the 

statutory and regulatory provisions cited 

in footnote 179 of our proposed rule 

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

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

not the only basis for including 

emission limitations and related 

compliance requirements for PM10 in 

the FIP. Several provisions of the CAA 

and EPA’s regulations require the 

promulgation of enforceable emission 

limitations in SIPs and FIPs generally, 

and in regional haze plans specifically. 

In particular, CAA section 110(a)(2)(A) 

requires SIPs to ‘‘include enforceable 

emission limitations and other control 

measures, means, or techniques . . . as 

may be necessary or appropriate to meet 

the applicable requirements of [the 

CAA].’’ 132 One of the ‘‘applicable 

requirements’’ of the CAA is that plans 

contain ‘‘such emission limits . . . as 

may be necessary to make reasonable 

progress’’ toward natural visibility 

conditions, including provisions for 

BART and a LTS.133 Under the RHR, 

plans must contain ‘‘emission 

limitations representing BART’’ for all 

subject-to-BART sources, as well as (1) 

a schedule for compliance with BART 

emission limitations for each source 

subject to BART; (2) a requirement for 

each BART source to maintain the 

relevant control equipment; and (3) 

procedures to ensure control equipment 

is properly operated and maintained.134

Furthermore, the LTS must include 

consideration of ‘‘emission limitations 

and schedules for compliance to achieve 

the reasonable progress goal’’ and the 

‘‘enforceability of emission limitations 

and control measures.’’ 135 Among the 

measures needed to ensure the 

enforceability of emission limits 

(including BART limits) are 

requirements for monitoring, 

recordkeeping, and reporting, as 

authorized by CAA section 110(a)(2)(F) 

and 40 CFR 51.212(c). 

Second, contrary to ASARCO’s 

suggestion, the Hayden Smelter is 

included in the Arizona RH SIP. In 

particular, while the State erroneously 

found that the Hayden Smelter was not 

‘‘subject-to-BART’’ for PM10, the SIP 

nonetheless included a BART 

determination for PM10 at the Hayden 

Smelter. EPA disapproved the State’s 

not-subject-to-BART finding, but 

approved its BART determination that 

existing controls constitute BART for 

PM10. Thus, a BART determination for 

PM10 for the Hayden Smelter is part of 

the approved Arizona RH SIP. However, 

the SIP did not include any enforceable 

emission limitations or related 

compliance requirements to implement 

this determination. Therefore, we found 

that the SIP did not meet the 

requirements of 40 CFR 51.212(c) and 

51.308(e)(1)(iv) and (v).136 We also 

disapproved the State’s RPGs and 

portions of its LTS because the SIP did 

not include enforceable emission limits 

to implement the State’s BART 

determinations.137 We are now required 

to promulgate a FIP to fill the gaps 

resulting from disapproved portions of 

the SIP. Thus, we are required to 

promulgate enforceable emission 

limitations to implement the State’s 

BART determination for PM10 at the 

Hayden Smelter. 

Finally, we do not agree that the 

promulgation of enforceable emission 

limits where no new controls are 

required is ‘‘novel.’’ As explained 

above, inclusion of such limits is a 

requirement of the RHR, and EPA has 

previously promulgated such limits, 

even where no additional controls were 

required for BART.138 Even where 

existing controls represent BART, there 

must be an emission limitation that 

reflects ‘‘the degree of reduction 

achievable’’ 139 by such controls. 

Comment: ASARCO stated that EPA 

has no legal basis for imposing 

additional limits on PM beyond the 

existing limits at the Hayden Smelter 

given that the PM emissions from the 

smelter contribute 0.04 dv or less to 

regional haze. Thus, further limits are 

not necessary to achieve the RPGs. 

ASARCO asserted that the LTS also 

does not require emission limits. 

Response: We do not agree with this 

comment. As explained above, the 

promulgation of PM10 limits for the 

BART-eligible units at ASARCO Hayden 

is required under 40 CFR 51.308(e). 

With regard to the requirements of the 

LTS, in addition to the requirement 

cited by the commenter, 40 CFR 

51.308(d)(3)(v)(F) requires consideration 

of the ‘‘enforceability of emission 

limitations and control measures’’ 

(including BART emission limitations) 

as part of the LTS. 

6. Other Comments 

Comment: ASARCO stated that a 

CEMS on the bypass stack, as EPA has 

proposed at CFR 51.145(l)(6)(i), is 

impractical and that the stack is actually 

a shutdown ventilation duct used to 

redirect in-transit SO2 and other gases 

out of the work environment in the 

event that the primary ventilation 

system becomes unavailable. ASARCO 

stated that events leading to the use of 

the shutdown ventilation duct are 

always associated with the cessation of 


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Federal Register / Vol. 79, No. 170 / Wednesday, September 3, 2014 / Rules and Regulations 52449 

140 78 FR 47190, 47193. 141Memorandum from Stephen Page to Regional 

Air Division Directors, Guidance for 1-Hour SO2

Nonattainment Area SIP Submissions (April 23, 

2014) at 10. 142 Id. 

143See Letters from Colleen McKaughan, EPA, to 

Jack Garrity, ASARCO, and Derek Cooke, FMMI 

(June 27, 2013); Letter from Jack Garrity, ASARCO, 

to Thomas Webb, EPA (July 11, 2013); letter from 

Derek Cooke, FMMI, to Thomas Webb, EPA (July 

12, 2013). 

144See comment letters from ASARCO and 

FMMI. 

145See Memo Regarding Communications with 

ASARCO on RH FIP; Memo Regarding Meeting with 

FMMI (April 28, 2014). 

smelting and converting and can be 

planned or unplanned. 

ASARCO explained that the estimated 

annual SO2 emissions resulting from 60 

events per year (based on average 

process parameters measured during 

GCT’s engineering study of the current 

system, assuming 30 unplanned events 

at full calculated mass SO2 and 30 

planned events at reduced SO2

accounting for the clearing of the gas 

before shutdown) are 2.81 tons for the 

BART-eligible units. ASARCO 

considered this amount, less than 0.09 

percent of the post-improvement SO2

emissions, to be de minimis. 

ASARCO stated that it also 

considered deployment of a SO2 CEMS 

to quantify emissions resulting from use 

of the shutdown ventilation duct to be 

impractical because it would require 

ranging of the concentration analyzer 

and flow measurement instrumentation 

to enable quantification of the emissions 

during the infrequent and very brief 

events, while recording zero/near zero 

levels the majority of the time. The 

relative accuracy test audit (commonly 

called ‘‘RATA’’) required could only be 

done by passing representative-strength 

SO2 gas past the analyzer for test 

periods totaling several hours, a 

situation that cannot occur (bypassing 

process gas while operating). 

Response: We agree with this 

comment. Because of the difficulties 

involved in operating a CEMS on a 

bypass stack, we have modified the 

BART determination to allow the 

Hayden Smelter to use test data to 

quantify emissions during normal 

startups and shutdowns, provided the 

facility is operated according to a 

startup and shutdown plan. 

Comment: AMA asserted that EPA 

should extend the compliance deadline 

in the rule, noting that if the rule 

continues as scheduled (promulgation 

by late June), the compliance date 

would be in June 2017. According to 

AMA, this is just months prior to the 

deadline of October 4, 2018, for Arizona 

to comply with the 1-hour SO2 NAAQS, 

meaning that the smelters would have to 

have completed their projects to reduce 

SO2 emissions to prevent causing or 

contributing to violations of the 

NAAQS. AMA noted that the two 

smelters, as indicated by their owners 

ASARCO and FMMI, are already 

planning to substantially modify their 

plants resulting in large SO2 reductions 

in order to prevent violations of the SO2

NAAQS, which will cost a significant 

amount of money, an amount higher 

than what EPA would consider 

reasonable under BART. AMA asked 

that EPA consider this significant 

undertaking by the two smelters and 

align the BART compliance deadline 

with the SO2 attainment deadline. 

AMA added that if nothing else, 

considering the projects the two 

smelters are undertaking, the EPA 

should consult with ASARCO and 

FMMI to ensure that the final rule does 

not interfere with plans the smelters 

have to reduce SO2 emissions in order 

meet the 1-hour SO2 NAAQS. AMA 

stated that coordination of the BART 

requirements with the facilities’ effort to 

comply with the new SO2 NAAQS is 

necessary to maintain the viability of 

these smelters, thereby preserving highpaying jobs and adding new jobs as the 

smelters install additional controls to 

comply with the CAA’s visibility 

requirements and other programs. 

Response: We partially agree with this 

comment. The BART level of control in 

the FIP is a performance standard. We 

do not prescribe any particular method 

of control. As a result, we do not 

anticipate any incompatibility with any 

changes that may be needed to comply 

with any attainment plan required by 

the 1-hour SO2 NAAQS. With regard to 

the compliance deadline, we note that 

Arizona is required to develop a SIP that 

provides for attainment of the 1-hour 

SO2 NAAQS as expeditiously as 

practicable, but no later than October 4, 

2018.140 Furthermore, as explained in 

EPA’s Guidance for 1-hour SO2

Nonattainment Area SIP Submissions 

‘‘. . . EPA expects attainment plans to 

require sources to comply with the 

requirements of the attainment strategy 

at least 1 calendar year before the 

attainment date.’’ 141 Therefore, the 

Hayden and Miami Smelters would be 

required to comply with the attainment 

strategy by January 1, 2017.142

Accordingly, the expected source 

compliance date under the 1-hour SO2

NAAQS actually precedes the proposed 

compliance date in the RH FIP of three 

years from promulgation of the final 

rule (i.e., about July 2017). 

Furthermore, based on additional 

information received during the 

comment period, we have decided to 

extend the compliance deadline for the 

secondary control system at the Hayden 

Smelter by an additional year (i.e., to 

about July 2018). As explained 

elsewhere in response to comments and 

in our revised BART analysis for the 

Hayden Smelter, our BART 

determination for the secondary stream 

now reflects the use of an amine 

scrubber rather than acid plant. We are 

not aware of any instances of an amine 

scrubber being used at any similar 

facility in the United States. Therefore, 

we no longer consider three years to be 

sufficient time for design, construction, 

and a shakedown period. Accordingly, 

we are finalizing a compliance deadline 

of four years from publication of the 

final rule for the requirements 

applicable to the secondary stream. We 

are retaining the proposed compliance 

deadline of three years from publication 

of the final rule for the requirements 

applicable to the primary stream. 

Finally, we also note that, during the 

development of our proposed FIP, we 

requested and received information 

from ASARCO and FMMI regarding 

control upgrades planned for purposes 

of attaining the 1-hour SO2 NAAQS.143

During the comment period on the 

proposed FIP, we received more 

detailed additional information from 

both companies.144 We have also met 

with representatives from both 

companies.145 As described elsewhere 

in this document, we have made certain 

revisions to the regulatory text 

applicable to the smelters to ensure that 

there is no incompatibility between the 

requirements of the RH FIP and the 

smelters’ plans to ensure attainment of 

the 1-hour SO2 NAAQS. 

D. Comments on the Miami Smelter 

1. General Comments 

Comment: ADEQ stated that EPA’s 

disapproval of ADEQ’s SO2 BART 

determinations for the Miami and 

Hayden Smelters is unsupported. 

Similarly, AMA, NMA and FMMI 

requested that EPA reconsider its 

decision to disapprove these BART 

determinations. In particular, FMMI 

asserted that once EPA accounts for the 

technical deficiencies in its own BART 

analysis, the Agency will conclude that 

additional controls at the Miami Smelter 

are not justified as BART. 

Response: We do not agree with these 

comments. Our action on the Arizona 

RH SIP is now final, and the 

commenters have cited no legal basis for 

EPA to reconsider that action. Moreover, 

the commenters have mischaracterized 

EPA’s disapproval of Arizona’s SO2

BART determinations for the copper 

smelters, which was based on multiple 


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52450 Federal Register / Vol. 79, No. 170 / Wednesday, September 3, 2014 / Rules and Regulations 

146FMMI previously estimated a capture 

efficiency of up to 98 percent for the primary 

capture system. Letter from Derek Cooke, FMMI to 

Tom Webb, EPA (January 25, 2013) at 5. More 

recently, FMMI has indicated that this capture 

efficiency will be improved by installation of 

actuated mouth covers, Freeport-McMoRan Miami 

Inc. BART Analysis (March 2014) (FMMI BART 

Report), at 2–4, and could be as high as 99.57 

percent. See Memorandum from J. Nikkari, Hatch 

to C. West, FMMI (November 14, 2013) (Hatch 

Memo), section 3.1.2. 

147Present emissions from the converter aisle are 

estimated to be 161,564. Id. 

148The estimated control efficiency of the acid 

plant and tailstack scrubber system is currently 

99.69 percent. Id. section 3.4. This control 

efficiency could be increased through increased use 

of the tailstack scrubber, as described further below, 

and conversion of tail gas scrubber to utilize caustic 

(NaOH), to enhance the SO2 control efficiency, 

which FMMI intends to do. See ADEQ Significant 

Permit Revision Application, ADEQ Class I Permit 

Number 53592, Smelter Expansion & Enhanced 

Controls; (July 2013) (FMMI Permit Application), 

section 4.1.1. 

149 Id. section 4.1.4 (‘‘Captured SO2 emissions 

were assumed to be controlled by the scrubber with 

an average efficiency of roughly 90 [percent].’’ 

deficiencies including the lack of any 

five-factor analysis and any enforceable 

emission limits. The commenters’ 

assertions regarding purported 

deficiencies in EPA’s own BART 

analysis are addressed in other 

responses. 

Comment: ADEQ asserted that EPA’s 

disapproval of ADEQ’s determination 

that the Miami Smelter is not subject to 

BART for NOX has no statutory basis, 

and that EPA’s imposition of BART for 

NOX emissions is arbitrary and 

capricious. 

Response: To the extent this comment 

concerns our action on the Arizona RH 

SIP, it is untimely, as that action is now 

final. To the extent it concerns our 

proposed FIP, we do not agree with its 

substance for the reasons set forth in 

response to similar comments on the 

Hayden Smelter above. 

2. BART Analysis and Determination for 

SO2 From the Converters 

Comment: FMMI noted that Converter 

1 has been out of service since the mid1980s, and the company has no plans to 

reactivate it. Therefore, all of the SO2

emissions from the converter aisle 

should be attributed to Converters 2–5, 

which are the BART-eligible units. 

Response: We appreciate the 

clarification regarding Converter 1. 

Because emissions from the different 

converters cannot be separated for 

technical reasons, we treated all 

converter emissions as BART-eligible. 

Thus, the fact that Converter 1, which 

is not a BART-eligible unit, is 

inoperable, does not affect our BART 

analysis. We have revised the regulatory 

text to clarify that the requirements of 

the FIP do not apply to Converter 1. 

Comment: FMMI asserted that the 

‘‘secondary hood’’ required by 40 CFR 

63.1444(d)(2) does not apply to Miami 

Smelter’s Hoboken converters because 

the Miami Smelter does not use PeirceSmith converters. FMMI also requested 

that EPA structure the FIP in a way that 

will ensure consistency between any 

new BART requirements and the 

controls that FMMI intends to install to 

ensure that the emissions from the 

Miami Smelter do not interfere with 

attainment of the 1-hour SO2 NAAQS. 

ADEQ, AMA and NMA echoed these 

comments. 

Response: We agree that 40 CFR 

63.1444(d)(2) does not apply to the 

Miami Smelter converters. Our 

reference to that provision of the 

NESHAP in the proposed FIP was not 

intended to suggest otherwise. Rather, it 

was intended to ensure that FMMI 

install a secondary capture system to 

collect emissions that currently escape 

the existing primary capture system at 

the Miami Smelter’s converters. This 

secondary system for the Hoboken need 

not be identical to the secondary 

capture system used for the PeirceSmith converters. Rather the FIP 

provides FMMI with substantial 

flexibility to design a capture system 

appropriate for the unique configuration 

of its converters, provided that FMMI 

demonstrates that this system is 

designed and operated to maximize 

collection of process off-gases vented 

from the converters. In fact, the aisle 

capture system that FMMI plans to 

install is itself a type of secondary 

capture system that could meet the 

requirements of the FIP, provided that it 

is optimized to capture the maximum 

amount of process off-gases vented from 

the converters. We have revised the 

regulatory language to clarify this 

requirement by removing the reference 

to 40 CFR 63.1444(d)(2) and defining 

‘‘capture system’’ to reflect the broad 

range of components that could be 

included in the system. 

Comment: FMMI stated that it is not 

technically feasible to route additional 

captured SO2 from the converters to the 

acid plant. FMMI explained that while, 

in an earlier letter, it had stated that SO2

emissions collected by the roofline 

capture system would be routed to the 

acid plant, this was an error since the 

routing is not technically feasible. 

Specifically, FMMI asserted that ‘‘the 

SO2 concentrations in this gas stream 

are much too low and the flow volume 

too high to allow the existing acid plant 

to handle this stream’’ and that ‘‘gases 

from the aisle capture system would 

also have significant heating 

requirements, and associated air 

emissions, if they were to be routed to 

the existing acid plant.’’ ADEQ, AMA, 

and NMA echoed FMMI’s concerns 

regarding the technical feasibility of the 

proposed requirements for SO2.

Response: We do not agree that the 

FIP requirements for the Miami Smelter 

are technically infeasible. In particular, 

as explained in response to comments 

from ASARCO above, while higher flow 

volumes and lower SO2 concentrations 

may reduce the control efficiency and 

cost-effectiveness of a double contact 

acid plant, they do not render use of 

such an acid plant infeasible. 

Nonetheless, if FMMI determines that 

the existing double contact acid plant is 

not adequate to treat emissions captured 

by the secondary capture system, it may 

use an alternative approach to comply 

with the requirements of the FIP. In 

particular, because the FIP does not 

prescribe any particular method of 

control, any combination of control 

devices may be employed to meet the 

99.7 percent control requirement. For 

example, FMMI may continue to use the 

existing double contact acid plant and 

tailstack scrubber on the primary stream 

and construct a new scrubber to treat 

the secondary stream, as it currently 

plans to do. Because the control 

efficiency is calculated on a cumulative 

mass basis, it will be determined largely 

by the degree of control achieved by the 

existing double contact acid plant and 

tailstack scrubber, which treat the vast 

majority of emissions from the converter 

aisle.146

For example, consider a situation 

where 100,000 pounds of SO2 is emitted 

by the converters.147 Of this 100,000 

pounds, 99 percent is captured by the 

primary capture system and ducted to 

the acid plant system, which has a 

control efficiency of 99.8 percent.148

The remaining 1 percent is captured by 

the secondary capture system and 

ducted to a caustic scrubber with a 

control efficiency of 90 percent.149

Ducted to acid plant: 99 percent of 100,000 

lbs = 99,000 lbs 

Controlled by acid plant: 99.8 percent of 

99,000 lbs = 98,802 lbs 

Ducted to scrubber: 1 percent of 100,000 lbs 

= 1,000 lbs 

Controlled by scrubber: 90 percent of 1,000 

lbs = 900 lbs 

Overall control efficiency: (98,802 + 900)/

100,000 = 0.997 = 99.7 percent 

Thus, FMMI can meet this overall 

control efficiency by improving the 

efficiency of the primary capture 

system, improving the efficiency of the 

primary control system (e.g., increasing 

the use of cesium promoted catalyst, 

increasing operation of the tailstack 

scrubber, or converting the tailstack 

scrubber from a magnesium oxide 

scrubber to a caustic or amine scrubber), 


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Federal Register / Vol. 79, No. 170 / Wednesday, September 3, 2014 / Rules and Regulations 52451 

150FMMI describes uncaptured emissions from 

the converters as ‘‘fugitive emissions.’’ However, 

under the RHR, ‘‘fugitive emissions’’ are defined as 

‘‘those emissions which could not reasonably pass 

through a stack, chimney, vent, or other 

functionally equivalent opening.’’ 40 CFR 51.301.

Because FMMI is planning to capture a significant 

portion of these emissions and route them to a 

scrubber, they are, by definition, not fugitive. 

151Letter from Derek Cooke, FMMI to Thomas 

Webb, EPA (July 12, 2013). 

152See Letter from Derek Cooke, FMMI to Tom 

Webb, EPA (January 25, 2013) at 5 (reporting a 

range of values of 87 percent to 98 percent). We 

used the high end of this range to ensure that our 

cost per ton estimates were conservative. That is, 

we assumed the baseline level of uncaptured 

emissions was lower and that there were therefore 

fewer emission reductions available, resulting in 

higher cost per ton values. 

153Roofline Study, prepared by Trinity 

Consultants for Freeport McMoRan, Inc. (November 

2013). 

154We note that the FMMI Permit Application 

indicates that the roofline capture system will 

collect 84 percent of ‘‘process fugitives’’ (i.e. 

currently uncaptured emissions) from the 

converters, meaning that the remaining 16 percent 

will escape elsewhere. Given that FMMI is not even 

attempting to capture any emissions at the roofline 

now, we expect that more than 16 percent of 

presently uncaptured emissions are bypassing the 

roofline monitors and are therefore not reflected in 

the results of the roofline study. 

155 Id. Section 5.1. 

156Report: Extended Roofline SO2 Emissions 

Summary (March 2014). 

157 Id. section 1, page 2. 

158 Id. section 3.1, page 2. 

159FMMI BART Report, Appendix A (BARTEligible Baseline Emissions Calculations), Table A– 

1 (BART Baseline Emissions). 

160 Id. note 4. 

161 40 CFR part 51, appendix Y, section 

IV.D.4.d.2. 

maximizing the efficiency of any new 

equipment installed to control 

emissions from the secondary capture 

system, or any combination of these 

options. 

Comment: FMMI asserted that by 

using a mass-balance approach to 

estimate SO2 emissions from the 

converter aisle, EPA had overestimated 

emissions and thereby overestimated 

the visibility improvement and 

underestimated the cost per ton of 

additional SO2 controls. FMMI 

described ‘‘its own attempts to measure 

fugitive SO2 emissions’’ (i.e., the 

Roofline Study) and asserted that EPA 

should have used emission estimates 

based on the Roofline Study, instead of 

emission estimates based on a massbalance method, which FMMI 

characterized as ‘‘highly imprecise’’ and 

‘‘unclear.’’ FMMI further noted that 

‘‘EPA’s calculation does not incorporate 

the effect of the new converter mouth 

covers, which reduce process fugitive 

emissions from the converters.’’ Finally, 

FMMI concluded that EPA’s use of a 

mass-balance approach is contrary to 

the BART Guidelines, which state that 

the baseline emission rate ‘‘should 

represent a realistic depiction of 

anticipated annual emissions from the 

source.’’ Similarly, Earthjustice and 

NMA both questioned EPA’s estimate of 

uncollected SO2 emissions. 

Response: We disagree that we 

overestimated uncaptured baseline SO2

emissions.150 We estimated uncaptured 

baseline SO2 emissions from the 

converters using the following massbalance approach: (1) We calculated the 

amount of sulfur in the concentrate 

processed by the smelter using 

throughput and composition data 

provided by FMMI for the maximum 

production day and a baseline year 

(2010); (2) we assumed full conversion 

of sulfur to SO2; (3) we apportioned 65 

percent of the SO2 to the smelter aisle 

and 35 percent to the converter aisle 

based on information provided by 

FMMI; 151 and (4) We assumed 95 to 98 

percent capture of emissions by the 

Hoboken converters’ side flues.152 We 

consider this modified mass-balance 

approach to provide a more accurate 

depiction of emissions than the massbalance approach in the Arizona RH 

SIP, which FMMI notes ‘‘has proven to 

be unreliable.’’ 

With regard to the Roofline Study, 

while we encourage ongoing efforts by 

FMMI to increase understanding of 

emissions that bypass the existing 

capture systems, we do not agree that 

the results of the Roofline Study are 

more accurate than the values that we 

used in our emission calculations. The 

Roofline Study measured emissions at 

four points along the open roof.153

Given that the roof and sides of the 

building are not fully enclosed, it is very 

unlikely that these four points 

accurately reflect all of the emissions 

currently escaping from the converter 

aisle.154 Indeed, the authors of the 

Roofline Study acknowledge that the 

emission rates presented ‘‘may not 

adequately measure the true value of the 

parameter’’ and are presented for 

‘‘illustration purposes.’’ 155 We also note 

that, following the close of the comment 

period, we received from FMMI a report 

summarizing the results of an ‘‘extended 

roofline sampling campaign’’ from 

approximately March 2013 through 

December 2013.156 While this extended 

sampling effort is intended to provide 

‘‘more representative, long-term roofline 

SO2 emission estimates for current 

operation,’’ 157 it still does not account 

for ‘‘unmeasured fugitive emissions.’’ 158

Therefore, we do not agree that this the 

Roofline Study necessarily provides a 

more accurate estimate of SO2 emissions 

than the mass-balance method we used. 

Furthermore, even assuming for the 

sake of argument that FMMI’s revised 

emission estimates based on the 

Roofline Study are correct, uncaptured 

baseline emissions from the converters 

would be 547 tpy.159 In order to reach 

the 109 tpy estimate of uncaptured SO2

emissions from the converters employed 

in its BART analysis, FMMI relies on an 

unverified and unenforceable 80 percent 

capture efficiency from improvements 

to the converter mouth covers.160

However, use of this ‘‘expected’’ capture 

efficiency does not provide an adequate 

basis for reducing baseline uncaptured 

emissions from the converters from the 

current emissions level, as measured 

estimated by the Roofline Study. As 

explained in the BART Guidelines, in 

the absence of enforceable limitations, 

you calculate baseline emissions based 

upon continuation of past practice.161

Although we support measures to 

increase the amount of emissions 

captured by the side flue and ducted to 

the acid plant, at present, there is no 

enforceable emission limitation that 

ensures that the mouth covers will 

achieve 80 percent capture of the 

existing uncaptured converter 

emissions. Therefore, even if the 

extended roofline study did provide an 

accurate estimate of uncaptured 

emissions and FMMI’s allocation of 

those emissions among various emission 

units was correct, baseline uncaptured 

emissions from the converters would be 

at least 547 tpy, not 109 tpy, as 

indicated by FMMI. 

Comment: FMMI stated that EPA’s 

reliance on cost data from the Hayden 

Smelter underestimates the costs of 

additional controls because the PeirceSmith Converters used at the Hayden 

Smelter are fundamentally different 

from the Hoboken Converters used by 

FMMI. FMMI asserted that this and 

other differences in the operational 

configuration of the two facilities means 

that the types of controls available and 

their respective costs are not 

transferrable between facilities. FMMI 

noted that it had prepared its own fivefactor analysis, which FMMI stated 

relies upon the most up-to-date cost 

estimates that FMMI has received from 

Hatch Engineering, which designed the 

smelter project including the upgraded 

roofline capture system and the new 

aisle scrubber. FMMI asserted that this 

cost data presented in the FMMI BART 

Report is the best and most accurate cost 

information that is available to FMMI 

and EPA at this time and that EPA 

should rely upon this cost data in any 

BART analyses it conducts for the 

Miami Smelter. 


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52452 Federal Register / Vol. 79, No. 170 / Wednesday, September 3, 2014 / Rules and Regulations 

162Letter from Jay Spehar, FMMI, to Geoffrey 

Glass, EPA (May 7, 2014). 163See, e.g., BART Report page 3–15 (‘‘Annual 

scrubbing reagent costs were calculated from total 

estimated SO2 design reductions (i.e., inclusive of 

emission units that are not BART-eligible).’’ 164See 70 FR 39166 ‘‘The basis for equipment 

cost estimates also should be documented, either 

with data supplied by an equipment vendor (i.e., 

budget estimates or bids) or by a referenced 

source.’’ 165BART Report page 3–15 (‘‘Owner’s costs were 

likewise factored as a percentage of the total direct 

plus indirect cost. A value of 6.7 percent was 

applied for this analysis.’’) 166Memo regarding BART Cost Using FMMI Data, 

June 11, 2014. 

167Phone call between FMMI and EPA, May 21, 

2014. 

168See appendices C and J to FMMI’s Jan. 2013 

letter. See also, Memorandum from J. Nikkari, 

Hatch to C. West, FMMI (November 14, 2013) 

(Hatch Memo), section 3.4 (calculating 99.69 

percent control efficiency for existing acid plant 

and tail stack scrubber system). 

169Letter from Derek Cooke, FMMI, to Thomas 

Webb, EPA (January 25, 2013) at 7. 

170ADEQ Significant Permit Revision 

Application, ADEQ Class I Permit Number 53592, 

Smelter Expansion & Enhanced Controls; (July 

2013) (FMMI Permit Application), Tables A–2 and 

A–b. 

Response: In order to avoid potential 

disclosure of cost data for the Miami 

Smelter claimed as CBI by FMMI, we 

based our cost analysis for the 

construction of secondary hooding, wet 

scrubbers and similar, though not 

identical, equipment on nonconfidential data provided by ASARCO 

for the Hayden Smelter. FMMI included 

additional non-confidential cost 

information in the BART Report it 

submitted with its comments. In 

addition, following the close of the 

comment period, FMMI withdrew its 

CBI claim from its prior submittals, 

including Appendix B to the BART 

Report.162 We have reviewed the BART 

Report and found that it contains a 

number of incorrect or unsupported 

assumptions that improperly inflate the 

$/ton estimates for the various control 

options presented. First, it assumes 

capture of emissions at the roofline 

rather than in the converter aisle itself. 

This design does not attempt to capture 

or control emissions until after mixing 

with ambient air inside the building, 

resulting in very high volumes of very 

low-concentration gases that are more 

costly to control. Second, the cost 

estimates include costs of control for 

non-BART units.163 Third, the cost 

estimates are not supported by sufficient 

documentation, such as vendor 

quotes.164 Finally, the cost estimates 

include costs not permitted by the CCM 

(e.g. owner’s costs).165 Therefore, we do 

not consider the cost estimates provided 

in FMMI’s BART Report to accurately 

reflect the cost of potential BART 

controls. 

Nonetheless, in order to further 

evaluate the cost-effectiveness of SO2

controls for the converters, we have 

conducted a supplemental cost analysis 

based on the cost information provided 

by FMMI. In this analysis, we have 

employed the cost estimates provided 

by FMMI, but revised the calculations to 

reflect the present level of uncaptured 

emissions from the converter aisle based 

on the mass-balance approach described 

above.166 According to the 

supplemental analysis, the costeffectiveness of the control options 

evaluated by FMMI falls in the range of 

$2,386 to $5,478 per ton of SO2. The 

upper end of this range is higher than 

we have previously found reasonable for 

purposes of BART. However, for the 

reasons described in the preceding 

paragraph, this estimate significantly 

overstates the costs of controlling the 

BART-eligible emissions. Accordingly, 

we do not agree that we should employ 

these costs in our BART analysis. 

Comment: FMMI asserted that neither 

the 99.7 percent control efficiency nor 

the 99.8 percent alternative control 

efficiency proposed by EPA could be 

feasibly measured at FMMI for three 

reasons. First, differences in precision 

between the acid plant inlet (percent) 

and tailstack (ppm) CEMS ‘‘mean that 

the two CEMS cannot be compared with 

an acceptable degree of accuracy . . .’’ 

Second, ‘‘the measurement of acid plant 

inlet and tail stack gas concentrations to 

determine control efficiencies contains 

an underlying assumption that there is 

a constant amount of time that it takes 

gases to pass through the acid plant.’’ 

Third, an expected 2 percent 

measurement drift in the acid plant inlet 

CEMS exceeds the measured 

concentration of the tailstack CEMS 

measurement span. 

Response: We disagree that it is 

technically infeasible to measure the 

required 99.7 percent control efficiency. 

We recognize that the acid plant inlet 

CEMS will have a much greater span 

than the tailstack CEMS. However, as 

explained in response to similar 

comments on the Hayden Smelter, 

because the emission limit is a percent 

control on a cumulative mass basis, the 

measurement of the inlet CEMS can 

vary appreciably without affecting 

compliance status. 

In addition, the compliance method 

in the proposed regulatory text makes 

no assumptions about residence time in 

any control device because it does not 

rely on instantaneous control 

efficiencies. Instead, it compares 

uncontrolled and controlled total 

masses over a 30-day period. Since the 

control efficiency data provided by 

FMMI were based on annual data, 

however, we have modified the final 

determination to be a rolling 365-day 

average rather than a rolling 30-day 

average. 

Finally, in response to a request from 

FMMI,167 we have added an additional 

option for measuring SO2 levels in the 

secondary stream. In particular, if FMMI 

chooses to control the secondary stream 

using an alkali scrubber, then it may 

calculate the pounds of SO2 entering the 

scrubber based on the amount of alkali 

added to the scrubber liquor, rather than 

installing an inlet CEMS. 

Comment: FMMI requested 

clarification concerning EPA’s proposal 

to calculate control for a combination of 

controlled and uncontrolled emissions. 

FMMI noted that EPA’s calculated 

control efficiency of 99.69 percent 

excluded the bypass stack. 

Response: We calculated the acid 

plant’s control efficiency based on 

annual SO2 emissions from the acid 

plant tailstack and annual production of 

sulfuric acid.168 This is a level of 

control that FMMI has demonstrated 

achieving in practice when emissions 

are ducted to the acid plant. Emissions 

from the bypass stack consist of 

uncontrolled emissions released during 

startup, shutdown, and malfunction 

events.169 Because BART emission 

limits apply at all times, including 

periods of startup, shutdown, and 

malfunction, the control efficiency 

requirement in the FIP includes 

uncontrolled emissions from the bypass 

stack. FMMI reported annual average 

SO2 emissions from the bypass stack of 

only 65 tpy in 2011 to 2012, and 

projected zero SO2 emissions from the 

bypass stack following its planned 

control upgrades.170 Therefore, any 

emissions from the bypass stack will be 

de minimis and will not impair FMMI’s 

ability to meet the 99.7 percent control 

efficiency requirement on a rolling 365- 

day basis. 

Comment: FMMI stated that its own 

five-factor analysis demonstrates that 

existing controls meet BART, additional 

controls are not justified, and EPA’s 

contrary finding is based on a 

technically flawed BART analysis. 

Response: We do not agree with this 

comment. As described above, FMMI’s 

five-factor analysis relies on 

unrealistically low estimates of 

uncontrolled emissions and 

unrealistically high estimates of control 

costs, resulting in improperly inflated $/ 

ton estimates. Based on these 

unrealistically high $/ton values, the 

FMMI BART Report improperly 

concludes that no additional controls 

are cost-effective. Because of the flaws 


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171See 40 CFR 51.308(e)(2)(i)(E) and (3). 

172ADEQ Significant Permit Revision 

Application, ADEQ Class I Permit Number 53592, 

Smelter Expansion & Enhanced Controls; (July 

2013) (FMMI Permit Application), Table A–4. 

173FMMI BART Analysis Table A–1. 

174See 40 CFR 51.308(e)(2)(iii). 

175ADEQ Air Quality Class I Permit # 53592 (As 

Amended by Significant Revision No. 58409) 

Freeport McMoRan Inc. Miami Smelter (Draft, April 

22, 2014). 

176Regional Haze Regulations and Guidelines for 

Best Available Retrofit Technology (BART) 

Determinations, 70 Fed. Reg. 39,104, 39,116 (July 6, 

2005) (emphasis added). 

177See 79 FR 9347 (referring to disapproval of 

not-subject-to-BART finding in the Arizona RH 

SIP); 77 FR 75721 (proposed disapproval of notsubject-to-BART finding in the 2011 RH SIP); 78 FR 

29301 (proposed disapproval of not-subject-toBART finding in the RH SIP Supplement). 

178See 78 FR 46156 (responses to FMMI 

comments regarding proposal on 2011 RH SIP) and 

46170–71 (responses to FMMI comments regarding 

proposal on RH SIP Supplement). 

underlying these cost analyses, we do 

not agree with this conclusion. 

Comment: FMMI stated that EPA 

should consider FMMI’s planned 

pollution controls as a better-than-BART 

alternative. FMMI asserted that EPA is 

aware that FMMI is in the process of 

obtaining a permit revision to install 

significant new controls to ensure the 

smelter does not cause or contribute to 

a violation of the 1-hour SO2 NAAQS. 

ADEQ also noted that FMMI is currently 

working with ADEQ to revise its permit 

to accommodate a facility expansion, 

and is evaluating controls necessary to 

comply with the 1-hour SO2 NAAQS. 

Response: EPA is willing to consider 

FMMI’s planned pollution controls for 

1-hour SO2 NAAQS compliance as a 

potential ‘‘better-than-BART’’ 

alternative under 40 CFR 51.308(e)(2). 

However, FMMI’s current proposal does 

not meet the requirements for a betterthan-BART alternative. First, in order to 

qualify as a better-than-BART 

alternative, FMMI’s proposed 

alternative would have to achieve more 

emissions reductions than BART.171

FMMI estimates that its proposed 

control upgrades will result in an 

emission reduction of 6,054 tpy of SO2

(future PTE minus past two-year 

actual).172 The bulk of this reduction 

would come from smelter ‘‘fugitives’’ 

that FMMI estimates would be reduced 

from 4,836 tpy of SO2 (actual from 

2011–2012) to 288 tpy (potential). 

However, this is inconsistent with 

FMMI’s BART analysis, which 

estimated actual baseline SO2 emission 

from 2011 to 2012 as 1,033 tpy.173 In 

order to make a better-than-BART 

demonstration, FMMI should use a 

consistent estimate of baseline 

emissions, rather than using different 

estimates of baseline emissions for its 

BART and better-than-BART analyses. 

Second, FMMI’s proposal would have 

to include a schedule for 

implementation, enforceable emission 

limitations, and monitoring, 

recordkeeping and reporting 

requirements.174 FMMI’s proposal, as 

set forth in its permit application and 

the draft permit developed by ADEQ,175

does not include all of these elements. 

Therefore, it does not meet the 

requirements for a better-than-BART 

alternative. If ADEQ wishes to submit a 

better-than-BART alternative as a SIP 

revision, we will work with FMMI and 

ADEQ to develop such a revision. 

Comment: NPS supports EPA’s 

proposed requirements to control SO2

emissions from the Miami Smelter. 

Response: We acknowledge NPS’s 

support. 

Comment: In response to EPA’s 

request for comment on whether a 

control efficiency more stringent than 

99.7 percent is warranted, Earthjustice 

asserted that a better control efficiency 

is achievable, and as a result 

Earthjustice does not support EPA’s 

proposed control efficiency 

requirement. Earthjustice indicated that 

the proposed control efficiency 

requirement appears to be the stated 

(and unverified) level of control 

currently achieved at the Miami 

Smelter. However, the BART Guidelines 

require EPA to base its analysis on the 

most stringent control efficiency 

achievable. Noting that the proposed 

level is lower than that proposed for the 

Hayden Smelter, Earthjustice stated that 

the control efficiency of the Miami 

Smelter’s acid plant should be 99.93 

percent or greater for the same reasons 

that Earthjustice put forward for the 

Hayden Smelter. 

Response: We disagree with this 

comment for the reasons described in 

response to a similar comment regarding 

the Hayden Smelter. In particular, the 

examples of higher control efficiencies 

cited by the commenter are not directly 

comparable to the Miami Smelter 

because they are different types of 

operation. 

3. BART Analysis and Determination for 

NOX

Comment: AMA, FMMI, and NMA 

said that the proposed NOX limits for 

the Miami Smelter exceed EPA’s 

authority. The commenters asserted that 

because NOX emissions from the BARTeligible sources at FMMI are below the 

exception threshold, the RHR provides 

that they may be excluded from BART 

analysis. The commenters indicated that 

they disagree with EPA’s position that 

‘‘all visibility impairing pollutants will 

be subject-to-BART once a source is 

subject-to-BART for any pollutant 

unless the pollutant in question is 

emitted at a level below the exception 

threshold.’’ NMA asserted that this was 

inconsistent with EPA’s prior 

acknowledgment that ‘‘it is reasonable 

to read [42 U.S.C 7491(b)(2)(a)] as 

requiring a BART determination only for 

those emissions from a source which are 

first determined to contribute to 

visibility impairment in a Class I 

area.’’ 176 FMMI added that nothing in 

the CAA grants EPA authority to 

establish emissions caps to ensure that 

facilities remain at or below the 

exception threshold. Even if EPA’s 

position were justified, baseline NOX

emissions from the smelter, which 

FMMI has submitted to EPA, indicate 

that the BART-eligible equipment only 

emits 21.7 tpy, which the commenters 

indicated is far below the BART 

exception threshold of 40 tpy. For these 

reasons, the commenters opposed EPA’s 

proposal for NOX at the Miami Smelter. 

FMMI and NMA also stated that 

EPA’s partial disapproval of the Arizona 

RH SIP does not affirmatively 

demonstrate that the smelter is subjectto-BART for NOX, and EPA’s proposal to 

subject FMMI to a BART analysis for 

NOX is legally deficient. According to 

AMA, if the source has been determined 

to be subject to BART for a particular 

pollutant, EPA has the following two 

options: (1) Impose BART controls 

based on the outcome of the five-factor 

analysis or (2) determine that a source 

is de minimis and exempt it from a 

BART analysis. AMA said that the NOX

emissions cap is arbitrary and 

capricious and should not be included 

in the final rule. 

Response: We acknowledge that we 

inadvertently omitted from our proposal 

a complete explanation of the basis for 

our proposed determination that the 

Miami Smelter is subject to BART for 

NOX. However, we do not consider this 

omission prejudicial because, as noted 

by FMMI, the rationale for this proposed 

determination is the same as the 

rationale for our disapproval of ADEQ’s 

determination that the Miami Smelter 

was not subject to BART for NOX.177

FMMI commented extensively on this 

element of the SIP action and included 

these comments as an attachment to its 

FIP comments. EPA responded to these 

comments in the context of our SIP 

action.178 As explained in our final 

action on the 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 PTE for that pollutant is below a 

specified de minimis level. Although a small 


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52454 Federal Register / Vol. 79, No. 170 / Wednesday, September 3, 2014 / Rules and Regulations 

179 78 FR 46156 (citing 40 CFR 51.308(e)(1)(ii)(C)). 

180 70 FR 39115–16. 

181 40 CFR 51.308(e)(ii) (emphasis added). 

182 40 CFR 51.308(e)(1)(ii)(C). 183 40 CFR 51.301. 184 Id. 185Summary of WRAP RMC BART Modeling for 

Arizona, Draft#5, May 25, 2007. 

186FMMI Comment Letter at 13, n.1. 

187BART Guidelines, 40 CFR part 51, appendix 

Y, section IV.D.4.d.1. 

188 40 CFR 51.308(e). 

189BART Guidelines, section V. 

190See 40 CFR 51.308(f) (requiring subsequent 

regional haze plans to ‘‘evaluate and reassess all of 

the elements required in paragraph (d)’’, i.e., RP and 

LTS requirements, but not BART). 

191See 70 FR 46159. 

pollutant-specific baseline visibility impact 

may be informative in determining what 

control option may be BART, a BART 

analysis is still required for any pollutant 

with a PTE that exceeds the de minimis 

threshold at an otherwise subject-to-BART 

source.179

The preamble to the 2005 revisions to 

the RHR and BART Guidelines cited by 

FMMI does not conflict with this 

interpretation. When EPA revised the 

RHR, we proposed to interpret CAA 

section 169A(b)(2)(A) to require a BART 

analysis for all visibility-impairing 

pollutants emitted by a source, 

regardless of amount. However, in the 

final rule, we explained that there were 

two reasonable interpretations of the 

statutory text: 

Section 169A(b)(2)(A) of the Act can be 

read to require the States to make a 

determination as to the appropriate level of 

BART controls, if any, for emissions of any 

visibility impairing pollutant from a source. 

Given the overall context of this provision, 

however, and that the purpose of the BART 

provision is to eliminate or reduce visibility 

impairment, it is reasonable to read the 

statute as requiring a BART determination 

only for those emissions from a source which 

are first determined to contribute to visibility 

impairment in a Class I area.180

FMMI cites the emphasized language, 

but omits the surrounding discussion, 

which explains that section 

169A(b)(2)(A) could reasonably be read 

either to require a BART analysis for 

emissions of any visibility impairing 

pollutant from a source or to require an 

analysis only for emissions first 

determined to contribute to visibility 

impairment. The preamble does not 

state which of these two interpretations 

EPA was adopting. However, in the 

RHR, EPA retained the requirement that 

States make a BART determination for 

each ‘‘BART-eligible source in the State 

that emits any air pollutant’’ which may 

cause or contribute to any impairment 

of visibility in any Class I area.181 The 

only revision made to allow for 

exemption of specific pollutants from a 

BART analysis was the addition of the 

de minimis exemption in 40 CFR 

51.308(e)(ii)(C). EPA’s decision to 

include this particular exemption, but 

no other, in the regulatory text makes it 

clear that individual pollutants may be 

exempted only where emissions of those 

pollutants are below the de minimis 

threshold. Under the commenters’ 

theory that sources are subject-to-BART 

on a pollutant-by-pollutant basis, a 

source with an impact at a Class I area 

was 0.4 dv for SO2 and 0.4 dv for NOX

would not be subject to BART at all, 

even though it clearly contributes to 

visibility impairment. EPA recognized 

the absurdity of this situation, and 

therefore chose to use the de minimis 

exceptions as the only means by which 

a state can avoid conducting a BART 

analysis for a given pollutant after the 

source as a whole has been deemed 

subject to BART. 

Moreover, the de minimis threshold is 

not based on historical emissions, as 

suggested by FMMI, but on the source’s 

PTE.182 PTE is defined as ‘‘the 

maximum capacity of a stationary 

source to emit a pollutant under its 

physical and operational design.’’ 183

Physical or operational limitations on 

emissions capacity (e.g., restrictions on 

hours of operation) may be taken into 

account, but only if those limitations are 

federally enforceable.184 For the Miami 

Smelter, the WRAP estimated an annual 

NOX emission rate of 156 tpy for the 

units constituting the BART-eligible 

source.185 FMMI has not identified 

enforceable physical or operational 

limitations that would limit potential 

emissions from these units to less than 

40 tpy. While FMMI cites to various 

documents that it asserts demonstrate 

that the Miami Smelter’s NOX emissions 

are below the de minimis threshold, 

these documents consist of historical 

records of emissions, fuel usage, and 

material throughput.186 They do not 

establish the maximum capacity of the 

BART-eligible source to emit NOX and 

therefore do not demonstrate that 

potential NOX emissions are less than 

40 tpy. Likewise, the fact that EPA has 

estimated that the historic baseline 

emissions from the BART-eligible units 

are 38 tpy does not establish that 

potential emissions are less than 38 tpy. 

Unlike subject-to-BART determinations, 

which are made based on a source’s 

PTE, emission rates for cost calculations 

in BART analyses are generally ‘‘based 

upon actual emissions from a baseline 

period.’’ 187 The PTE for the BARTeligible units at the Miami Smelters 

remains above 40 tpy, and the source is 

therefore subject-to-BART for NOX.

Based on our five-factor BART 

analysis for NOX emissions from the 

Miami Smelter, we proposed to 

determine that no additional controls 

are needed for purposes of BART. FMMI 

supports this conclusion, but argues that 

there is no need for an emission 

limitation to implement this 

determination. We do not agree. 

Regional haze implementation plans 

must contain ‘‘emission limitations 

representing BART’’ for all subject-toBART sources.188 In particular, either 

the State or EPA must establish an 

enforceable emission limit for each 

subject emission unit at the source and 

for each pollutant subject to review that 

is emitted from the source.189 This 

requirement applies even where BART 

is determined to be consistent with 

existing controls. Otherwise, emissions 

could increase to a level where 

additional controls would be warranted 

for BART, but no mechanism would 

exist to require such controls. Contrary 

to FMMI’s suggestion, additional BART 

controls could not be required by EPA 

in the next regional haze plan for 

Arizona, as BART is only required in 

the first regional haze plan and cannot 

be deferred to future planning 

periods.190 Thus, an emission limit for 

NOX is needed to comply with 40 CFR 

51.308(e). 

Comment: Earthjustice stated that 

EPA’s NOX emissions analyses and 

BART determinations are fatally 

deficient because the estimate of BARTeligible NOX emissions is based on the 

combustion of natural gas alone, with 

no consideration of the formation of 

thermal NOX in the converters and the 

electric furnace. 

Response: We do not agree with this 

comment for the reasons provided in 

response to similar comments regarding 

the Hayden Smelter. 

4. Comments on Enforceable Emission 

Limits for PM10

Comment: FMMI asserted that ‘‘EPA’s 

current reliance on the NESHAP 

standards to ensure enforceability 

demonstrates that the Agency’s criticism 

of Arizona’s SIP as lacking ‘emissions 

limits and compliance requirements’ 

was misplaced.’’ 

Response: We do not agree that our 

proposal to rely on the NESHAP 

provisions to ensure the enforceability 

of BART for PM10 at the Miami Smelter 

is inconsistent with our finding that the 

Arizona RH SIP lacked enforceable 

emission limits to implement BART. As 

explained in our actions on the Arizona 

RH SIP, ADEQ sought to rely on the 

NSPS requirements to ensure the 

enforceability of its SO2 BART 

determinations for both the Hayden and 

Miami Smelters.191 However, under the 


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192 In particular, the Title V permit for the Miami 

Smelter makes the 0.065 percent NSPS limit 

applicable to emissions from the acid plant, but not 

the remainder of the facility’s emissions. ADEQ 

Title V Permit 53592 for Miami Smelter (2012), 

Attachment B section IV.C.1.a. 

193 Id. section IV.C.4. 

194See, e.g., id; section I.C (40 CFR Part 63 

Subpart QQQ General Requirements), VI.A (Smelter 

Fugitives, Particulate Matter and Opacity). 

195Miami Project Execution, schedule provided 

to EPA by FMMI, at a May 13, 2014 teleconference. 

196Phone call between FMMI and EPA (May 28, 

2014). 

197These requirements apply only if PCC chooses 

to comply with 2.12 lb/ton rolling 30-kiln operating 

day limit for NOX, rather than the 810 tpy 12-month 

rolling limit. 

State’s interpretation, as set out in the 

two smelters’ Title V permits, the NSPS 

requirements do not apply to all of the 

BART sources’ emissions.192 The 

permits also contain ‘‘permit shields’’ 

that limit the independent 

enforceability of the NSPS 

requirements, except to the extent that 

they are specifically listed in the 

facilities’ Title V permits.193 Therefore, 

NSPS provisions in the copper smelters’ 

permits do not apply to all subject-toBART emissions at the smelters and do 

not satisfy the requirements of the Act 

or the RHR. By contrast, the Miami 

Smelter’s Title V Permit does not 

restrict the applicability of the NESHAP 

requirements to the acid plant.194

Nonetheless, in order to ensure that the 

requisite emission limits and 

enforceability requirements are 

included in the applicable 

implementation plan, we are 

incorporating the applicable NESHAP 

requirements by reference as part of the 

final FIP for the Miami Smelter. 

5. Other Comments 

Comment: FMMI requested that EPA 

extend its proposed compliance 

deadline for the Miami Smelter until at 

least 2018. FMMI noted that ‘‘entities in 

many regulated industries anticipate 

undertaking significant engineering and 

construction projects in the near term to 

comply with regulations promulgated to 

implement new 1-hour NAAQs’’ and 

that ‘‘the high volume of this work 

could lead to a shortage of skilled 

laborers to complete the necessary 

construction to install pollution control 

equipment.’’ Accordingly, FMMI asked 

that EPA extend the proposed 

compliance deadline to 2018. AMA also 

asserted that EPA should extend the 

compliance deadline in the rule for the 

Miami Smelter. 

Response: We partially agree with this 

comment. Following the close of the 

public comment period, FMMI 

submitted the construction schedule for 

its planned SO2 control upgrades. The 

schedule indicates that FMMI will 

conclude construction of the roofline 

capture system and aisle scrubber by 

March 2017.195 FMMI also indicated 

that a shakedown period is necessary to 

ensure that the capture system and 

scrubber can meet the requirements of 

the FIP.196 Based on the additional 

information provided by FMMI, we 

agree that additional time beyond the 

proposed compliance deadline of three 

years from promulgation (i.e., roughly 

July 2017) is needed. However, because 

the averaging period for the BART limit 

for SO2 has been increased from 30 days 

to 365 days, we do not agree that a full 

additional year is needed to comply 

with the requirements of the FIP. 

Therefore, we are extending the BART 

compliance deadline to January 1, 2018. 

VII. Responses to Comments on EPA’s 

Proposed Reasonable Progress 

Determinations 

A. Comments on Phoenix Cement 

Clarkdale Plant 

Comment: NPS expressed support for 

EPA’s proposal to require emission 

limits for RP equivalent to SNCR to 

reduce NOX at the Clarkdale Plant. 

Response: We acknowledge NPS’s 

support for the proposed RP 

determination. The final rule contains 

two compliance options: a 2.12 lb/ton 

emission limit calculated on a rolling 

30-kiln-operating-day basis, and an 810 

tpy limit calculated on a rolling 12- 

month basis. Both emission limits 

reflect the degree of emission reduction 

achievable with the installation and use 

of SNCR. 

Comment: Earthjustice argued that 

SNCR can reach higher control 

efficiencies for NOX than the 50 percent 

control efficiency assumed by EPA in 

the proposal. Earthjustice requested that 

EPA look more closely at the 

capabilities of SNCR and the specific 

performance of the control technology 

on other kilns, specifically those 

referenced by Earthjustice. Earthjustice 

asserted that such an examination 

would ensure that the final control 

efficiency selected to represent SNCR 

would be consistent with the actual 

performance of this technology at Kiln 

4. 

Response: We partially agree with this 

comment. Although the commenter 

notes that SNCR is capable of achieving 

80 to 90 percent control in certain sitespecific instances, these results 

typically represent the highest end of 

the range of SNCR performance. In 

addition, while such levels of control 

are attainable on a short-term basis, they 

are not necessarily consistently 

sustainable over longer periods, such as 

on a 30-day or annual basis. We note 

that the reports provided by Earthjustice 

assumed much lower control 

efficiencies (35 to 50 percent) for 

purposes of calculating costeffectiveness, which is calculated on an 

annual average basis. Our use of 50 

percent for the SNCR control efficiency 

in the BART analysis is not intended to 

indicate the maximum effectiveness of 

SNCR. Information submitted by the 

commenter, as well as information that 

we included in our proposed 

rulemaking, does indicate that SNCR 

technology is capable of achieving 

greater than 50 percent control 

efficiency at preheater/precalciner kilns 

under certain conditions. It is possible 

that a site-specific optimization program 

at Kiln 4 could identify operating 

parameters and conditions that could 

result in an SNCR control efficiency 

greater than 50 percent. As noted in our 

proposed rulemaking, the optimization 

report from the CalPortland Mohave 

plant indicates a range of SNCR 

efficiency between 30 and 60 percent for 

a preheater/precalciner kiln (the same 

type as Kiln 4 at the Clarkdale Plant). 

However, site-specific information is 

not available for the Clarkdale Plant. In 

the absence of information indicating 

the extent to which the design and 

operating conditions at higher 

performing kilns are similar to, or 

replicable at, the Clarkdale Plant, we do 

not consider it appropriate to base our 

analysis on the higher control efficiency 

values. In developing the SNCR control 

efficiency used in our analysis, we 

examined the most stringent level of 

control attributed to SNCR at other 

similar facilities (as a retrofit on 

preheater/precalciner kilns) in other 

regulatory actions. These results are 

summarized in our proposed rule, and 

indicate that a 50 percent control 

efficiency is the most stringent SNCR 

control efficiency that has been applied 

to a preheater/precalciner kiln in other 

actions. Accordingly, we have used a 50 

percent control efficiency as the basis 

for cost and emission calculations for 

the Clarkdale Plant. 

However, in response to concerns 

raised by Earthjustice and in order to 

ensure that performance of the SNCR 

system installed at the Clarkdale Plant 

is optimized, we are including in the 

final rule a series of control technology 

demonstration requirements.197 In 

particular, PCC is required to prepare 

and submit to EPA: (1) A design report 

describing the design of the ammonia 

injection system to be installed as part 

of the SNCR system; (2) data collected 

during a baseline period; (3) an 

optimization protocol; (4) data collected 


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198See Guidance for Setting Reasonable Progress 

Goals Under the Regional Haze Program (June 1, 

2007) (‘‘RP Guidance’’) section 5.1 (recommending 

use of BART Guidelines and CCM for calculating 

costs of compliance for stationary sources); BART 

Guidelines, 70 FR at 39166–68 (Impact analysis part 

1: How do I estimate the costs of control?). 

199 70 FR 39170. 

200 D-06c-AZ_RP_sources_all-Task9_2012-09- 

30.xlsx. 

201See, e.g. Summary of Communications and 

Consultation between EPA, Phoenix Cement 

Company (PCC), and Salt River Pima Maricopa 

Indian Community (SRPMIC) Regarding Potential 

Reasonable Progress (RP) Controls for Phoenix 

Cement Clarkdale Plant (January 27, 2014); Revision 

to the Regional Haze SIP for the State of Arizona 

with Technical Support Document (May 3, 2013); 

Attachments to the 2013 Arizona Regional Haze SIP 

revision (May 3, 2013). 

during an optimization period; (5) an 

optimization report establishing 

optimized operating parameters; and (6) 

a demonstration report including data 

collected during a demonstration 

period. While this type of control 

technology demonstration is not 

typically required as part of a regional 

haze plan, we consider it to be 

appropriate here, given the significant 

variability in control efficiencies 

achievable with SNCR at cement kilns. 

Based upon the data collected, EPA may 

revise the lb/ton emission limit in a 

future notice and comment rulemaking 

action. 

Comment: PCC said that it supports 

the alternative of a cap on NOX

emissions for Kiln 4 of 810 tpy on a 

rolling 12-month basis, effective 

December 31, 2018. However, PCC 

conditioned its support on the final FIP 

expressly providing PCC with the 

option to select either the cap or the 

output-based emission limit by the 

deadline of December 31, 2018. 

Otherwise, PCC opposed a cap on NOX

emissions for Kiln 4 on the grounds that 

EPA is not authorized by law to impose 

a mass cap in lieu of an emission limit. 

PCC also requested that the FIP provide 

PCC with the option to switch 

compliance scenarios after December 

31, 2018, pursuant to either an 

alternative compliance scenario 

provision in the FIP or a similar 

provision in the facility’s Title V permit. 

PCC stated that this approach would 

best address the continuing fiscal 

impacts on the SRPMIC that will result 

from the FIP. 

Response: As explained in an earlier 

response, we disagree that the RHR 

precludes EPA from establishing a 

source-specific annual emission cap for 

the purpose of achieving emission 

reductions to ensure reasonable 

progress. In the final rule, we are 

including provisions for both mass cap 

and an output-based emission limit, and 

are providing PCC with a deadline of 

June 30, 2018, to decide on the emission 

limit with which it will demonstrate 

compliance by December 31, 2018. 

Comment: PCC and ADEQ asserted 

that EPA’s assessment of baseline 

visibility impacts attributable to PCC is 

based on inappropriate assumptions. In 

particular, PCC commented that EPA’s 

CALPUFF modeling is based on a NOX

emission rate calculated using the 

maximum rated capacity of PCC’s 

Schenck feeder, a backup feeder that is 

never used unless the primary feeder is 

down for repair or maintenance. 

Therefore, the NOX emission rate used 

in the modeling is not representative of 

actual or reasonably foreseeable 

conditions. EPA should re-propose the 

FIP using a more realistic NOX emission 

rate in the modeling, or else revise the 

model outputs accordingly in the final 

FIP. 

PCC also stated that EPA’s CALPUFF 

modeling is based on a NOX emissions 

factor that was different from that used 

in EPA’s cost analysis. In the cost 

analysis, EPA used ‘‘[a]nnual baseline 

emissions . . . calculated using the 

average of the lb/ton NOX emissions 

factors . . . observed over a 2005 to 

2010 timeframe.’’ For the CALPUFF 

modeling, EPA used the highest NOX

emissions factor (3.69 lbs/ton) that 

corresponds to the year 2008. PCC 

asserted that EPA should re-propose the 

FIP to harmonize the two approaches or 

revise the model outputs accordingly in 

the final FIP. 

Response: We disagree that the NOX

emission rate used in the modeling is 

unrealistic and unrepresentative of 

actual or reasonably foreseeable 

conditions. With regard to the emissions 

factors used for calculating the costs of 

compliance, we have determined costs 

of compliance on an annual average 

basis, with costs and emissions 

calculated on an annualized basis (e.g., 

dollars/year, tons emitted/year, tons 

removed/year), as recommended in the 

BART Guidelines.198 With regard to 

visibility modeling, while visibility 

improvement is not listed in the CAA or 

RHR as a required factor for evaluating 

individual RP sources, we consider it to 

be relevant and have therefore 

considered it as a supplemental factor in 

our RP analyses. In general, we have 

used the same modeling approach for 

RP sources as for BART sources, as we 

consider this to be a reasonable means 

of assessing visibility benefits from 

potential controls at specific sources. In 

particular, since the visibility modeling 

examines improvement on certain days, 

emission rates used in visibility 

modeling correspond to daily emission 

rates. As described in the BART 

Guidelines, pre-control (baseline) model 

emission rates for BART sources use the 

24-hour average actual emission rate 

from the highest emitting day over a 

specified baseline period.199 For cement 

kilns, actual emission data are either not 

recorded on a daily basis, or are not 

publicly available. As noted in the TSD 

for the proposed rulemaking, baseline 

emissions for the Clarkdale Plant were 

developed primarily from information 

contained in annual emission 

inventories reported to ADEQ. Since 

these reports provide only total annual 

emissions and annual average emissions 

factors (lb/ton clinker), it is not possible 

to identify the highest emitting day 

based on this information. As a result, 

the single highest annual average 

emission factor (lb/ton clinker) was 

used in combination with short-term 

production capacity (ton clinker/day) in 

order to estimate a short-term emission 

rate (lb/day) that is representative of the 

highest emitting day. As noted in the 

model emission spreadsheet included in 

the docket for the proposed rule,200 the 

maximum 24-hour average NOX

emission rate used for the baseline is 

645 lb/hour, or about 7.75 tons/day. A 

summary of calculated daily NOX

emissions for the Clarkdale Plant is now 

included in the docket for this final 

rulemaking. As seen in these emission 

data, there were 12 days between 2005 

and 2010 in which daily emissions were 

higher than the modeled baseline 

emission rate, ranging from 7.77 tons/

day to 11.91 tons/day. Since the 

Clarkdale Plant has emitted at rates 

greater than those modeled in the 

baseline scenario, we disagree that the 

baseline NOX emission rate we selected 

is unrepresentative of actual or 

reasonably foreseeable conditions. 

Regarding the use of the Schenk 

feeder’s capacity in emission 

calculations rather than the primary 

feeder’s capacity, we note that the 

primary feeder’s capacity is specified as 

simply ‘‘NA’’ in the Clarkdale Plant’s 

Title V permit. Furthermore, this 

information was not provided by ADEQ 

or PCC in their comments or any other 

communication with EPA over the last 

18 months.201 In addition, while PCC 

has stated that use of the primary 

feeder’s capacity, combined with other 

revisions to emission calculations, 

could result in 25 percent lower NOX

emissions, it has not provided 

supporting data to justify this claim, 

such as the primary feeder’s capacity. 

The modeled baseline emission rate is 

within the range of actual emissions 

reported for the Clarkdale Plant, as 

noted in the previous paragraph. Thus, 

we consider that 645 lb/hour is a 


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202TSD at 13–14. 

203 ‘‘Revision to the Guideline on Air Quality 

Models: Adoption of a Preferred Long Range 

Transport Model and Other Revisions’’, 68 FR 

18440, April 15, 2003. 

204 40 CFR Appendix W, Guideline on Air Quality 

Models section 7.2.1.e. at the time of promulgation, 

68 FR 18440, April 15, 2003; later moved to section 

6.2.1.e, 70 FR 68218, November 9, 2005. 

205 40 CFR part 51, appendix Y, IV.D.5. or 70 FR 

39170. 

206TSD section IV.C.3, p.109. 

207 Docket spreadsheet PhoenixCement_vis_

NO2conv.xlsx. 

representative characterization of the 

facility’s baseline emission rate. 

Comment: According to PCC, EPA 

post-processed its CALPUFF dispersion 

modeling results using IMPROVE 

Method 8b to compute extinction and 

delta deciview impacts attributable to 

the Clarkdale Plant’s NOX emissions. 

PCC said that EPA should re-propose 

the FIP to solicit comments on the 

applicability of Method 8b for the RHR, 

or propose its understanding of how 

best to assess source-specific visibility 

impacts in a separate notice and 

comment rulemaking, before it uses 

Method 8b in the regional haze context. 

In the alternative, EPA could issue a 

separate notice-and-comment 

rulemaking to explain the Agency’s 

understanding of how best to assess 

source-specific visibility impacts using 

Method 8b before EPA uses Method 8b 

to impose legal obligations on the 

regulated community. 

Response: The details of our visibility 

analyses are in the TSD and the public 

has had ample opportunity to comment 

on these analyses through the notice 

and comment process on our proposal. 

With regard to use of Method 8b in 

particular, the ‘‘8’’ in ‘‘8b’’ refers to 

‘‘method 8’’ in CALPOST, a postprocessor for the CALPUFF model, and 

indicates that CALPOST uses the 

revised IMPROVE equation for 

calculating visibility impact from 

pollutant concentrations (as opposed to 

‘‘method 6’’ which specifies the original 

IMPROVE equation). The ‘‘b’’ refers to 

natural conditions on the 20 percent 

best days (as opposed to ‘‘a’’ for annual 

average natural conditions). As 

explained in our TSD, ‘‘Method 8 is 

currently preferred by the [FLMs]’’ and 

use of ‘‘b’’ (best 20 percent) is 

‘‘consistent with initial EPA 

recommendations for BART [and] 

current [FLM] guidance for assessing 

visibility impacts at Class I areas.’’ 202

The commenter has not asserted or 

provided any evidence that EPA’s 

reliance on method 8b is unreasonable 

or that use of another method is 

preferable in this instance. Therefore, 

we do not agree that any further notice 

and comment process is needed to 

evaluate our assessment of sourcespecific visibility impacts. 

Comment: PCC noted that CALPUFF 

‘‘is nominally for great distances and, 

therefore, assumes the NO component of 

NOX emissions is fully converted to NO2

that is then ‘available to form visibilitydegrading particulate nitrate.’ ’’ 

However, PCC is ‘‘only 10.5 km’’ from 

Sycamore Canyon Wilderness Area 

(SCWA), the nearest and most affected 

Class I area. PCC stated that EPA’s 

sensitivity analysis is arbitrary and does 

not appear to support EPA’s proposal to 

impose an SNCR-based standard on the 

Clarkdale Plant, given the significant 

reductions in SNCR-related visibility 

benefits in the SCWA that would result 

from lower NO–NO2 conversion rates. 

PCC stated that EPA should re-propose 

the FIP using photochemical modeling 

to determine appropriate estimates of 

NO-to-NO2 and NO2-to-NO3

conversions, the nitrogen species’ 

effects on visibility in the SCWA, and 

the improvement in visibility that 

would result from the use of SNCR at 

the Clarkdale Plant. 

Response: NO is converted to NO2

and NO3

¥ by oxidants such as ozone. 

This conversion takes some time, since 

the plume from the facility does not 

instantly mix into the ambient air 

containing oxidants. We agree with the 

PCC that NO emitted by the Clarkdale 

Plant may not fully convert to NO2 by 

the time it reaches the nearby SCWA, 

and therefore may not fully form 

visibility-impairing nitrate (NO3

¥). 

However, we disagree CALPUFF can 

only be used to model great distances, 

that our sensitivity analysis is arbitrary, 

or photochemical modeling is necessary 

in this instance. PCC stated that 

CALPUFF ‘‘is nominally for great 

distances.’’ It is true that we 

promulgated CALPUFF with distances 

greater than 50 km in mind.203

However, we also approved it for 

situations with complex wind 

situations, and specifically 

recommended CALPUFF for regional 

haze analyses. EPA’s Guideline on Air 

Quality Models states that CALPUFF 

(Section A.3) may be applied when 

assessment is needed of reasonably 

attributable haze impairment or 

atmospheric deposition due to one or a 

small group of sources.204 Further, the 

BART Guidelines provide that in 

situations where one is assessing 

visibility impacts for source-receptor 

distances less than 50 km, one should 

use expert modeling judgment in 

determining visibility impacts, giving 

consideration to both CALPUFF and 

other EPA-approved methods.205 In this 

instance, we consider CALPUFF to be 

the most appropriate EPA-approved 

method, but have also conducted 

additional analyses to account for the 

limitations of CALPUFF at distances 

less than 50 km. 

In particular, we acknowledge that 

CALPUFF’s assumption that NO is 

totally converted to NO2 and NO3

might not be warranted for all 

circumstances. NO is converted to NO2

and NO3 by oxidants such as ozone. 

This conversion takes some time, since 

the plume from the facility does not 

instantly mix into the ambient air 

containing oxidants. The Clarkdale 

Plant is only 6.5 miles from the SCWA. 

We explored this issue in our proposal 

in the form of a sensitivity analysis 

described in the TSD 206 and an 

associated spreadsheet.207 We scaled the 

nitrate portion of the visibility impact of 

the Clarkdale Plant on SCWA to reflect 

NO-to-NO2 conversion rates ranging 

from 10 percent to 100 percent. We used 

10 percent as an absolute lower bound 

because typically 10 percent of emitted 

NOX (the sum of NO and NO2) is already 

in the form of NO2, but we consider 25 

percent a more reasonable assumption, 

since there is time for some conversion 

during the plume’s travel to SCWA. We 

disagree that this analysis is ‘‘arbitrary’’ 

as asserted by PCC, because it covers the 

full range of possible conversion rates, 

as shown in Table 7. 

TABLE 7—SYCAMORE CANYON VISIBILITY BENEFIT FROM SNCR ON CLARKDALE CEMENT PLANT AS A FUNCTION OF NO 

CONVERSION 208

NO to NO2 Conversion 

10% 25% 50% 75% 100% 

Base Visibility Impact (dv) ....................................................................... 1.17 1.94 3.13 4.19 5.14 

Visibility Impact with SNCR (dv) .............................................................. 0.92 1.42 2.07 2.68 3.30 


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208 Id. 

209See EPA’s Air Quality System Database at 

http://www.epa.gov/ttn/airs/airsaqs/. 

210 Id. 

211 Id. 

212See 70 FR 39120 (‘‘States should consider a 

1.0 deciview change or more from an individual 

source to ‘cause’ visibility impairment, and a 

change of 0.5 deciviews to ‘contribute’ to 

impairment.’’). 

213RP Guidance section 5.1. 

214 In addition to the public comment period on 

our proposed FIP, EPA previously provided PCC 

with two opportunities to review and provide 

feedback on our analysis for the Clarkdale Plant. 

See email from Colleen McKaughan, EPA, to Verle 

Martz, PCC (November 6, 2012); email from 

Charlotte Withey to George Tsiolis (December 11, 

2013). 

215F–42—2013–03–06 Comments from Phoenix 

Cement Co.pdf. 

TABLE 7—SYCAMORE CANYON VISIBILITY BENEFIT FROM SNCR ON CLARKDALE CEMENT PLANT AS A FUNCTION OF NO 

CONVERSION 208—Continued 

NO to NO2 Conversion 

10% 25% 50% 75% 100% 

Improvement (dv) ..................................................................................... 0.25 0.52 1.06 1.51 1.85 

We also disagree that we must use 

photochemical modeling for this 

visibility assessment. The range of NO 

conversion rates assumed in our 

sensitivity analysis already spans 

whatever rate would be derived using a 

photochemical model. As noted in our 

proposed rule, considering that SNCR is 

very cost-effective in this instance, we 

consider a benefit of 0.25 dv at a single 

Class I area to be sufficient to warrant 

SNCR as a control for RP. Given that 

SNCR is warranted for any conversion 

rate, photochemical modeling would 

not alter our decision. Even if we were 

to perform such modeling, it would be 

strongly dependent on the background 

concentration of ozone and other 

oxidants in the local area for which no 

ozone measurements are available. The 

two ozone monitors nearest to the 

Clarkdale Plant are both about 28 miles 

away at Prescott to the southwest and in 

the opposite direction at Flagstaff.209

One might also use modeled ozone, 

derived from photochemical modeling 

of NOX and VOC sources over a large 

area, but such an estimate would have 

its own uncertainties. For example, the 

results may not be sufficiently precise at 

the 6.5-mile scale in question to provide 

an accurate ozone background. 

Therefore, we do not agree that 

photochemical modeling is preferable to 

CALPUFF or required in this instance. 

Comment: PCC stated that EPA’s 

conclusion that SNCR should be 

considered the basis of an RHR standard 

for the Clarkdale Plant is without 

reference to a decision-making 

threshold. EPA stated that ‘‘the benefit 

of SNCR remained substantial even for 

the lowest (NO–NO2) conversion 

assumption.’’ However, PCC stated that 

EPA does not state or justify what 

visibility benefit is ‘‘substantial’’ enough 

to warrant imposition of RHR control 

technology-based standards on a BARTineligible source. In PCC’s case, PCC 

stated that EPA does not explain or 

justify how low the improvement in 

visibility would have had to go before 

EPA would have decided the visibility 

benefits are not ‘‘substantial’’ enough to 

impose a standard based on SNCR. 

Absent this, PCC believes EPA’s 

decision to impose on PCC a standard 

based on SNCR is arbitrary. PCC stated 

EPA should re-propose the FIP to 

provide such explanation and 

justification for public comment, or 

provide them in the final FIP. 

Response: We do not agree with this 

comment. The RHR does not require the 

development of specific thresholds for 

any of the RP factors. If 100 percent 

NO–NO2 conversion is assumed, SNCR 

is expected to reduce Kiln 4’s visibility 

impact at SCWA from 5.14 dv to 3.30 

dv, resulting in a benefit of 1.85 dv, 

which is quite large.210 Assuming only 

10 percent conversion, SNCR is 

expected to reduce the Clarkdale Plant’s 

visibility impact at SCWA from 1.17 dv 

to 0.92 dv, a benefit of 0.25 dv, which 

would still contribute to improved 

visibility.211 Given that the four RP 

factors establish SNCR as a reasonable 

control for the Clarkdale Plant, we 

consider this visibility benefit sufficient 

to support installation of controls 

during this planning period. Indeed, 

because SNCR would reduce the 

facility’s impact from more than 1 dv to 

less than 1 dv, the Clarkdale Plant 

would no longer cause visibility 

impairment at SCWA, but would 

instead only contribute to such 

impairment.212

Comment: PCC asserted that EPA 

used the wrong cost for ammonium 

hydroxide. PCC argued that the correct 

cost is $1,180/ton, not $1,000/ton, based 

on information PCC provided to EPA on 

December 20, 2013. PCC stated that EPA 

also used a 15 percent contingency on 

costs without reference to a 

promulgated rule for that percentage 

and without offering a reasoned 

justification of the use of that percentage 

generally or in PCC’s case. PCC 

concluded that EPA should re-propose 

the FIP to include legally applicable 

inputs, explain why its inputs are not 

arbitrary, or revise its cost analysis 

accordingly in the final FIP. PCC added 

that EPA’s analysis relied on EPA’s 

CCM, which has no legal force because 

it has never been subjected to a notice 

and comment rulemaking. Therefore, 

PCC concluded that EPA should repropose the FIP to eliminate its reliance 

on the CCM in PCC’s case, or else adjust 

its determination for PCC in the final 

FIP to exclude all assumptions based on 

the CCM or justify such assumptions on 

their merits so that they are not 

arbitrary. 

Response: We disagree with these 

comments. EPA’s RP Guidance 

specifically recommends use of the 

CCM in evaluating the cost of controls 

for potentially affected RP sources.213

While the CCM itself has not been 

subject to notice and comment 

rulemaking, our use of the CCM in this 

rulemaking has been subject to public 

notice and comment, and PCC has had 

ample opportunity to dispute all 

assumptions in our analysis.214 In this 

instance, PCC provided its own SNCR 

cost estimate that also relied on 

information from the CCM for certain 

line items (such as direct and indirect 

installation costs), as well as internal 

cost estimates for other line items 

(SNCR purchased-equipment cost).215 In 

our proposed rule, we accepted the 

majority of PCC’s cost analysis and 

included all of the line items provided 

by PCC. In specific instances, where we 

found a particular line item cost to be 

excessive or unjustified, we revised the 

value provided by PCC in order to 

ensure a fair and meaningful 

comparison of costs between the 

Clarkdale Plant and other facilities. In 

no case did we entirely eliminate or 

disregard the cost of a line item 

provided by PCC. 

In the case of reagent cost, PCC used 

a reagent cost of $0.59/lb (i.e., $1,180/ 

ton), citing the cost-effectiveness 

analysis performed for the BACT 

analysis of the Drake Cement Plant’s 

PSD construction permit in 2005. Based 


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216AEPCO Final Comments to AZ FIP_SIP_CBI 

included.pdf, C–37 Letter from Erik Bakken, TEP, 

to Greg Nudd, EPA, re TEP Sundt Modeling & Cost 

Information. 

217RP Guidance section 5.4. 

218CCM section 4.2, chapter 1, section 1.4.2, page 

1–37. 

219As a result of using a 1,513 tpy NOX baseline 

emission rate instead of 1,620 tpy as described in 

the proposed rule. 

220As a result of using a 3.69 lb/ton baseline 

emission factor instead of a 3.25 lb/ton emission 

factor as described in the proposed rule. 

221Use of a 1,513 tpy baseline emission rate 

would result in an SNCR cost-effectiveness of 

$1,215/ton, rather than $1,162/ton in the proposed 

rule. 

on the information provided by PCC, 

this estimate does not appear to have 

been updated or adjusted from its 

original 2005 estimate, nor has PCC 

explained why the estimate provided for 

a different plant is appropriate for the 

Clarkdale Plant. As noted in the 

proposed rule, we used a reagent cost of 

$1,000/ton, based on recent historical 

prices (about $500/ton) and increased it 

by a factor of two in order to account for 

potential fluctuations in ammonia 

prices over the 20-year useful life of the 

control equipment. Absent additional 

details from PCC indicating a more 

recent or site-specific justification for an 

ammonia cost of $1,180/ton, we 

consider our estimate of $1000/ton to be 

a reasonable and sufficiently 

conservative estimate for the price of 

ammonia. 

In the case of cost contingency, we 

consider the 40 percent contingency 

suggested by PCC, without additional 

site-specific information to support it, to 

be excessive. The CCM uses 

contingency values ranging from five to 

15 percent, depending upon the control 

device in question and the precise 

nature of the factors requiring 

contingency. We have used the upper 

end of this estimate in our cost 

calculation. In no instance does the 

CCM provide for a generic contingency 

value as high as 40 percent. We 

recognize, however, that retrofit 

installations may pose additional cost 

estimate uncertainty (i.e., cost 

contingency). Consequently, we have 

incorporated estimates of such 

additional costs at other facilities 

affected by our regional haze FIP 

actions.216 In these instances, however, 

affected facilities provided greater detail 

regarding the additional costs, which we 

incorporated either as additional 

specific line items or as larger 

purchased equipment costs. We do not 

consider it appropriate to include these 

additional retrofit costs in a generic 

contingency value. Therefore, we are 

retaining the 15 percent contingency 

value. 

Comment: PCC said that reliance on 

the EPA’s CCM for the 20-year useful 

life presumption for amortization is 

inappropriate because the CCM was 

never subject to notice and comment 

rulemaking. PCC stated that the EPA 

should re-propose the FIP to eliminate 

its reliance on the CCM in PCC’s case, 

or adjust its determination for PCC in 

the final FIP to exclude all 

presumptions based on the CCM, or 

justify such presumptions on their 

merits so that they are not arbitrary. 

Response: We do not agree with this 

comment. EPA’s RP Guidance 

recommends use of the CCM in 

considering the remaining useful life of 

potentially affected RP sources, and 

explains that ‘‘the methods for 

calculating annualized costs in EPA’s 

[CCM] require the use of a specified 

time period for amortization that varies 

based upon the type of control.’’ 217 The 

CCM, in turn, provides that ‘‘[a]n 

economic lifetime of 20 years is 

assumed for the SNCR system.’’ 218 As 

noted in the previous response, while 

the CCM itself has not been subject to 

notice-and-comment rulemaking, our 

use of the CCM in this particular 

rulemaking has been subject to public 

notice and comment. PCC has had 

ample opportunity to dispute all 

assumptions in our analysis, including 

the 20-year amortization period. 

However, PCC has provided no 

evidence that our use of an equipment 

lifetime of 20 years is inappropriate in 

this instance. On the contrary, PCC 

submitted a four-factor analysis dated 

March 28, 2013, which states that Kiln 

4 has a remaining useful life of roughly 

50 years. Thus, there is no evidence in 

the record to suggest that an 

amortization period of less than 20 years 

is appropriate for capital costs of SNCR 

at Kiln 4. 

Comment: Earthjustice disagreed with 

EPA’s calculation of baseline emissions 

for Kiln 4, noting that the baseline value 

of 1,620 tpy employed by EPA is higher 

than actual annual emissions from 2005 

through 2010. Earthjustice asserted that 

using baseline emissions that are higher 

than any of the baseline years is bad 

policy and bad precedent, and urged 

EPA to use the maximum of the actual 

observed emissions from the baseline 

period, which is 1,513 tpy in 2005. 

Response: We disagree that the 

baseline emission rate should be 

adjusted in the manner suggested by 

Earthjustice. The challenges associated 

with accurately characterizing the 

baseline emissions for a source that 

exhibited such significant variation in 

cement production, annual emissions, 

and emission factors over the baseline 

period are documented in our proposed 

rule. We acknowledged in our proposed 

rule that our method marginally 

overstates the annual baseline emission 

rate. However, we do not consider the 

method proposed by Earthjustice, which 

involves using the maximum actual 

baseline value observed, to be a more 

accurate characterization of baseline 

emissions. We acknowledge that 

Earthjustice’s method would result in a 

marginally lower annual emission 

limit,219 but Earthjustice’s method 

would also result in a higher lb/ton NOX

emission limit.220 We do not consider 

the use of the maximum observed 

emission factor (lb/ton), which is the 

result of low levels of kiln production, 

as a realistic depiction of anticipated 

annual emissions from the source. 

Moreover, an adjustment of the baseline 

by this amount would not alter our 

determination that SNCR constitutes the 

appropriate RP control for Kiln 4.221

Comment: PCC noted an 

inconsistency between the proposed 

compliance date in the preamble 

applicable to the Clarkdale Plant, ‘‘by 

December 31, 2018,’’ and the 

compliance date in the proposed 

regulations, ‘‘no later than (three years 

after date of publication of the final rule 

in the Federal Register).’’ PCC stated 

that it needs the maximum flexibility 

that EPA can provide, and requested 

that the compliance date in the final 

rule be stated as ‘‘no later than 

December 31, 2018.’’ Similarly, ADEQ 

asserted that, given the difficulty of 

retrofitting Kiln 4 with SNCR, more than 

three years is necessary to demonstrate 

compliance. By contrast, Earthjustice 

commented that the proposed 

compliance time frame of 4.5 years to 

install SNCR on the kiln is too long, 

asserting that the proposed compliance 

deadline has no basis, and should be 

shortened to one year. 

Response: EPA acknowledges that 

there is a discrepancy between the 

preamble and the regulatory language in 

the proposed FIP regarding the 

compliance date for the Clarkdale Plant. 

Unlike BART controls, which must be 

installed as expeditiously as practicable, 

RP controls are not subject to any 

particular compliance deadlines under 

the CAA and RHR, other than the 

overarching requirement to achieve 

reasonable progress during each 

planning period. PCC has indicated that 

it needs until December 31, 2018, to 

comply with any requirements of the 

FIP, which is also the end of the first 

planning period. While it may be 

technically feasible for the Plant to 

install SNCR before this date, we 


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222 42 U.S.C. 7602(k), 40 CFR 51.100(z). 

223See spreadsheet labeled ‘‘E–45—TEP Sundt4 

2001–12 Emission Calcs 2014–01–24.’’ 

224Although the term ‘‘cap’’ was used to describe 

the limit on Kiln 4, the commenter is correct to note 

that only Kiln 4 is subject to the ‘‘cap.’’ The ‘‘cap’’, 

therefore, essentially functions as an emission limit 

for a single emission unit. 

225We note, for example, that per 40 CFR 51.301 

(Definitions), BART represents an emission limit, 

not necessarily a requirement to install a specific 

control technology. 226See TSD at 92–93. 

consider it appropriate in this instance 

to provide the facility until December 

31, 2018. We have amended the 

regulatory text to require compliance 

with the NOX emission limit and other 

NOX-related requirements no later than 

December 31, 2018. 

Comment: Earthjustice did not 

support revising the 30-day average 

emission limit in order to accommodate 

startup and shutdown events at the 

Clarkdale Plant. Earthjustice concluded 

that the proposed upward revision is 

not warranted. In contrast, PCC 

commented that the method EPA used 

to derive the 2.12 lb/ton emission limit 

is ‘‘not unreasonable for being based on 

empirical data.’’ 

Response: Under the CAA and EPA’s 

implementing regulations, ‘‘emission 

limitation’’ is defined as a requirement 

which limits the quantity, rate, or 

concentration of emissions of air 

pollutants ‘‘on a continuous basis.’’ 222

Thus, the emission limits established in 

the FIP apply at all times, including 

periods of startup, shutdown, and 

malfunction. Malfunctions are, by 

definition, unforeseeable, and cannot be 

accounted for in setting emission limits. 

By contrast, startup and shutdown are 

part of normal operations, and must be 

included when establishing emission 

limits. As discussed in our proposed 

rule, the 30 percent upward revision 

from the annual emission rate to the 30- 

day lb/ton limit was based on an 

examination of daily emissions (lbs) and 

production (tons clinker) data over a 

multi-year period for cement kilns 

(operating without SNCR) in which we 

identified the highest rolling 30-day 

emission rate and the highest annual 

average emission rate, and examined the 

difference between these values. A 

similar approach was used to develop 

the rolling 30-day emission limits for 

TEP Sundt Unit 4, and a copy of the 

emission data is included in the 

docket.223 Unlike the emission data for 

Sundt Unit 4, which are publicly 

available from EPA’s CAMD, the data 

we examined for the cement kilns 

contain daily production information 

that is considered CBI and we are 

generally prohibited from making it 

available for public review. The method 

we applied in developing the 30-day 

emission limit for the cement plants, 

however, is the same as the method 

documented for Sundt Unit 4 that is 

available for public review. While 

alternative methods might exist to 

account for these emissions, we did not 

receive any comments describing any 

alternative or more refined approaches 

to address this issue. Accordingly, we 

are finalizing the emission limit of 2.12 

lb/ton as proposed. 

Comment: Earthjustice opposed 

setting an annual NOX emission cap for 

the Clarkdale Plant’s Kiln 4. According 

to Earthjustice, the cap is inexplicable 

because there is just the single kiln at 

the facility, and a cap is not needed. 

Earthjustice pointed out that EPA 

acknowledges that the facility can meet 

the cap without further controls. 

Earthjustice would support a 

combination of a unit-specific massbased emission limit (e.g., ton/year or 

ton/day) and an output-based limit (e.g., 

lb/ton clinker) in some situations. 

Nevertheless, Earthjustice opposed the 

NOX cap for Kiln 4 and urged EPA not 

to adopt the cap in the final rule. 

Response: We disagree with this 

comment. The RHR does not preclude 

the establishment of an annual emission 

limit 224 for the purpose of achieving 

emissions reductions for reasonable 

progress. As proposed, an annual NOX

emission limit of 810 tpy represents a 50 

percent reduction, consistent with the 

use of SNCR, relative to baseline 

emissions. In addition, we note that 

while the RHR does require the 

consideration of specific control 

technologies and emission reduction 

systems in BART and RP analyses, the 

emission limits established pursuant to 

the RHR do not specifically require the 

application of a specific control method 

or technology.225 Although the emission 

limit itself is based on the reductions 

achievable from a considered control 

option, the source is not required to 

install a specific technology to 

demonstrate compliance with the limit, 

and may pursue other means of meeting 

the limit. In this instance, PCC may 

elect to comply with the 810 tpy NOX

limit by installing SNCR, or may elect 

to limit cement production to about half 

of pre-2008 production levels. 

Comment: Earthjustice noted that EPA 

considered two BART controls options, 

SCR and SNCR, but that EPA rejected 

SCR as technically infeasible. 

Earthjustice disagreed with this 

decision, and provided information 

asserting that while SCR systems have 

proven impractical due to operational 

reasons at several European kilns, that 

is not the same as technical infeasibility. 

Earthjustice asserted that SCRs can work 

in cement kilns, but require additional 

maintenance that may impact the cost of 

the controls. However, because EPA did 

not do any cost analysis, Earthjustice 

asserted that it is impossible to state 

with certainty that SCR is not costeffective, which Earthjustice alleged is 

what is implied from EPA’s discussion. 

Thus, Earthjustice stated that EPA 

should not have conflated technical 

infeasibility and economic infeasibility 

when it rejected SCR. 

Response: We agree that SCR is 

technically feasible. We clarify that 

although SCR was not further 

considered after Step 2 (Eliminate 

Technically Infeasible Options) of the 

RP analysis, we consider SCR a 

technically feasible control option. 

While we explicitly eliminated other 

control options (e.g., mixing air 

technologies) in Step 2 as technically 

infeasible, we elected not to consider 

further SCR due to a lack of information 

that would allow us to evaluate its 

effectiveness and cost of controls on 

cement kilns. In particular, we note that 

SCR has not been commercially applied 

to a cement plant of any type in the 

United States, and there is little 

information available about its use on 

cement kilns in other countries.226

Thus, we lack sufficient information to 

conduct a four-factor analysis for SCR 

on cement kilns. 

B. Comments on CalPortland Cement 

Rillito Plant 

Comment: CPC asserted that the fourfactor analysis for the Rillito Plant must 

be done within the context of the RPGs. 

In the current litigation over EPA’s FIP 

governing three subject-to-BART power 

plants in Arizona, CPC noted that the 

petitioners argued that EPA erred by 

disapproving Arizona’s BART 

determinations without considering 

whether the Arizona RH SIP 

demonstrated reasonable progress. 

According to CPC, EPA asserted in 

response: 

Given that there is no statute or regulation 

plainly requiring EPA to consider sourcespecific BART determinations in the context 

of a state’s overall ‘‘reasonable progress,’’ the 

State must demonstrate that EPA’s approach 

was an unreasonable interpretation of EPA’s 

own regulations. 

Whether EPA is correct with respect 

to BART determinations, CPC asserted 

that 40 CFR 51.308(d)(l) and (d)(l)(A) 

plainly require EPA to consider sourcespecific reasonable progress factors in 

the context of establishing RPGs. CPC 

concluded that EPA should not, and 

cannot, take a position in this matter 


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227 79 FR 9363. 

that is patently inconsistent with its 

position currently pending before the 

Ninth Circuit Court of Appeals. 

Response: We do not agree that our 

action here is in any way inconsistent 

with our Phase 1 action or our brief 

defending that action. Furthermore, 

while we agree that the RHR requires 

consideration of the RP factors in the 

context of setting RPGs, we do not agree 

that our proposed FIP failed to comply 

with this requirement. The RPGs are 

analytical benchmarks that reflect the 

visibility improvement at each Class I 

area that is estimated to occur by the 

end of the planning period on the 20 

percent best and worst days after all 

reasonable control measures, including 

both RP determinations and BART 

determinations, have been 

implemented. In our proposed FIP, we 

proposed RPGs for Arizona’s Class I 

areas that reflect the combination of 

control measures included in the 

approved portions of the Arizona RH 

SIP (Phases 1 and 2), the partial Arizona 

RH FIP (Phase 1), and the proposed 

partial Arizona RH FIP (Phase 3) that we 

are finalizing today with some 

modifications.227 In addition, as 

explained elsewhere in this notice, we 

are now quantifying (in deciviews) the 

RPGs for each Class I area. 

Comment: CPC stated that the 

estimated cost per dv improvement for 

Kilns 1–3 in Table 43 of the proposal 

notice does not reflect the cost for all 

three kilns. According to CPC, the Table 

43 figures improperly compare the 

annual cost of SNCR at one kiln with 

the cumulative visibility improvement 

from requiring SNCR at all three kilns. 

CPC asserted that, based on EPA’s 

estimates, the corrected values would be 

$4.5 million/dv (cumulative 

improvement) and $14.3 million/dv 

(maximum improvement). CPC also 

stated there are several errors in the 

proposed FIP’s visibility modeling for 

Kilns 1–3. 

Response: We agree that Table 43 

reflects the annual cost of SNCR for one 

kiln, compared to the cumulative 

visibility improvement from requiring 

SNCR at all three kilns. However, this 

error had no impact on our proposed 

determination that no controls should 

be required for Kilns 1–3 at this time. 

Making the change suggested by CPC 

would further support this 

determination by increasing the $/dv 

value for SNCR at Kilns 1–3. Likewise, 

making the alterations in the modeling 

as suggested by CPC would not alter our 

determination that no controls are 

reasonable for Kilns 1–3 in this 

planning period. 

Comment: CPC stated that the 

proposed FIP underestimates ammonia 

costs (citing Exhibit 1 submitted with 

the comments). CPC stated that its total 

annual cost estimate, which differs from 

the proposed FIP’s only due to vendor 

quotes and site-specific information for 

ammonia costs, is $1,348,084. 

Response: As part of its comments, 

CPC provided an ammonia vendor quote 

of $1,336/ton (compared to our 

ammonia cost of $1000/ton in our 

proposed rule). We have revised the 

ammonia costs in our cost estimate 

based upon the vendor quote provided 

by CPC. This change, together with 

other revisions described below, results 

in a cost-effectiveness of $1,850/ton, 

which we consider to be very costeffective. 

Comment: Earthjustice and NPS 

indicated that they do not agree with 

EPA’s assessment of the control 

efficiency of SNCR for Kilns 1–3, which 

they believe is higher than 30 percent. 

In Earthjustice’s opinion, EPA randomly 

chose a 25 percent control efficiency for 

SNCR without explanation, despite the 

Agency’s acknowledgement that the 

technology is capable of reducing NOX

by as much as 40 percent. 

With respect to two other control 

options, Mid Kiln Firing (MKF) and 

Mixing Air Technology (MAT), 

Earthjustice noted similar concerns in 

that EPA simply accepted the 20 percent 

reduction from CPC’s observed range of 

11 to 55 percent NOX reduction, again 

without support or justification. Better 

support must be provided, or EPA 

should select a higher control efficiency 

for these control strategies. 

NPS agreed with EPA that it is not 

reasonable to require controls at the 

kilns that will not operate again, but 

noted that it does not agree with how 

EPA conducted the analysis to arrive at 

the decision not to require controls, 

particularly with regard to control 

efficiency assumptions, and emphasized 

that before the kilns begin operating, 

they should be reevaluated. 

Response: As noted in the proposed 

rule, and as pointed out by the 

commenters, we relied upon 

information provided by CPC to 

estimate the control efficiencies of 

various control options being analyzed 

for Kilns 1–3, specifically LNB, SNCR, 

and MKF. The information provided by 

CPC indicated a range of performances 

for each option. However, the sitespecific information available for Kilns 

1–3 was insufficient to allow us to 

determine that the maximum control 

efficiency values within the 

performance ranges were achievable at 

the kilns. Consequently, we reasonably 

chose to use control efficiency values 

that fell within the middle of the 

respective performance ranges. While 

the commenters advocate for control 

efficiency values at the high end of the 

performance ranges, they have provided 

no new site-specific information to 

demonstrate that more stringent levels 

of control are achievable. Finally, we 

note that Kilns 1–3 are long-dry kilns, 

whereas Kiln 4 is a preheater/

precalciner kiln. Given that more 

information is available regarding the 

control efficiency of SNCR on preheater/ 

precalciner kilns, we were able to 

estimate a higher control efficiency for 

SNCR at Kiln 4 (50 percent) than we 

were able to at Kilns 1–3. 

Comment: Earthjustice disagreed with 

EPA’s decision to require no further 

controls for Rillito Kilns 1–3. EPA 

justified its determination based on the 

fact that the kilns have not operated 

over the last five years, and the 

relatively high cost of controls. 

Earthjustice argued that EPA’s 

justification is inadequate because the 

kilns are not required to be permanently 

removed and an enforceable 

commitment from the company should 

be put in place if these units are to be 

exempt from RP controls. By contrast, 

CPC agreed with EPA that controls are 

not appropriate on Kilns 1–3 at this 

time. 

Response: As noted in our proposed 

rule, we do not consider it reasonable to 

require RP controls on Kilns 1–3 given 

the relatively high cost of the control 

options and the fact that these kilns last 

operated in 2008, and have therefore not 

generated any emissions for the last five 

years. With regard to an enforceable 

shutdown date, we do not consider it 

appropriate to require the shutdown of 

these units. As noted in our proposed 

rule, if Kilns 1–3 resume production, 

they should be re-evaluated for RP 

controls by ADEQ during the next 

regional haze planning period. 

Comment: Earthjustice disagreed with 

EPA’s rejection of SCR as a technically 

feasible control technology for Kiln 4. 

Earthjustice argued that the technology 

can be used on kilns, but it may require 

additional maintenance, which includes 

more frequent catalyst changes. 

Earthjustice stated that this can have an 

effect on the cost of controls, but 

because EPA did not conduct a cost 

analysis, the conclusion cannot be 

drawn that SCR is definitely not costeffective. Infeasibility due to cost should 

not have been equated with technical 

infeasibility, if that is what EPA has 

done. 

Response: We agree that SCR is 

technically feasible. As noted in our 

responses regarding to comments 

concerning PCC’s Clarkdale Plant, we 


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228See TSD at 92–93. 

wish to clarify that although SCR was 

not considered after Step 2 of the RP 

analysis, we consider SCR to be a 

technically feasible control option. 

While we explicitly eliminated other 

control options (such as Mixing Air 

Technologies) in Step 2 as being 

technically infeasible, we elected to not 

further consider SCR further due to a 

lack of information that would allow us 

to evaluate its effectiveness and cost on 

cement plants. In particular, we note 

that SCR has not been commercially 

applied to a cement plant of any type in 

the United States and there is little 

information available about its use on 

cement kilns in other countries.228

Thus, we lack sufficient information to 

conduct a four-factor analysis for SCR 

on cement kilns. 

Comment: Earthjustice argued that 

EPA has not provided adequate support 

for the proposed 50 percent NOX

reduction at Kiln 4 using SNCR. 

Earthjustice acknowledged the existence 

of Table IV.B–7 in the TSD showing 

SNCR NOX control efficiencies from 

different sources, but indicated that it 

could not tell based on the cited sources 

in that table that the test results would 

limit the control efficiency to 50 percent 

for Kiln 4 as well. Earthjustice indicated 

that SNCR performance is site-specific 

and can be optimized. Earthjustice said 

that the injection of ammonia or urea 

into an exhaust gas stream under certain 

conditions can reduce NOX emissions 

significantly, but that the temperature 

range is important because at 

temperatures beyond a certain range, the 

reagent can oxidize to create NO, 

thereby increasing NOX emissions. On 

the other hand, if the temperature is 

below a certain temperature range, the 

reaction rate is too slow for completion 

and the source might emit unreacted 

agent. 

Reemphasizing the fact that the 

control efficiency of SNCR is variable 

and dependent on installation-specific 

variables, Earthjustice argued that it is 

possible to achieve NOX reductions of 

90 percent at cement kilns. Therefore, 

Earthjustice urged EPA to reconsider the 

50 percent level of control and consider 

raising the control efficiency for Kiln 4 

at Rillito. By contrast, NPS indicated 

that it agreed with EPA’s estimate of 50 

percent control efficiency for SNCR and 

believed this level of control is 

supported by estimates of 50 percent at 

similar kilns. 

Response: We disagree that a 50 

percent control efficiency estimate for 

SNCR is too low for the reasons 

provided in response to similar 

comments regarding PCC’s Clarkdale 

Plant. In addition, in our proposed rule, 

we solicited comment regarding SNCR 

control efficiency on Kiln 4, and stated 

that if we receive additional information 

or data providing more site-specific 

information that justifies a different 

control efficiency at the Rillito Plant, we 

would revise our analysis accordingly. 

As noted later in our responses, CPC 

provided information regarding the 

design and operation of Kiln 4, and 

stated that only a 35 percent control 

efficiency was achievable. As described 

in greater detail below, we agree that 35 

percent reflects an appropriate estimate 

of the degree of control achievable with 

SNCR at Kiln 4, and have revised our 

cost analysis to reflect a 35 percent 

control efficiency at Kiln 4. 

However, in response to concerns 

raised by Earthjustice and in order to 

ensure that performance of the SNCR 

system installed at Kiln 4 is optimized, 

we are including in the final rule a 

series of control technology 

demonstration requirements. In 

particular, CPC is required to prepare 

and submit to EPA: (1) A design report 

describing the design of the ammonia 

injection system to be installed as part 

of the SNCR system; (2) data collected 

during a baseline period; (3) an 

optimization protocol; (4) data collected 

during an optimization period; (5) an 

optimization report establishing 

optimized operating parameters; and (6) 

a demonstration report including data 

collected during a demonstration 

period. While this type of control 

technology demonstration is not 

typically required as part of a regional 

haze plan, we consider it to be 

appropriate here, given the significant 

variability in control efficiencies 

achievable with SNCR at cement kilns. 

Based upon the data collected, EPA may 

revise the lb/ton emission limit in a 

future notice and comment rulemaking 

action. 

Comment: CPC stated that the 

proposed FIP’s estimate of 50 percent 

control of NOX emissions using SNCR 

on Kiln 4 is inaccurate because it is 

based on feasibility studies at four other 

cement plants and data collection from 

an optimization protocol at CPC’s 

Mojave cement plant. CPC asserted that 

for each of the four plants, the TSD 

incorrectly characterized them in Table 

IV.B–9 as ‘‘a preheater/precalciner 

operating with existing combustion 

controls.’’ According to the commenter, 

the Holcim Trident and Ash Grove 

Montana plants are long-wet kilns, 

which have fundamentally different 

combustion characteristics and emission 

profiles. 

CPC added that, while initially 

estimating 30 percent control 

effectiveness for SNCR at Kiln 4, it had 

refined its analysis and determined that 

35 percent control efficiency may be 

achievable, based on the data observed 

at Mojave and CPC’s engineering 

judgment that accounts for the sitespecific differences between the two 

kilns. 

CPC stated that a critical difference 

between Kiln 4 and Mojave is that 

potential ammonia injection points at 

Kiln 4 are not within the optimum 

temperature range of 1,600 °F to 

l,900 °F. Moreover, CPC continued, 

because potential injection points at 

Kiln 4 are below the optimum 

temperature range, NOX reduction 

reactions will be much slower, leading 

to less reduction of NOX emissions. 

Another critical difference, according to 

CPC, is Kiln 4’s unique modified loop 

calciner, which, due to its design, is less 

efficient at mixing exhaust gases and 

reagent than a cyclonic precalciner, 

such as the one at Mojave. CPC asserted 

that the inferior mixing in Kiln 4’s 

modified loop calciner will impede the 

ability of the SNCR reactions to reduce 

NOX concentrations. In addition, CPC 

stated that fuel combustion is less 

efficient in a modified loop calciner, 

which leads to significantly higher 

carbon monoxide (CO) and lower 

oxygen concentrations in Kiln 4’s 

exhaust when compared to Mojave. Kiln 

4 CO emissions are approximately ten 

times higher than at Mojave. CPC 

concluded that, collectively, these 

factors will reduce the potential NOX

control efficiency to no more than 35 

percent for Kiln 4. 

Response: In its ‘‘Reasonable Progress 

Analysis for CalPortland Company 

Rillito Cement Plant Kilns’’ dated May 

2013, CPC estimated a 30 percent NOX

control efficiency, based in part on an 

SNCR optimization report for CPC’s 

Mojave Plant in California. Emission 

data from this report, which CPC 

submitted to EPA on August 30, 2013, 

indicated a range of SNCR control 

efficiency of 30 to 60 percent at the 

Mojave Plant, depending upon 

operating parameters. Based on this 

information, and given the range of 

SNCR performance indicated from the 

first six months of Mojave Plant 

optimization protocol collection, we 

stated that the use of a 50 percent 

control efficiency for SNCR was 

appropriate for Kiln 4. We also noted 

that, if we received additional 

information or data providing more sitespecific information that justified a 

different control efficiency at the Rillito 

Plant, we would revise our analysis 

accordingly. 

As part of its comments on the 

proposed FIP, CPC submitted to EPA a 


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229See 79 FR 9352. 

230TSD page 98, table IV.B–12 

231The commenter cited the last paragraph on 

page 99 of EPA’s TSD (EPA–R09–OR–2013–0588– 

0009). 

232 42 U.S.C. 7602(k), 40 CFR 51.100(z). 

document entitled ‘‘Evaluation of EPA’s 

Reasonable Progress Analysis for Kiln 4 

at CalPortland Company’s Rillito 

Cement Plant dated March 2014,’’ 

which, among other things, provided 

further information on the NOX control 

efficiency that is assumed for applying 

SNCR to Kiln 4. This evaluation 

provided differences between Kiln 4 at 

the Rillito Plant and the cement kiln at 

the Mojave Plant that could lead to a 

lower NOX control efficiency when 

applying SNCR to Kiln 4. 

CPC stated that because of these 

differences, the SNCR NOX control 

efficiencies obtained for the cement kiln 

at the Mojave Plant cannot be applied to 

Kiln 4 at Rillito. In addition to the 

differences cited above, CPC also stated 

in its March 2014 report that the 

emission data from the Mojave Plant are 

highly variable (due to the operational 

variability that is part of the 

optimization), and CPC has not 

determined what control efficiency or 

emission rate is appropriate to use as 

the basis for an emission limit for the 

Mojave Plant. Based on considered 

engineering judgment, CPC proposed 

that a 35 percent NOX control efficiency 

would be an appropriate estimate for 

Kiln 4. Because we agree with the 

analysis in CPC’s report, we are revising 

our analysis based on a 35 percent NOX

control efficiency for SNCR at Kiln 4. In 

addition, as explained above, we are 

including in the final rule a series of 

control technology demonstration 

requirements to ensure that performance 

of the SNCR system installed at Kiln 4 

is optimized. 

In our proposed rule, we proposed a 

50 percent NOX control efficiency using 

SNCR, with a corresponding emission 

limit of 2.05 lb/ton of clinker produced 

and a cost-effectiveness of $1,047/ton. A 

35 percent control efficiency would 

result in a NOX emission limit of 2.67 

lb/ton of clinker produced and a costeffectiveness of $1,850/ton. We consider 

$1,850/ton to be very cost-effective. 

Comment: CPC stated that EPA 

should revise the proposed rolling 30- 

day emission limit for Kiln 4 to reflect 

more recent emissions data and 35 

percent control efficiency for SNCR. 

CPC stated that the TSD for the 

proposed rule references an annual 

design value of 2.05 lb NOX/ton clinker 

based on a pre-control emission rate 

estimate of 4.10 lb/ton, which omits 

data for 2011 and 2012. According to 

CPC, a six-year average based on the 

2007 to 2012 time period yields a precontrol emission rate of 4.62 lb/ton. 

Over the 2009 to 2012 time period, the 

annual average emission rate has been 

5.15 lb/ton. 

CPC also stated that emission limits 

must account for changes in production 

rates that are a function of market forces 

beyond the company’s control. CPC said 

that, to be achievable, any emission 

limit imposed must account for the 

inherently higher emission rates that 

occur during periods of reduced 

production. CPC stated that if an 

emission limit is based on 50 percent 

control efficiency and that level of 

control is not achievable, then the 

company will be at risk of an 

enforcement action, third party claim, 

and/or plant shutdown for failing to 

meet an unachievable standard. 

Response: As noted above, we agree 

that 35 percent reflects an appropriate 

estimate of the degree of control 

achievable with SNCR at Kiln 4. 

Accordingly we are revising the 30-day 

rolling average for the NOX emission 

limit at Kiln 4 from 2.05 lb/ton of 

clinker to 2.67 lb/ton of clinker. In 

addition, as explained above, we are 

including in the final rule a series of 

control technology demonstration 

requirements to ensure that performance 

of the SNCR system installed at Kiln 4 

is optimized. If the data collected 

pursuant to these control demonstration 

requirements indicate that a different 

control efficiency is appropriate for this 

kiln, EPA may revise the lb/ton limit in 

a future notice-and-comment 

rulemaking action. 

We do not agree that the lb/ton 

emission limit should be based solely 

on periods of reduced production. Such 

an approach does not ensure that the 

facility would achieve fully effective 

emission control during periods of full 

production, which exhibit lower lb/ton 

values. Conversely, a lb/ton limit based 

solely upon periods of full production 

would result in a low lb/ton value that 

may not be achievable during periods of 

reduced production. Although our 

baseline period did not include the most 

recent two years of data, it did 

incorporate emission data from periods 

of both full operation and reduced 

operation. As a result, we consider it to 

be a reasonable representation of 

baseline emissions. Therefore, we are 

not revising this value. 

Comment: CPC stated that because 

Kiln 4 does not cause or contribute to 

visibility impairment, a source specific 

four-factor reasonable progress analysis 

was not necessary or appropriate. The 

commenter asserted that EPA, in its 

final partial approval/disapproval of the 

Arizona RH SIP, stated ‘‘We are 

approving Arizona’s BART threshold of 

0.5 dv and its determination that West 

Phoenix Power Plant and the Rillito 

Cement Plant are not subject to BART.’’ 

Thus, the commenter argued that if a 

facility was not required to undergo a 

five-factor BART analysis, it follows that 

the facility should not be required to 

undergo a similarly burdensome 

reasonable progress analysis either. 

Response: We disagree that exemption 

from BART automatically exempts a 

facility from control for purposes of 

reasonable progress under the RHR. In 

this instance, EPA approved Arizona’s 

determination to exempt Kiln 4 at the 

Rillito Plant from BART, but 

disapproved the State’s reasonable 

progress analysis for point sources of 

NOX. As part of our own analysis of 

point sources of NOX, we identified the 

Rillito Plant as a potentially affected 

source because it had a Q/D value of 

726, more than 70 times the threshold 

value of 10.229 Furthermore, our 

modeling indicates that the plant causes 

visibility impairment at Saguaro 

National Park, where it has a baseline 

impact of 1.26 dv from all four kilns.230

Therefore, we determined that a sourcespecific four-factor analysis was 

appropriate. 

Comment: Earthjustice was not 

supportive of revising the 30-day 

average emission limit in order to 

accommodate startup and shutdown 

events. Earthjustice indicated that there 

is insufficient evidence in the record 

documenting the analysis referenced in 

the TSD 231 where EPA indicates it 

looked at emission factors over 2008 to 

2011 for other preheater/precalciner 

kilns. Further, Earthjustice also 

questioned whether the data that EPA 

examined was with or without SNCR. In 

Earthjustice’s opinion, if the data 

represented uncontrolled emissions, the 

variability would not remain the same 

after the installation of SNCR. 

According to Earthjustice, proper 

controls have the effect of reducing 

variability. Therefore, Earthjustice did 

not believe that the proposed 30 percent 

upward revision to the 30-day average 

was warranted or sufficiently 

documented in the record. 

Response: As noted in our response to 

a similar comment for PCC’s Clarkdale 

Plant, under the CAA and EPA’s 

implementing regulations, an ‘‘emission 

limitation’’ is defined as a requirement 

which limits the quantity, rate, or 

concentration of emissions of air 

pollutants on a continuous basis.232

Thus, the emission limits established in 

the FIP apply at all times, including 

periods of startup, shutdown, and 


emcdonald on DSK67QTVN1PROD with RULES2
52464 Federal Register / Vol. 79, No. 170 / Wednesday, September 3, 2014 / Rules and Regulations 

233See spreadsheet labeled ‘‘E–45—TEP Sundt4 

2001–12 Emission Calcs 2014–01–24’’.xlsx’’. 

malfunction. Malfunctions are, by 

definition, unforeseeable, and cannot be 

accounted for in setting emission 

limitations. By contrast, startup and 

shutdown are part of normal operations 

and emissions occurring during startup 

and shutdown must be accounted for 

when establishing emission limits. 

As discussed in our proposed rule, 

the 30 percent upward revision was 

based upon an examination of daily 

emissions (lbs) and production (tons 

clinker) data over a multi-year period 

for cement kilns (operating without 

SNCR) in which we identified the 

highest rolling 30-day emission rate and 

the highest annual average emission 

rate, and examined the difference 

between these values. A similar 

approach was used to develop the 

rolling 30-day emission limits for TEP 

Sundt Unit 4, and a copy of the 

emission data was included in the 

docket.233 Unlike the emission data for 

Sundt Unit 4, which is publicly 

available from EPA’s CAMD Acid Rain 

database, the data set we examined for 

the cement kilns contains daily 

production data that is considered CBI, 

which we are prohibited from making 

available for public review. The 

methodology we applied in developing 

the 30-day emission rate for the cement 

plants, however, is the same as the 

methodology documented for Sundt 

Unit 4, which is available for public 

review. While there might be alternative 

methods to account for these emissions 

than the approach we adopted, we did 

not receive any comments describing 

any alternative or more refined 

approaches for addressing this issue. 

Accordingly, we have retained this 

methodology in establishing the 

emission limit in the final rule. 

Comment: ADEQ said that, given the 

difficulty of retrofitting Kiln 4 with 

SNCR, more time is necessary to 

demonstrate compliance. ADEQ said 

that the three-year compliance time 

frame is not sufficient. By contrast, 

Earthjustice asserted that the 

compliance deadline should be 

shortened to one year. 

Response: As noted in a response to 

a similar comment on PCC’s Clarkdale 

Plant, unlike BART controls, which 

must be installed as expeditiously as 

practicable, RP controls are not subject 

to any particular compliance deadlines 

under the CAA and RHR, other than the 

overarching requirement to achieve 

reasonable progress during each 

planning period. CPC has indicated that 

it needs until the end of the first 

planning period that ends on December 

31, 2018, to comply with any 

requirements of the FIP. While it may be 

technically feasible for the plant to 

install SNCR before that date, we 

consider it within our discretion and 

reasonable in this instance to provide 

the facility until December 31, 2018. 

Comment: Earthjustice responded to 

EPA’s request for comments on whether 

a NOX emission cap should be set for 

the Rillito Plant. Earthjustice did not 

understand how EPA arrived at the 

proposed cap level and argued that the 

level is not commensurate with actual 

emissions data. The proposed level of 

2,082 tpy would allow minimal to no 

control of NOX at the plant, assuming 

that Kilns 1–3 do not operate. Therefore, 

Earthjustice asserted that it is 

unreasonable to propose a cap without 

a guarantee that the older kilns will 

permanently cease operation because 

this could mean no control at all for 

Kiln 4. Earthjustice suggested that the 

combination of a unit-specific massbased emission limit (e.g., ton/year or 

ton/day) and process-based limits (e.g., 

lb/ton clinker) might be reasonable in 

some situations, but Earthjustice 

indicated that it is does not support the 

proposed cap. 

CPC also expressed opposition to the 

annual emission cap. CPC stated that 

the proposed alternative NOX emissions 

cap would require the permanent 

shutdown of Kilns 1–3, as installing 

SNCR on Kiln 4 would not be sufficient 

to meet the cap if the other kilns were 

operating. CPC noted that when Kilns 

1–3 operate at full capacity, NOX

emissions from them exceed 1,900 tpy, 

so an annual cap of 2,082 tpy would 

require Kiln 4 to reduce emissions to 

around 150 tpy, which is more than a 

90 percent reduction from current 

emission levels. CPC asserted that, 

because 90 percent control efficiency is 

not possible with SNCR, the only way 

it could meet this annual limit would be 

to permanently shut down at least two, 

and perhaps all three, of its smaller 

kilns. 

Response: As noted in a response to 

a similar comment regarding PCC’s 

Clarkdale Plant, the RHR does not 

preclude the establishment of an annual 

emission cap for the purposes of 

achieving emission reductions for 

reasonable progress. However, 

considering the issues raised by 

commenters, and the multi-unit nature 

of the proposed annual emission cap, 

we are not including the option of an 

annual emission cap for the Rillito Plant 

in the final rule. 

Comment: CPC stated that the 

visibility modeling for Kiln 4 contains 

some errors and unsupported 

assumptions, leading to an overestimate 

of the visibility benefit due to SNCR, 

including assuming 50 percent control 

and inaccurately assuming constant 

background ammonia levels. CPC 

asserted that because modeling results 

are highly sensitive to the estimated 

ammonia value, the assumption of 1 

ppb for winter greatly overestimates 

NOX effects on regional haze. CPC stated 

that EPA used monthly background 

ammonia concentrations in the visibility 

modeling for the recently adopted 

Wyoming RH FIP and should do the 

same here given the available and 

representative monitoring data from the 

Chiricahua monitoring station, located 

less than 200 km from the Rillito Plant. 

CPC also asserted that EPA’s visibility 

modeling for Kiln 4 contains the 

following errors: 

(1) The stack parameters in the 

worksheet labeled ‘‘Stack Parameters’’ 

are the parameters for Kiln 6 that was 

proposed for construction at the Rillito 

Cement Plant to replace Kilns I–4, but 

has not been constructed. 

(2) EPA’s contractor assumed a 

geometric mean diameter for coarse 

particulate matter of 0.48 microns in its 

CALPUFF modeling. Because coarse 

particles are larger than 2.5 microns in 

diameter, CPC’s technical consultant, 

AECOM, assumed a geometric mean 

diameter of 6 microns. 

(3) EPA’s subcontractor used nondefault minimum turbulence velocities 

sigma-v (SVMIN) and sigma-w (SWMIN) 

for each stability class over land and 

over water of 0.5 meter/second (m/s). 

According to comments in the 

subcontractor’s CALPUFF modeling 

files, using the default values produced 

an error message. The only way to 

bypass the error and run the model to 

completion was to set SVMIN and 

SWMIN to 0.5 m/s. AECOM used the 

default values without encountering 

errors from CALPUFF. 

Finally, CPC stated that AECOM reran 

the visibility modeling analysis using 

corrected and supportable inputs, 

demonstrating that the maximum 

visibility benefit from installing SNCR 

on Kiln 4 would be 0.15 dv, 

approximately seven times less than the 

human eye can detect. Citing the DC 

Circuit’s decision in American Corn 

Growers, CPC stated that a source 

should not be required to spend 

millions of dollars for imperceptible 

visibility improvements. 

Response: We partially agree with this 

comment. As explained above, we agree 

with CPC’s assertion that a control 

efficiency of 35 percent is more 

appropriate for SNCR at Kiln 4 than our 

proposed efficiency of 50 percent. 

However, we do not agree that our use 

of the IQAQM default for background 


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Federal Register / Vol. 79, No. 170 / Wednesday, September 3, 2014 / Rules and Regulations 52465 

234Memorandum in docket, ‘‘Full Technical 

Response to Modeling Comments for June 2014 

Final Arizona Regional Haze FIP (Phase III),’’ Colleen McKaughan and Scott Bohning, EPA, June 

16, 2014. 

ammonia of 1.0 ppb was improper. As 

explained in our response to comments 

from TEP on the BART determination 

for Sundt Unit 4, given the uncertainty 

and variability in ammonia values 

measured in Arizona, we consider the 

1.0 ppb IWAQM default to be the most 

appropriate value to use here.234

We agree that we used the incorrect 

stack parameters. However, because 

these parameters have varying impacts 

on visibility benefits, this error had little 

effect overall. In particular, the lower 

stack height and smaller stack diameter 

tend to increase baseline visibility 

impacts and the visibility improvements 

due to controls, whereas the higher 

stack exit velocity and higher exit 

temperature tend to decrease visibility 

impacts and control benefits. 

Similarly, the changes related to 

particle diameters have little effect on 

the modeling results because PM 

contributes only a few percent to the 

modeled visibility impacts. The changes 

related to default minimum turbulence 

velocities would tend to increase 

slightly atmospheric mixing and thus to 

reduce slightly pollution impacts and 

the benefit of controls. Overall, the 

effect of the changes to the modeling 

input parameter is much smaller than 

the change in SNCR control efficiency, 

and does not affect our control 

determination. 

While CPC’s comment cites the 

results of AECOM’s modeling using 

variable ammonia background, AECOM 

also conducted modeling using constant 

1.0 ppb ammonia background. As 

explained above, we consider use of 

constant 1.0 ppb ammonia background 

to be the most appropriate approach and 

we agree with CPC’s other corrections to 

our contractor’s modeling. Therefore, 

we accept the results of CPC’s modeling 

using 1.0 ppb ammonia background as 

a generally reasonable estimate of 

visibility benefits expected from SNCR 

on Kiln 4. These results indicate that the 

benefit of SNCR at Kiln 4 would be 

somewhat less than EPA’s modeling 

showed. In particular, EPA’s modeling 

showed a benefit of 0.24 dv at Saguaro 

National Park, the area with the highest 

impact from Kiln 4, and a cumulative 

benefit over the 12 nearby Class I areas 

of 0.78 dv. By contrast, CPC’s modeling 

showed a benefit of 0.18 dv at Saguaro 

National Park and a cumulative 

improvement of 0.59 dv. 

Despite these decreased visibility 

benefits, EPA still considers SNCR to be 

reasonable for Kiln 4 for several reasons. 

First, as explained above, even with the 

revisions suggested by CPC in its 

comments, SNCR remains highly costeffective at $1,850/ton. Second, even 

though the visibility benefits from SNCR 

at Kiln 4 at the Rillito Plant are lower 

than those expected to result from 

controls on other sources addressed in 

this FIP, they are not negligible, and 

together with controls on other sources 

now and in the future will achieve 

progress in improving visibility at 

multiple Class I areas. In particular, we 

note that, according to CPC’s modeling, 

12 different Class I areas will be 

improved, including Galiuro WA, for 

which the expected improvement is 

0.16 dv, only slightly less than expected 

improvement of 0.18 dv at Saguaro 

National Park. Third, due to the close 

proximity of the Rillito Plant to the 

western unit of Saguaro National Park, 

there is significant uncertainty regarding 

the benefits of controls. In particular, 

EPA’s modeling indicated that the 

benefit of SNCR at the western unit of 

Saguaro National Park (0.30 dv) is 

greater than the benefit at the eastern 

unit (0.24 dv), if 100 percent conversion 

of NO to NO2 is assumed. EPA also 

conducted a sensitivity analysis to 

address the possibility that NOX emitted 

from the Rillito Plant is not 100 percent 

in the form of NO2. The results of this 

analysis are shown in Table 8. 

TABLE 8—VISIBILITY BENEFIT AT WESTERN SAGUARO NP FROM SNCR ON RILLITO CEMENT PLANT AS A FUNCTION OF

NO CONVERSION

NO to NO2 Conversion 

Conversion Rate 

10% 25% 50% 75% 100% 

Improvement (deciviews) ......................................................................... 0.03 0.05 0.15 0.22 0.30 

While we do not know for certain which 

of these scenarios is most realistic, it is 

worth noting that there also will be 

some benefit to the western unit of 

Saguaro, which is not directly reflected 

in the modeling provided by CPC. 

Finally, we disagree with CPC’s 

suggestion that human perceptibility of 

visibility improvement is a criterion for 

imposing controls for purposes of 

selecting source-specific controls for 

reasonable progress under the CAA and 

the RHR. No one control will be 

sufficient to achieve the visibility goals 

of the RHR. The effect of reasonable 

controls on the many contributing 

sources will cumulatively enable 

progress toward those goals. 

Comment: CPC asserted that the 

reasonable progress analysis for Kiln 4 

is inconsistent with EPA’s analyses of 

other sources. CPC included a table 

comparing the proposed FIP’s cost and 

visibility results for TEP Sundt Units 1– 

3 and CPC Rillito’s Kiln 4, and 

concluded that for about the same 

annual cost, emission controls at Sundt 

would have a much greater beneficial 

impact on visibility at Saguaro National 

Park. CPC stated that the only factor that 

could explain this differential treatment 

is the ‘‘cost/ton reduced’’ metric, which 

the FIP estimates is higher for TEP 

Sundt than Rillito, thus demonstrating 

the limitations of the cost/ton reduced 

metric. CPC further stated that the FIP 

should not rely on this metric, which 

provides no insight on whether controls 

are cost-effective for achieving RPGs by 

improving visibility, the sole potential 

justification for establishing controls. 

With respect to TEP Sundt Units 1–3, 

CPC stated that EPA concluded ‘‘the 

cost-effectiveness of ULNB is relatively 

high in light of the anticipated visibility 

benefit’’ and argued that because the 

costs are similar and the visibility 

benefits are even smaller, the same 

conclusion must be reached for Kiln 4. 

Concerning the reasonable progress 

analysis for El Paso’s facilities and Pima 

County’s Ina Road sewage plant, CPC 

included a table comparing the fourfactor analyses for those facilities and 

Kiln 4. CPC asserted that there is no 

explanation or justification to support 

the proposed decision to require 

controls on Kiln 4, but not on these 

other sources. CPC noted that the cost 

of compliance is higher for Kiln 4 than 

the other sources, the time needed to 

comply is longer, energy and non-air 

quality impacts are equivalent, and the 

remaining useful life is assumed to be 

identical. CPC asserted that because the 

four factors set forth in 40 CFR 


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52466 Federal Register / Vol. 79, No. 170 / Wednesday, September 3, 2014 / Rules and Regulations 

235Our cost analyses also incorporate 

consideration of two other statutory factors: 

Remaining useful life and energy and non-air 

environmental impacts. 236See 79 FR 9358. 237EPNG Comment Letter at 1–2. 

238See RP Guidance, section 5.1, note 23. 

239TSD for the Proposed Phase 3 FIP, January 27, 

2013, Page 19 of 233. 

240We also note that while NPS refers to ‘‘BART 

for Cholla Unit 1’’, Cholla Unit 1 is, in fact, not 

BART-eligible and therefore not subject to BART. 

See 78 FR 46145. 

241 I.e., BART has very specific applicability 

criteria, and is a ‘‘one-time’’ analysis that is only 

performed on affected sources during the first 

planning period. The procedure for identifying 

candidate sources for RP controls is not as specific, 

may have more or less expansive criteria than 

BART, and can be potentially performed each 

planning period. 

51.308(d)(l) cannot justify this 

differential treatment, the proposed FIP 

justifies the decision to not require 

controls on these other sources based on 

a factor that is not listed in 40 CFR 

51.308(d)(l), and stated that CPC should, 

and must, be treated equally, and no 

controls should be imposed during this 

first planning period. 

Response: We do not agree with this 

comment. The CAA and RHR provide 

considerable discretion in how the four 

RP factors are weighed. Moreover, while 

the CAA and RHR explicitly require 

consideration of visibility improvement 

in BART analyses, they do not require 

consideration of such benefits for 

individual RP sources. Therefore, while 

we have taken visibility benefits into 

account as a supplementary factor, we 

have not weighed them as heavily for 

RP as we have for BART. Rather, we 

have placed more emphasis on cost, 

which is one of the enumerated 

statutory factors for RP analyses.235

Accordingly, we do not agree with 

CPC’s suggestion that we should 

consider $/dv as more important than 

$/ton in evaluating potential RP 

controls. Even with CPC’s suggested 

modifications, the cost-effectiveness of 

SNCR at Kiln 4 ($1,850/ton) is two to 

four times less than the costeffectiveness of controls at Sundt Units 

1–3 ($4,400–$8,300/ton).236

Accordingly, we do not agree that we 

are treating these units inconsistently. 

With regard to El Paso’s Compressor 

Station and Pima County’s Ina Road 

sewage plant, we agree with the 

commenter that controls on these units 

would be more cost-effective than SNCR 

at Kiln 4, and that the results for the 

other three statutory factors are similar. 

However, we note that El Paso Natural 

Gas Company (EPNG) has asserted that 

EPA has underestimated the costs of 

compliance and time necessary for 

compliance.237 Furthermore, as 

explained in our proposal, natural-gas 

engines similar to those at these 

facilities are dispersed throughout the 

State and it is not practical for EPA to 

control these sources. By contrast, the 

Rillito Plant is a single discrete facility 

for which SNCR is a cost-effective and 

otherwise reasonable control option. We 

also note that, while we do not have 

visibility modeling to gauge the impacts 

of the other facilities cited by CPC, the 

Q/D value for the Rillito Plant (a rough 

gauge of potential for visibility 

impairment) is more than ten times the 

Q/D value for any of the other sources. 

Under these circumstances, we consider 

it reasonable to require SNCR at the 

Rillito Plant and not to require 

additional controls at the compressor 

stations or the sewage treatment plant. 

We strongly encourage the State to 

consider development of a statewide 

rule to regulate natural-gas engines in 

the next planning period. 

Comment: Arizona Rock Products 

Association expressed support for and 

incorporated by reference the comments 

of CPC and PCC. 

Response: We have responded to 

CPC’s and PCC’s comments above. 

C. Comments on Other Reasonable 

Progress NOX Point Sources 

Comment: NPS argued that SCR 

should be BART for APS Cholla Unit 1. 

NPS provided more details on the cost 

analysis for Cholla Unit 1, indicating 

that the calculated average and 

incremental cost-effectiveness values for 

SCR of $5,313/ton and $6,307/ton, 

respectively, are erroneously high. NPS 

noted that EPA’s calculation 

methodology relied heavily upon IPM, 

and suggested several revisions and 

corrections to EPA’s calculation that 

would have the effect of reducing the 

control costs. After applying the 

corrections, NPS concluded that an 

average cost-effectiveness of $5,263/ton 

is obtained which NPS considers to be 

reasonable. In addition, NPS provided 

its own set of cost calculations, relying 

primarily upon the cost equations 

contained in EPA’s CCM. NPS estimated 

that the average cost-effectiveness of 

SCR is $4,353/ton, which is less than 

the values established by several states 

and EPA. 

NPS also made similar comments 

about TEP Springerville Units 1 and 2. 

NPS asserted that EPA’s estimates of 

SCR cost-effectiveness of $6,829/ton for 

Unit 1 and $6,085/ton for Unit 2 are 

erroneously high, and therefore the 

incremental cost-effectiveness of SCR 

over SNCR of $8,606/ton and $7,416/

ton, respectively, are also too high. After 

applying the corrections discussed by 

NPS, average cost-effectiveness of 

$5,700 to $6,400/ton is obtained, which 

NPS considers to be reasonable. In 

addition, NPS provided its own cost 

calculations for Springerville Units 1 

and 2, relying primarily upon the cost 

equations contained in EPA’s CCM. NPS 

estimated that the average costeffectiveness of SCR is $5,688 to $6,377/ 

ton, which is less than the values 

established by several states and EPA 

for EGUs. Detailed calculations and 

analysis for Cholla Unit 1 and 

Springerville Units 1 and 2 are 

documented in Appendix C and E of 

NPS’s submittal. 

Response: We disagree with NPS’s 

assertion that our calculations, based on 

IPM methodology, are overestimates. 

The revisions indicated by NPS consist 

primarily of lower urea/ammonia and 

catalyst costs. NPS made similar 

assertions regarding ammonia and 

catalyst costs in our analysis for TEP 

Sundt Unit 4. As described in our 

responses to those comments, we 

consider the values we used for 

ammonia and catalyst costs appropriate. 

Regarding NPS’s cost calculations that 

use the cost equations from the CCM (as 

opposed to using the information 

contained in IPM), we note that nothing 

in the RHR requires use of the CCM for 

calculating the cost of compliance for 

RP sources. Moreover, while EPA’s RP 

Guidance recommends use of the CCM, 

it also allows for divergence from the 

CCM, provided that any difference from 

the CCM is documented.238 In this and 

other RH rulemakings, we have not 

required strict adherence to the study 

level cost equations contained in the 

CCM, and have developed cost 

calculations based on a number of 

supplemental sources including certain 

site-specific data provided by the 

facility, vendor quotes, and information 

from other EPA rulemakings. As noted 

in our proposed rule and TSD,239 IPM 

has been used by EPA in multiple 

regulatory actions, and we consider it an 

appropriate source of supplemental 

information. 

Regarding the use of cost-effectiveness 

thresholds, we note that the examples 

cited by NPS consist of BART 

determinations and not RP 

determinations.240 Given the differences 

between the BART factors and RP 

factors and the nature of the 

applicability criteria that would trigger 

BART and RP analyses,241 we do not 

necessarily consider the costeffectiveness and visibility benefit 

values from BART determinations to be 

directly comparable to RP analyses. 

Furthermore, the cost-effectiveness 

values that NPS finds reasonable are, in 

fact, higher than EPA has required for 


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242See, e.g. BART EGU FIP Summary. 

243National Parks Conservation Association, On 

an Approach for Improving Visibility in Class I 

Areas Using Visibility Restoration Plans (VRPs) 

with an Example VRP for the Grand Canyon 

National Park (2014). Exhibit 17 in Earthjustice’s 

comments. Hereafter ‘‘NPCA Report’’. 

244See 79 FR 9362, Tables 53 and 54. 

245NPCA Report, section C.2 at 10 (‘‘While we 

have currently accepted these findings for the 

purposes of developing the example VRP for the 

GCNP, the accuracy of these findings is 

questionable and a thorough analysis of the many 

emission inventories and modeling assumptions 

made in the WestJump study would be a necessary 

task in developing an actual VRP for any Class I 

area’’). 

246NPCA Report, Attachment B Development of 

Extinction Source Apportionment Data for the 

Visibility Restoration Plan, Particulate Matter 

Species Apportionment (‘‘The average 

apportionment during the highest ten daily-average 

PM2.5 concentrations was created for the six PM 

species corresponding to the six pollutants that 

account for the controllable contributions to Bext

(PMC, EC, NO3, SOA, SO4, and PM2.5)’’). 

any BART source during this planning 

period.242 While it may be necessary to 

require controls at this cost level for RP 

sources in future planning periods, we 

do not agree that this level of costeffectiveness is reasonable at this time, 

given the significant emission 

reductions already achieved by BART 

and RP determinations during this 

planning period (see Table 12). 

Comment: ADEQ expressed support 

for EPA’s determination that it is not 

practical to control compressor stations 

due to their dispersed locations. 

Similarly, the owner of Williams and 

Flagstaff Compressor Stations (EPNG) 

said that it agreed with EPA’s 

determination that it is not reasonable to 

require further controls at these two 

facilities. Even though EPNG supported 

EPA’s decision, EPNG did not agree that 

the control technology, cost of 

compliance, and time to comply used by 

EPA in its analysis are appropriate. 

Response: We acknowledge ADEQ’s 

and EPNG’s support on this issue. We 

note that our finding of impracticability 

with regard to the regulation of engines 

(including those found at compressor 

stations) only applies to regulation by 

EPA in this planning period. It does not 

apply to potential regulation by the 

State in future planning periods. Given 

the availability of cost-effective controls 

for these sources and the potential for 

significant emission reductions from a 

statewide rule applicable to such 

sources, we strongly encourage ADEQ to 

develop such a rule during the next 

planning period. We acknowledge the 

comments made by EPNG regarding our 

control technology analyses for the 

natural gas turbines, but have not 

revised our analysis at this time because 

it would not alter our determination not 

to control compressor stations at this 

time. 

Comment: TEP, the owner of the 

Sundt and Springerville facilities, 

agreed with EPA’s conclusion that 

additional controls are not required on 

Springerville Units 1 and 2 or Sundt 

Units 1–3 at this time. ADEQ similarly 

expressed support for the EPA’s 

decision not to require low-NOX burners 

for Sundt Units 1–3 because they are not 

cost-effective. TEP added that the same 

result would have been achieved if EPA 

had approved ADEQ’s identical 

determination. 

Response: We acknowledge TEP’s 

support on this issue. We agree that, 

with regard to TEP Sundt Unit 1–3, our 

determinations are identical to those 

made by ADEQ. However, we note that, 

unlike ADEQ, EPA conducted a fourfactor RP analysis for these units, as 

well as visibility modeling to evaluate 

potential visibility benefits, before 

concluding that no additional controls 

are reasonable at this time. 

Comment: The owner of Tucson 

Compressor Station (EPNG) indicated 

that that the facility is no longer 

operating and should therefore be 

removed from the FIP. 

Response: We appreciate the 

clarification. Our proposed FIP did not 

require any controls for this facility, so 

no revisions are needed. 

D. Comments on Area Sources of NOX

and SO2

Comment: Earthjustice argued that 

area sources should also be required to 

install reasonable progress controls. 

Earthjustice referred to an NPCA 

Report 243 that shows how Visibility 

Restoration Plans can help ensure that 

Class I areas achieve the glide path by 

2064. The report indicated that 

Arizona’s area sources are the largest 

contributors to visibility impairment at 

the Grand Canyon. Earthjustice noted 

that EPA looked at reasonable progress 

controls for area sources, but classified 

its analysis as ‘‘limited in scope.’’ 

Earthjustice explained that EPA 

identified the area source categories 

contributing the most to visibility 

impairment, but performed only a brief 

analysis because the inventories that 

were analyzed did not contain sufficient 

data (e.g., on the number, age, and 

design of the actual area sources). In 

Earthjustice’s opinion, in order to 

conduct a thorough reasonable progress 

analysis in this case where there was 

limited information available, EPA 

should have obtained the data necessary 

to conduct a proper analysis. Further, 

Earthjustice said that the justification 

for no further controls based on no other 

regional haze SIP or FIP requiring 

controls on such sources primarily to 

ensure reasonable progress is not 

sufficient, because no other state had 

RPGs as poor as Arizona’s. 

Earthjustice highlighted the Visibility 

Restoration Plan that was submitted 

with the Earthjustice’s public comments 

as a tool to help EPA in identifying 

other sources that impact visibility, and 

should be evaluated for reasonable 

progress controls. According to 

Earthjustice, the Visibility Restoration 

Plan could also be a helpful tool to the 

Agency by illustrating how a long-term 

strategy based on existing data can be 

developed to restore visibility by 2064. 

In Earthjustice’s opinion, if the plan is 

adopted, this would assist states and 

EPA to implement the goals of the haze 

program’s reasonable progress mandate. 

Response: We do not agree that 

additional area source controls are 

reasonable for this planning period. 

According to our analysis, Arizona’s 

area sources are typically the smallest 

contributor to anthropogenic nitrate and 

sulfate pollution at Arizona’s Class I 

areas, including the Grand Canyon, 

where Arizona area sources contribute 

only 2.9 percent of the nitrate pollution 

and only 0.4 percent of the sulfate 

pollution.244 EPA’s analysis is based on 

source apportionment modeling 

conducted by the WRAP. As we note in 

the proposal, EPA has carefully 

evaluated that work and has determined 

it to be of sufficient quality to use in 

making policy decisions. 

The NPCA Report suggests that the 

contribution of Arizona’s area sources to 

haze at the Grand Canyon may be 

greater than indicated by our analysis. 

However, as acknowledged in the NPCA 

Report’s Visibility Restoration Plan 

(VRP), there are significant limitations 

in the data on which the VRP is 

based.245 Furthermore, the average 

apportionment provided in the VRP is 

based on the highest 10 daily-average 

PM2.5 concentrations,246 rather than the 

20 percent most impaired days and the 

20 percent least impaired days, on 

which RPGs are based. Therefore, the 

NPCA Report does not provide an 

adequate technical basis for revising our 

findings regarding the relative 

contribution of area sources at Arizona’s 

Class I areas. Accordingly, for the 

reasons described in our proposal, we 

conclude that it is not reasonable to 

require additional controls on Arizona’s 

area sources at this time. 

Comment: EPNG said that it agrees 

with EPA’s assessment that the potential 

visibility benefits from applying NOX

controls at natural gas compressor 

stations would be relatively small. 


emcdonald on DSK67QTVN1PROD with RULES2
52468 Federal Register / Vol. 79, No. 170 / Wednesday, September 3, 2014 / Rules and Regulations 

247 79 FR 9363. 

248 Id. 

249The State’s analysis included monitored data 

for 2000 through 2010, i.e. including several years 

after the 2000–2004 baseline, during which the 

effect of emission changes from new controls and 

other causes might be expected to manifest. We did 

not find the evidence for downward trends 

compelling, partly because the year to year 

variability was comparable to the claimed decreases 

in visibility impairment. 78 FR 29297. A portion of 

the State analysis attempted to explain some 

periods of anomalously high sulfate impairment, 

with back trajectories suggesting that they were due 

to out-of-State sources. The difficulty of this 

analysis illustrates why recent monitored trends by 

themselves are not a reliable basis for projecting 

progress, and why multistate photochemical 

modeling is needed. Unlike trend analysis, such 

modeling accounts for out-of-State and other 

sources, along with the varying meteorology and 

atmospheric chemistry conditions encountered by 

the pollution plumes from these sources. In any 

case, the State’s analysis and recent trend data do 

not provide us a basis for establishing numerical 

RPGs. 

250 77 FR 23988, 24053. 

251See 77 FR 31693, 31708. 

252 79 FR 2437. 

Response: We agree with this 

comment on a per-engine basis, but we 

strongly encourage the State to consider 

development of a statewide rule to 

regulate the categories of natural gas 

engines and sewage treatment plants in 

the next planning period. 

E. Comments on Reasonable Progress 

Goals and Uniform Rate of Progress 

Comment: Two commenters objected 

to the lack of numerical RPGs, 

expressed in deciviews, in EPA’s 

proposed FIP. CPC asserted that because 

EPA disapproved Arizona’s RPGs, EPA 

is required to establish its own RPGs, 

under 40 CFR 51.308(d). CPC noted that 

there is no statutory or regulatory 

provision that excuses compliance with 

51.308(d)(1) due to time and resource 

limitations. CPC added that EPA would 

not approve a SIP that did not include 

numerical RPGs. For these reasons, CPC 

asserted that the FIP cannot be approved 

as proposed. 

CPC also stated that there is no 

statutory or regulatory support for EPA’s 

assertion that emission limitations are 

more critical components of an RH plan 

than RPGs. CPC stated that establishing 

RPGs, not emission limits, is the first 

‘‘core requirement’’ listed in 51.308(d), 

and that other components, including 

emission limits established as part of an 

LTS, must be developed in 

consideration of RPGs. 

CPC stated that future RH plans will 

be unable to comply with 40 CFR 

51.308(f), (g), and (h) unless numerical 

RPGs are established now. Citing 40 

CFR 51.308(f)(2) and (3), CPC noted that 

Arizona must evaluate the effectiveness 

of its LTS for achieving RPGs and affirm 

or revise its RPGs as part of the next 10- 

year RH SIP. CPC also noted that 

Arizona must submit a report to the 

Administrator every five years 

evaluating progress toward RPGs. CPC 

stated that such provisions are 

predicated on the establishment of 

numerical RPGs and that without this, 

the proposed FIP does not comply with 

the RHR today and prevents Arizona 

from complying with the RHR in the 

future. 

Earthjustice also asserted that EPA 

should quantify its RPGs. Earthjustice 

stated that EPA’s contention that it has 

limited time and resources to conduct 

this task is not justified because Arizona 

completed its analysis within months of 

EPA’s request. Earthjustice further 

pointed out that EPA did analysis to 

determine RPGs in other haze FIPs, such 

as Hawaii and Montana. Earthjustice 

also found EPA’s claim of insufficient 

time and resources weak considering 

the multiple extensions it has received 

on the consent decree deadlines to 

complete the FIP. Therefore, 

Earthjustice asserted that EPA’s claim is 

not warranted and the Agency should 

have conducted this critical analysis. 

Earthjustice strongly urged EPA to 

conduct this analysis during this 

rulemaking to meet the RHR 

requirements and for the purpose of 

identifying emission reductions needed 

for future planning periods. Earthjustice 

contended that EPA and the public must 

have this information available in order 

to determine how progress will be made 

and how reasonable EPA’s plan is. 

Response: We agree that, having 

disapproved Arizona’s RPGs, EPA is 

required to establish new RPGs under 

40 CFR 51.308(d). Therefore, we 

proposed non-quantified RPGs 

consistent with the combination of 

approved control measures in the 

Arizona RH SIP, the Phase 1 RH FIP, 

and the proposed Phase 3 RH FIP.247 We 

explained that ‘‘[w]hile 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.’’ 248 The commenters 

underestimate the difficulty and time 

required for this task. While Earthjustice 

points to the effort of Arizona to provide 

for new RPGs, the State’s effort was 

based on an extrapolation of historical 

monitoring trends into the future 

without any evaluation of whether these 

trends could reasonably be expected to 

continue through 2018.249 Further, the 

RPGs that EPA promulgated for Hawaii 

and Montana are not directly 

comparable to the situation in Arizona. 

For Montana, EPA relied on WRAP 

modeling to set RPGs without updating 

the modeling to reflect additional 

controls included in the FIP.250 For 

Hawaii, EPA employed unique, islandspecific emission inventories to develop 

RPGs.251

Development of more refined 

numerical RPGs for each of Arizona’s 12 

Class 1 would require photochemical 

grid modeling of a multistate area, 

involving thousands of emission 

sources, unlike the comparatively 

simple single-source CALPUFF 

modeling used for individual BART 

assessments. In order to accurately 

reflect all emissions reductions 

expected to occur during this planning 

period, the new modeling would require 

an update of the emissions inventory for 

Arizona and the surrounding states to 

include not just the actions under this 

FIP, but all EPA and state regulatory 

actions on point, area, and mobile 

sources. After the inventory is 

developed and reviewed by the affected 

states for accuracy, it must be converted 

to a model-ready format before air 

quality modeling can be used to 

estimate the future visibility levels at 

the Class I areas.252 This modeling 

would require specialized and extensive 

computing hardware and expertise. 

Developing all of the necessary input 

files, running the photochemical model, 

and post-processing the model outputs 

would take several months at a 

minimum. Finally, the specific controls 

we are requiring that would be inputs to 

the modeling changed from the proposal 

as a result of comments and 

supplemental information received from 

the affected facilities and other 

commenters. Some of these changes 

occurred only shortly before the 

deadline for this action, leaving 

insufficient time for the extensive 

modeling effort required to develop new 

RPGs based on photochemical 

modeling. Therefore, we were unable to 

conduct additional modeling to quantify 

the degree of progress that we expect to 

result from this new combination of 

controls. 

Nonetheless, in order to provide RPGs 

that account for emission reductions 

from the FIP controls, we have used a 

method similar to the one that we used 

in our FIP for Hawaii, which is based on 

a scaling of visibility extinction 

components in proportion to emission 

changes. To determine the RPGs, we 

started with the 2018 projection of 

extinction components from the 

WRAP’s CMAQ photochemical 

modeling of WRAP emissions scenario 

PRP18b (‘‘Preliminary Reasonable 

Progress for 2018, version b’’). This 


emcdonald on DSK67QTVN1PROD with RULES2
Federal Register / Vol. 79, No. 170 / Wednesday, September 3, 2014 / Rules and Regulations 52469 

253 ‘‘Simulation Specification for 2018 

Preliminary Reasonable Progress Simulation 

version B’’, WRAP Regional Modeling Center, 

August 11, 2009. Available at WRAP Regional 

Modeling Center Visibility Modeling Results Web 

page http://pah.cert.ucr.edu/aqm/308/cmaq.shtml. 

254We assumed that the relevant inventory is the 

emissions in Arizona and all of its neighboring 

states. 

255Additional details of the calculation are 

available in a spreadsheet in the docket, FIP_RPG_

estimates.xlsx. 

CMAQ PRP18b emission scenario 

included the results of State BART 

determinations and other SIP controls, 

as well as projected emissions from 

other point, area, and mobile sources.253

We scaled the modeled visibility 

extinction components for sulfate (SO4) 

and nitrate (NO3) in proportion to the 

FIP’s emission reductions for SO2 and 

NOX, respectively. The sulfate scaling 

factor was the CMAQ PRP18b SO2

emissions with FIP controls for BART 

and RP sources in place, divided by the 

original CMAQ PRP18b SO2

emissions.254 We conducted the same 

scaling exercise with nitrate and NOX. 

The scaled sulfate and nitrate 

extinctions were added to the unscaled 

extinctions for organic mass and other 

components to get total extinction, and 

then this was used to calculate post-FIP 

RPGs in deciviews.255 The results of this 

analysis are shown in Tables 9 and 10. 

TABLE 9—REASONABLE PROGRESS GOALS FOR 20 PERCENT WORST DAYS

[In deciviews] 

Code Class I 

area 

IMPROVE 

monitor 

code 

2000–2004 

baseline 

2064 natural 

conditions 2018 URP 

2018 

projection 

by WRAP 

FIP effect FIP 2018 

RPG 

Years to 

reach natural 

conditions 

chir ........... Chiricahua 

NM.

CHIR1 ...... 13.43 7.20 11.98 13.35 -0.16 13.19 367 

chrw ......... Chiricahua 

WA.

CHIR1 ...... 13.43 7.20 11.98 13.35 -0.16 13.19 367 

gali ........... Galiuro 

WA.

CHIR1 ...... 13.43 7.20 11.98 13.35 -0.16 13.19 367 

grca .......... Grand 

Canyon 

NP.

GRCA2 .... 11.66 7.04 10.58 11.14 -0.11 11.02 101 

maza ........ Mazatzal 

WA.

IKBA1 ...... 13.35 6.68 11.79 12.76 -0.13 12.63 131 

moba ........ Mount 

Baldy 

WA.

BALD1 ..... 11.95 6.24 10.62 11.52 -0.13 11.40 141 

pefo .......... Petrified 

Forest 

NP.

PEFO1 ..... 13.21 6.49 11.64 12.76 -0.12 12.64 165 

pimo ......... Pine 

Mountain 

WA.

IKBA1 ...... 13.35 6.68 11.79 12.76 -0.13 12.63 131 

sagu ......... Saguaro 

NP East.

SAGU1 .... 14.83 6.46 12.88 14.82 -0.13 14.68 767 

sagu ......... Saguaro 

NP West.

SAWE1 .... 16.22 6.24 13.90 15.99 -0.12 15.87 397 

sian .......... Sierra 

Ancha 

WA.

SIAN1 ...... 13.67 6.59 12.02 13.17 -0.12 13.05 159 

supe ......... Superstition 

WA.

TONT1 ..... 14.16 6.61 12.40 13.85 -0.13 13.72 237 

syca .......... Sycamore 

Canyon 

WA.

SYCA1 ..... 15.25 6.65 13.25 15.00 -0.08 14.92 360 

TABLE 10—REASONABLE PROGRESS GOALS FOR 20 PERCENT BEST DAYS

[In deciviews] 

Code Class I area 

IMPROVE 

monitor 

code 

2000–2004 

baseline 

2064 natural 

conditions 

2018 

projection 

by WRAP 

FIP effect FIP 2018 

RPG Degradation? 

chir ....................... Chiricahua NM ..... CHIR1 ...... 4.91 1.83 4.90 -0.12 4.77 No.

chrw ..................... Chiricahua WA ..... CHIR1 ...... 4.91 1.83 4.90 -0.12 4.77 No.

gali ....................... Galiuro WA .......... CHIR1 ...... 4.91 1.83 4.90 -0.12 4.77 No.

grca ...................... Grand Canyon NP GRCA2 .... 2.16 0.31 2.12 -0.10 2.02 No.

maza .................... Mazatzal WA ....... IKBA1 ...... 5.40 1.91 5.17 -0.11 5.07 No.

moba .................... Mount Baldy WA .. BALD1 ..... 2.98 0.51 2.86 -0.10 2.76 No.

pefo ...................... Petrified Forest 

NP.

PEFO1 ..... 5.02 1.07 4.73 -0.11 4.62 No.

pimo ..................... Pine Mountain WA IKBA1 ...... 5.40 1.91 5.17 -0.11 5.07 No.

sagu ..................... Saguaro NP East SAGU1 .... 6.94 2.23 7.04 -0.11 6.93 No.

sagu ..................... Saguaro NP West SAWE1 .... 8.58 2.50 8.34 -0.11 8.23 No.


emcdonald on DSK67QTVN1PROD with RULES2
52470 Federal Register / Vol. 79, No. 170 / Wednesday, September 3, 2014 / Rules and Regulations 

256 40 CFR 51.308(d)(1)(v). 

257 Id. 

258 40 CFR 51.308(d)(1)(vi). 

259RP Guidance section 4.1. 

260See Arizona RH SIP at 167 (explaining that 

Arizona’s RPGs are based on, among other things, 

‘‘the results of the CMAQ modeling . . . which 

includes ‘‘on-the-books’’ controls and other 

emission inputs’’ and Appendix C (list of CMAQ 

model emission inputs) Section 11.3.3, and the 

BART review described in Chapter 10. http://

wrapedms.org/InventoryDesc.aspx. 

261Arizona RH SIP Supplement, page 97. 

262See 78 FR 29298 (proposing to concur with the 

State’s decision to omit coarse mass and fine soil 

from its four-factor reasonable progress analysis for 

this planning period); 78 FR 46175, codified at 40 

CFR 52.120(c)(154)(ii)(A)(2) and (c)(158) (approving 

the Arizona Regional Haze SIP, except for specified 

sections). 

263See CPC Comments, Exhibit 2. 

264Summary of WRAP RMC BART Modeling for 

Arizona Draft#5, May 25, 2007, at 2 (Table 1) and 

17, SRC04 Arizona Portland Cement: PM Only (98th 

percentile 3 Year Average). 

TABLE 10—REASONABLE PROGRESS GOALS FOR 20 PERCENT BEST DAYS—Continued 

[In deciviews] 

Code Class I area 

IMPROVE 

monitor 

code 

2000–2004 

baseline 

2064 natural 

conditions 

2018 

projection 

by WRAP 

FIP effect FIP 2018 

RPG Degradation? 

sian ...................... Sierra Ancha WA SIAN1 ...... 6.16 2.03 5.88 -0.10 5.78 No.

supe ..................... Superstition WA ... TONT1 ..... 6.46 2.03 6.22 -0.12 6.09 No.

syca ..................... Sycamore Canyon 

WA.

SYCA1 ..... 5.58 0.98 5.49 -0.10 5.39 No.

Although we recognize that this 

method is not refined, it allows us to 

translate the emission reductions 

achieved through the FIP into 

quantitative RPGs, based on modeling 

previously performed by the WRAP. 

These RPGs reflect rates of progress that 

are faster than the rates projected by the 

State, but are still slower than the URP 

for each Class I areas. Nonetheless, we 

consider these rates to be reasonable for 

the reasons set forth in our proposal and 

in this final rule. We also note that 

RPGs, unlike the emission limits that 

apply to specific RP sources, are not 

directly enforceable.256 Rather, they are 

an analytical tool used by EPA to 

evaluate whether measures in the 

implementation plan are sufficient to 

achieve reasonable progress.257 Arizona 

may choose to use these RPGs for 

purposes of its progress report, or may 

develop new RPGs, based on new 

modeling or other appropriate 

techniques, in accordance with the 

requirements of 40 CFR 51.308(d)(1). 

Comment: Citing 40 CFR 

51.308(d)(1)(vi) and EPA’s RP Guidance, 

CPC stated that emission reductions that 

will occur under other CAA 

requirements must be taken into 

account when establishing RPGs. For 

example, CPC cited the Portland Cement 

MACT that imposes a PM emission 

standard of 0.07 lb/ton clinker for 

existing kilns and clinker coolers. The 

revised Portland Cement MACT will 

significantly reduce PM emissions at the 

Rillito Cement Plant. CPC stated that 

this is particularly noteworthy because 

at Saguaro National Park and other Class 

I areas in Arizona, PM is a far more 

substantial contributor to regional haze 

than NOX. CPC asserted that even if no 

additional controls are imposed as part 

of this initial RH plan, emissions of the 

primary visibility-impacting pollutant 

will substantially decrease at the Rillito 

Plant. 

Response: We partly agree with this 

comment. The cited provision of the 

RHR prohibits the adoption of RPGs that 

represent less visibility improvement 

than is expected to result from 

implementation of other requirements of 

the CAA during the applicable planning 

period.258 EPA’s RP Guidance explains 

that states ‘‘must therefore determine 

the amount of emission reductions that 

can be expected from identified sources 

or source categories as a result of 

requirements at the local, State, and 

federal levels during the planning 

period of the SIP and the resulting 

improvements in visibility at Class I 

areas.’’ 259 The WRAP modeling that 

Arizona used to develop RPGs 

addressed this requirement by including 

all emission reductions expected at the 

time that the modeling was 

performed.260 In addition, Arizona 

submitted a supplemental analysis of 

monitored coarse mass and fine soil 

impairment at the State’s Class I areas, 

including an examination of the 

monitored visibility impairment at Class 

I areas near large stationary sources of 

PM10.261 Based on these analyses and 

EPA’s supplemental analysis, as 

described in our supplemental notice of 

proposed rulemaking, we approved 

Arizona’s conclusion that no further 

analysis of PM controls was necessary 

for this planning period.262 Therefore, 

we do not agree that we are required to 

consider expected reductions in PM 

emissions from the Portland Cement 

MACT. Nonetheless, we note that, 

according to information supplied by 

CPC, implementation of the cement 

MACT at Kiln 4 would result in a 

relatively modest decrease in emissions 

from 9.6 pounds/hour (lb/hour) to 9.0 

lb/hour, a difference of 0.6 lb/hour or 

6.25 percent.263 According to modeling 

performed by the WRAP, based on an 

emission rate of 1.43 grams/second (g/ 

s) (about 11.3 lb/hour), the baseline 

impact of PM emissions from Kiln 4 at 

the Rillito Plant would be 0.02 dv or 

less at all potentially affected Class I 

areas.264 While the expected emission 

reductions from Kilns 1–3 are greater, 

these kilns have not operated since 

2008, so there would be no practical 

impact from this change. Therefore, the 

overall visibility improvement expected 

from implementation of the Portland 

Cement MACT at the Rillito Plant 

would be de minimis. 

Comment: CPC stated that EPA’s 

proposed demonstration that its RPGs 

are reasonable does not and cannot 

comply with all requirements of 

51.308(d)(1)(ii), which state that a RH 

plan ‘‘must provide to the public for 

review an assessment of the number of 

years it would take to attain natural 

conditions if visibility improvement 

continues at the rate of progress selected 

by the State as reasonable.’’ As the FIP 

does not contain this analysis, CPC 

asserted that the proposed rule does not 

comply with these requirements. 

CPC further stated that once EPA 

establishes RPGs based on the controls 

proposed for BART sources, it may learn 

that 40 CFR 51.308(d)(l)(ii) is not even 

applicable. CPC asserted that given the 

significant additional controls proposed 

for BART sources, it is likely that 

several Class I Areas will be on pace to 

meet or exceed URPs, eliminating the 

need to provide the assessment required 

here. For example, CPC stated that at 

Saguaro National Park, EPA has 

estimated that its proposed BART 

controls on the Hayden Smelter, Miami 

Smelter, and Apache Power Plant will 

have a collective visibility benefit of 

2.68 dv, more than enough to meet the 

URP with no additional controls. CPC 

added that if Saguaro National Park is 

already on pace to meet the URP, then 


emcdonald on DSK67QTVN1PROD with RULES2
Federal Register / Vol. 79, No. 170 / Wednesday, September 3, 2014 / Rules and Regulations 52471 

265See 70 FR 39124. 

266See also CAA section 302(y), 42 U.S.C. 7602(y) 

(defining FIP 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 [SIP] . . .’’). 

267 79 FR 75730. 

268See, e.g. http://www.wrapair.org/

commforum.html (describing and listing 

membership of various WRAP forums, committees 

and work groups). 

269See, e.g. 76 FR 13944, 13953 (discussing the 

‘‘very small impact on visibility impairment’’ of 

emissions from California on Grand Canyon NP and 

Sycamore Canyon NP); 77 FR 50936, 50937 

(discussing expected improvement in visibility at 

Grand Canyon NP from BART at Reid Gardner 

Generating Station in Nevada); 79 FR 26909, 26917, 

Table 4 (showing expected visibility improvement 

at Grand Canyon NP and Petrified Forest NP from 

BART at San Juan Generating Station in New 

Mexico). 

270See also CAA section 302(y), 42 U.S.C. 7602(y) 

(defining FIP 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 [SIP] . . .’’). 

271See 77 FR 75734 (proposing to find that 

Arizona met the requirements for coordination with 

the FLMs under 40 CFR 51.308(i)); 78 FR 46175 

(codified at 40 CFR 52.120(c)(154)(ii)(A)(2) and 

(c)(158)) (approving the Arizona Regional Haze SIP, 

except for specified sections). 

272NPS Comment Letter at 7–8, 10–11. 

it would be reasonable to conclude that 

additional controls are not necessary for 

Kiln 4 at this time. 

Response: We disagree with this 

comment. As shown in Table 9 above, 

even accounting for BART and RP 

controls, the RPG for Saguaro National 

Park on the 20 percent worst days is still 

well above the URP, and it is expected 

to take hundreds years to reach natural 

conditions. It is important to note that 

deciview improvements modeled for 

individual BART and RP sources using 

CALPUFF are not directly comparable 

to RPGs. In particular, modeling for 

individual BART and RP sources is 

performed using natural background 

conditions, rather than current, 

degraded conditions. EPA explained the 

rationale for this approach in the 

preamble to the BART Guidelines: 

Using existing conditions as the baseline 

for single source visibility impact 

determinations would create the following 

paradox: the dirtier the existing air, the less 

likely it would be that any control is 

required. This is true because of the 

nonlinear nature of visibility impairment. In 

other words, as a Class I area becomes more 

polluted, any individual source’s 

contribution to changes in impairment 

becomes geometrically less. Therefore the 

more polluted the Class I area would become, 

the less control would seem to be needed 

from an individual source. . . . Such a 

reading would render the visibility 

provisions meaningless, as EPA and the 

States would be prevented from assuring 

‘‘reasonable progress’’ and fulfilling the 

statutorily-defined goals of the visibility 

program. 265

Thus, EPA has determined that it is 

appropriate to use natural background 

conditions in order to gauge the impacts 

of an individual source and the 

expected benefits of controls on an 

individual source. 

By contrast, RPGs are intended to 

reflect actual conditions at a future date. 

Accordingly, they are typically set using 

regional-scale photochemical grid 

modeling that accounts for the visibility 

impacts of numerous sources over a 

large geographic area. Under this 

approach, the impact attributable to any 

one source (and the benefits available 

from controls on any one source) are 

quite small. Therefore, the expected 

degree of visibility improvement (in dv) 

from controls on individual sources 

does not translate directly into the same 

degree of improvement in RPGs. 

Comment: Citing 40 CFR 

51.308(d)(1)(iv), CPC stated that the 

RHR imposes an obligation to consult 

with states that may reasonably be 

anticipated to cause or contribute to 

visibility impairment in Arizona’s Class 

1 areas. CPC stated that the proposed 

FIP does not identify this requirement 

or explain how it complies with it. CPC 

concluded that because this 

consultation must occur when 

developing each RPG, the proposed FIP 

does not comply with this requirement. 

Response: We do not agree with this 

comment. As explained in our proposal, 

the Arizona RH FIP covers only those 

elements of the RHR for which we 

disapproved the Arizona RH SIP.266

Although we disapproved Arizona’s 

RPGs, we did not disapprove the 

Arizona RH SIP with respect to the 

consultation requirements 40 CFR 

51.308(d)(iv). As explained in our 

proposal on the Arizona RH SIP, 

‘‘Arizona consulted with other states 

and tribes using the WRAP forums and 

processes. In particular, Arizona 

consulted with California, Colorado, 

New Mexico, and Utah using the 

primary vehicle of the WRAP 

Implementation Work Group (IWG).’’ 267

EPA also consulted with these other 

states through our participation in the 

WRAP.268 Furthermore, as explained 

elsewhere in this notice, we have relied 

upon modeling performed by the WRAP 

to help quantify RPGs for Arizona. In 

addition, through our actions on other 

states’ RH SIPs, EPA has considered the 

impacts of emissions from other states 

on Arizona’s Class I areas.269 Therefore, 

we do not agree that we failed to comply 

with 40 CFR 51.308(d)(1)(iv) or that 

further consultation was necessary for 

purposes of today’s FIP. 

Comment: CPC asserted that 40 CFR 

51.308(i)(2) requires that FLMs must be 

provided with an opportunity for 

consultation at least 60 days before 

holding any public hearing on a regional 

haze implementation plan, and must be 

provided an opportunity to discuss their 

recommendations on development of 

RPGs. CPC stated that the proposed FIP 

neither identifies nor explains how 

these requirements were met. 

Response: We do not agree with these 

comments. As noted above, the Arizona 

RH FIP covers only those elements of 

the RHR for which we disapproved the 

Arizona RH SIP.270 We approved the 

Arizona RH SIP with respect to the 

requirements of 40 CFR 51.308(i).271

Therefore, no FIP is required for this 

element under the RHR. Nonetheless, 

we consulted the FLMs during 

development of the proposed FIP and 

we have considered and responded to 

their comments on our proposal, as 

documented elsewhere in this notice. 

We note that, while the FLMs have 

urged EPA to require additional RP 

controls, they expressed support for 

EPA’s proposed determinations with 

regard to CPC’s Rillito Plant.272

Comment: NPS indicated that it 

agreed with EPA that it is not likely that 

all of Arizona’s Class I areas will meet 

the URP during this planning period. 

But, according to NPS, this is partly 

because EPA and states have not done 

enough to properly address emissions 

from RP sources. NPS expressed 

disappointment that although EPA has 

acknowledged that certain control 

technologies are cost-effective, it still 

proceeded to reject certain controls 

because they would lead to insufficient 

improvements in visibility. According 

to NPS, a fundamental principle of the 

RHR is the recognition that a decline in 

visibility is due to a number of sources 

that contribute to a cumulative visibility 

issue. NPS argued that EPA’s approach 

of disaggregating each source’s 

contributions to visibility impairment 

does not solve the problem. The EGU 

sources that EPA analyzed for 

reasonable progress, i.e., Cholla Unit 1 

and Springerville Units 1 and 2, 

combined to cause a cumulative 32 dv 

of impairment at Class I areas in the 

State. By installing controls on these 

units, NPS said that emissions could be 

reduced by more than 4,400 tpy and 

decrease visibility impacts by 2.6 dv at 

a cost of $25 million annually. NPS 

asserted that, by not requiring controls 

on these units, EPA has failed to meet 

its obligation to show that it has taken 

all reasonable measures to make 

reasonable progress at this time. 

Response: We agree with NPS that a 

fundamental principle of the RHR is the 


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273Corrected Final Brief of Respondent EPA at 

80–81, Am. Corn Growers Ass’n v. EPA, 291 F.3d 

1 (D.C. Cir. 2002) (No. 99–1348). Submitted with 

the comments as Exhibit 15. 

274See 64 FR 35730–35731. 

275See 78 FR 46172. 

recognition that visibility impairment at 

Class I areas is caused by a multitude of 

different sources. However, in this 

particular action, EPA is only 

considering the reasonableness of 

controls for point sources of NOX and 

area sources of NOX and SO2. As for the 

specific EGUs referenced in this 

comment, we have addressed NPS’s 

concerns about these sources elsewhere 

in this notice. Therefore, we do not 

agree that EPA has failed to meet its 

obligation to ensure reasonable progress. 

We will continue to work with NPS, the 

State, and other stakeholders to ensure 

that reasonable progress is made at 

Arizona’s Class I areas. 

Comment: PCC agreed with EPA that 

it is necessary to consider the degree of 

improvement in visibility that would be 

achieved by the imposition of control 

technology-based standards under 40 

CFR 51.308(d)(1)(i)(A), but noted the 

requirement of 40 CFR 51.308(d)(1)(i)(B) 

to consider the uniform rate of 

improvement in visibility. PCC stated 

that, although EPA has appropriately 

concluded it is not reasonable to 

provide for rates of progress at any of 

Arizona’s Class I areas consistent with 

the URP in this planning period, EPA 

should make clear the functional 

distinction between 40 CFR 

51.308(d)(1)(i) [RP analysis] and 

308(e)(1)(ii)(A) [BART analysis] or else 

the distinction might appear to be 

irrelevant. PCC said this clarity is 

needed where BART-ineligible sources 

are concerned, particularly PCC, for 

which EPA characterized the proposed 

standard as ‘‘EPA’s proposed BART,’’ 

even though PCC is a BART-ineligible 

source. 

Response: We agree that the Clarkdale 

Plant is not BART-eligible. The 

reference in the TSD to ‘‘EPA’s 

proposed BART’’ for the Clarkdale Plant 

was a clerical error. Thus, our analysis 

of the Clarkdale Plant is based solely on 

the RP requirements. There are several 

distinctions in the applicable 

requirements for RP sources and BART 

sources, which are reflected in our 

analyses for the respective source types. 

First, unlike for BART, the expected 

degree of visibility improvement is not 

listed in the RHR as a required factor for 

consideration in relation to individual 

RP sources. While we have considered 

visibility improvement as a 

supplementary factor for RP sources, we 

have not given it the same weight as in 

our BART determinations, for which it 

is a mandatory statutory factor. Second, 

‘‘the time necessary for compliance’’ is 

a required factor for RP, but not for 

BART, and we have considered it as 

such. Third, BART controls must be 

installed ‘‘as expeditiously as 

practicable,’’ whereas there is no similar 

requirement for RP sources. Thus, we do 

not consider the distinction between 

BART and RP sources to be irrelevant. 

Comment: Earthjustice stated that 

EPA’s proposed FIP fails to meet the 

goals of the regional haze program. The 

commenter asserted that EPA’s RPGs 

and reasonable progress determination 

are in violation of the CAA. Earthjustice 

said that Arizona’s regional haze plan, 

which EPA disapproved, was far from 

meeting the RPGs and would have 

delayed natural visibility for Arizona’s 

national parks and wilderness areas by 

hundreds, even thousands of years. 

According to Earthjustice, it is now 

EPA’s responsibility to step in and 

ensure that a Federal haze plan makes 

reasonable progress toward the national 

goals, because Arizona’s plan failed to 

do so. However, in Earthjustice’s 

opinion, EPA’s proposal failed to 

comply with the regional haze 

program’s reasonable progress 

requirements. Earthjustice pointed out 

that the Agency admitted that the 

Federal plan will not achieve reasonable 

progress towards the 2064 goal. 

Earthjustice continued by stating that 

EPA has failed to meet the requirements 

of 40 CFR 51.308(d)(1)(ii) to 

demonstrate that (1) the 2064 goal is 

unreasonable at each of Arizona’s Class 

I areas and that (2) EPA’s RPGs are 

reasonable. 

Earthjustice stated that EPA should 

have determined the necessary 

emissions reductions needed to remain 

on the 2064 glide path and whether 

those reductions would be reasonable 

based on the four reasonable progress 

factors. According to Earthjustice, 

instead of doing this EPA promptly 

determined that the 2064 glide path was 

unachievable because the individual 

source-by-source reasonable progress 

determinations would not be enough to 

meet the glide path. Earthjustice 

acknowledged and appreciates the work 

EPA has done in place of Arizona’s 

inadequate haze plan. However, 

Earthjustice thought that the approach 

EPA has followed is inadequate because 

it is not bound to the overarching 2064 

natural visibility goal. Specifically, it is 

not known what level of emissions 

reductions (1,000, 100,000 or 1,000,000 

tpy) will ensure that the State of 

Arizona will meet the glide path for 

each Class I area. Nor is it known how 

those reductions could be achieved and 

if those reductions would be reasonable. 

Because these analyses have not been 

conducted, Earthjustice argued that EPA 

has not shown that it would be 

unreasonable for Arizona’s Class I areas 

to achieve the glide path. 

Earthjustice pointed to a brief filed by 

EPA in American Corn Growers, where 

EPA stated that: 

Certainly the courts would not find it 

difficult to affirm an EPA decision finding a 

State plan ‘‘unreasonable’’ if a State proposes 

to improve visibility so slowly that the 

national visibility goal would not be 

achieved for 200 or 300 years despite the 

availability of more stringent, cost-effective 

measures.273

Earthjustice stated, however, that 

under EPA’s proposal it is very likely 

that it would take even longer to restore 

Class I areas to their natural visibility. 

In spite of recent EPA actions and the 

proposed pollution controls, the FIP 

does not, in Earthjustice’s opinion, have 

sufficient emissions reductions to bring 

Arizona’s Class I areas back on track to 

the glide path. Earthjustice asserted that 

additional controls are needed, and 

without further controls, it could still 

take centuries or millennia to restore 

natural visibility. 

Similarly, CPC stated that because the 

proposed FIP contains no discussion of 

what measures would be required to 

meet a uniform rate of improvement in 

Arizona’s Class 1 areas, the proposed 

rule does not comply with 40 CFR 

51.308(d)(1)(i)(B). 

Response: The commenters’ focus on 

the URP for the 20 percent worst days 

is misguided for a number of reasons. 

First, the URP is not binding. A state or 

EPA can set RPGs that provide for less 

progress than the URP if those RPGs are 

demonstrated to be reasonable (and 

achievement of the URP to be 

unreasonable) based upon an analysis of 

the four RP factors.274 Second, as 

explained further below, much of the 

visibility impairment on the 20 percent 

worst days at many Class I areas 

implicated in this plan is caused by 

sources that are either nonanthropogenic or not feasible to control. 

Under these circumstances, projections 

regarding progress on those days are of 

limited value in determining the 

reasonableness of additional controls. 

Lastly, the only source categories and 

pollutants at issue in this action are 

non-BART point sources of NOX and 

area sources of NOX and SO2. All other 

source categories and pollutants were 

addressed by EPA’s action on the State’s 

SIP.275

EPA disagrees with Earthjustice’s 

assertion that we have not demonstrated 

that it is unreasonable to attain the URP. 

The commenter correctly notes that the 


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276The pollutants in question are organic carbon, 

elemental carbon, coarse mass, fine soil and sea 

salt. We explained in our action on the State’s SIP 

that these pollutants are not reasonable to control 

at this time. See 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. 

277See 77 FR 75717. 

278See Table 8 on 77 FR 75717. 

279See 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. 

280 78 FR 46146. 

281See 64 FR 35730–35731. 

282 78 FR 46142. 

State’s RPGs provide little visibility 

improvement on the 20 percent worst 

days, leading to long estimates of the 

time that would be required to attain 

‘‘natural’’ levels of visibility. 

Earthjustice implicitly assumes that 

most of the visibility impairment on the 

20 percent worst days is from 

controllable, anthropogenic sources. As 

EPA explained in our previous action 

on the Arizona RH SIP, the causes of 

haze on the 20 percent worst days in the 

Class I areas of Arizona are often due to 

largely uncontrollable sources.276 Table 

8 in our December 21, 2012, proposed 

action on the Arizona RH SIP shows the 

causes of haze at the Class I areas in 

Arizona. Earthjustice highlighted seven 

Class I areas that are projected to make 

particularly slow progress in visibility 

improvement on the 20 percent worst 

days: Saguaro National Park East Unit 

(SAGU1 monitor), Chiricahua National 

Monument, Chiricahua Wilderness and 

Galiuro Wilderness (all represented by 

the CHIR1 monitor), Saguaro National 

Park West Unit (SAWE1 monitor), 

Sycamore Canyon Wilderness (SYCA1 

monitor) and Superstition Wilderness 

(TONT1 monitor).277 As shown in Table 

11, in each of these Class I areas, the 

majority of impairment on the 20 

percent worst days is attributable to 

organic carbon, elemental carbon, coarse 

mass, fine soil and sea salt. 

TABLE 11—PERCENTAGE CONTRIBUTION FROM ORGANIC CARBON, ELEMENTAL CARBON, COARSE MASS, 

FINE SOIL ON 20 PERCENT WORST

DAYS DURING BASELINE PERIOD 278

IMPROVE Monitor 

Contribution from 

organic carbon, 

elemental carbon, 

coarse mass, 

fine soil and 

sea salt 

(percent) 

SAGU1 ............................ 65.9 

CHIR1 ............................. 68.9 

SAWE1 ........................... 72.9 

SYCA1 ............................ 81.8 

TONT1 ............................ 66.8 

We previouslyapproved Arizona’s RP 

determinations for this planning period 

with respect to each of these 

pollutants.279 We also approved the 

State’s determination that it is not 

reasonable to require additional controls 

on mobile sources of NOX and SO2 and 

that it is not reasonable to require 

additional SO2 reductions from point 

sources in this planning period for RP 

purposes.280 Thus, the only RP issue at 

question in this action is whether it is 

appropriate to require controls on nonBART point sources of NOX or area 

sources of NOX and SO2 in order to 

ensure reasonable progress in visibility 

improvement. As explained elsewhere 

in this notice, based on our analyses of 

the four RP factors and the potential for 

visibility improvement from additional 

controls, we have determined that it 

reasonable to require installation of 

SNCR on two cement kilns by 2018, but 

that additional RP controls are not 

reasonable at this time. 

Comment: Earthjustice strongly urged 

EPA to require additional RP controls 

beyond the proposal for control on only 

two cement kilns, to make sure Arizona 

returns to the glide path to meet natural 

visibility goal in 2064. According to 

Earthjustice, in EPA’s explanation of 

why it did not require any of the other 

sources of NOX to install pollution 

controls, EPA recognized that 

reasonable progress controls on these 

other sources are generally reasonable 

and EPA said that the decision of no 

control for these sources should be 

revisited in future planning periods. 

Earthjustice argued that taking into 

account how far off Arizona Class I 

areas are from their glide paths, EPA 

should require reasonable progress 

controls on these other sources during 

the current planning period. 

Earthjustice cited 40 CFR 

51.308(d)(3)(ii), which requires ‘‘all 

measures necessary’’ be implemented to 

achieve reasonable progress. 

Earthjustice said that additional NOX

reductions can be achieved at both 

cement plants and should be pursued in 

order to ensure Arizona Class I areas 

move closer towards the glide path. 

While acknowledging that EPA’s 

proposal is an improvement over the 

State’s plan, Earthjustice questioned 

whether it represents all measures that 

should be taken to reduce SO2, NOX, 

and PM that impair visibility at places 

like the Grand Canyon and the many 

other renowned national parks in 

Arizona and the Southwest. To the 

extent that it does not, Earthjustice 

encouraged EPA to compel further 

reductions. Earthjustice stated that it is 

good that EPA has acted, particularly in 

the earlier phase of the Arizona plan 

that compels controls on the Cholla, 

Coronado, and Apache coal-fired power 

plants, but Earthjustice asserted that 

given the level of impairment and 

numerous sources responsible, more 

should be done. 

Response: As explained in our 

response to the previous comment, the 

URP is not binding and a state or EPA 

can set RPGs that provide for less 

progress than the URP if those RPGs are 

demonstrated to be reasonable (and 

achievement of the URP to be 

unreasonable) based upon an analysis of 

the four RP factors.281 EPA disagrees 

with the Earthjustice’s interpretation of 

40 CFR 51.308(d)(3)(ii), which requires 

the State (or EPA in the case of a FIP) 

to implement all measures necessary to 

achieve the RPG. As explained in the 

previous response, due to our previous 

partial approval of the State’s SIP, our 

RP analysis is limited to point sources 

of NOX and area sources of NOX and 

SO2. Our responses to comments 

regarding specific sources are included 

elsewhere in this notice. As explained 

in those responses, EPA does not agree 

that additional controls are warranted in 

this implementation period. 

F. Other Comments on Reasonable 

Progress 

Comment: ADEQ commented that 

even though EPA has disapproved the 

RPGs in Arizona’s RH SIP, the Agency 

has been unable to develop specific 

goals, except for the ones based on the 

WRAP modeling results. The only thing 

EPA has added to the LTS for Arizona, 

besides new BART or reasonable 

progress control requirements, was 

‘‘enforceable measures.’’ However, 

ADEQ asserted that many of these 

measures are already in place. For 

example, ADEQ asserted that ‘‘EPA 

admits that the current Title V permit 

for the Miami Smelter provide[s] 

sufficient enforceability.’’ Therefore, 

ADEQ argued that EPA has no basis for 

disapproving those portions of the 

Arizona RH SIP and should not impose 

a FIP for that reason. 

Response: These comments largely 

pertain to EPA’s partial disapproval of 

the Arizona RH SIP and are therefore 

untimely, as EPA has already taken final 

action on the SIP.282 To the extent that 

that comments suggest that EPA has not 

fulfilled the requirements of the RHR, 

we do not agree. As explained above, we 

are now quantifying the RPGs that we 

proposed. These RPGs show greater 


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283Executive Order 12866, 58 FR 51735 (October 

4, 1993), section 3(e). 

284 Id. section 3(d). 

285See http://www.cbo.gov/publication/45209. 

286See ‘‘Summary of Costs for Final Rule: 

Promulgation of Air Quality Implementation Plans; 

Arizona; Regional Haze and Interstate Visibility 

Transport Federal Implementation Plan, EPA–R09– 

OAR–2013–0588.’’ We do not agree with the 

commenter that we should use total capital costs 

instead of annualized costs. The UMRA threshold 

is based on annual costs. It is not known in exactly 

which year capital costs associated with controls 

would be incurred. Thus it is not possible to 

allocate these costs to specific years. Instead, our 

reasonable progress at all of the State’s 

Class 1 areas than Arizona’s RPGs. 

Furthermore, we note that our FIP 

includes enforceable emission limits 

and related requirements applicable to 

six different sources. The Arizona RH 

SIP did not include any such 

enforceable measures. With regard to 

the Miami Smelter in particular, as 

explained elsewhere in this notice, we 

are incorporating the relevant NESHAP 

requirements as part of the final FIP in 

order to ensure the federal 

enforceability of ADEQ’s BART 

determination for PM10.

Comment: Earthjustice commented 

that additional PM reductions could be 

achieved by using improved fabric filter 

materials at the cement plants’ fabric 

filters. 

Response: Because we previously 

approved the State’s RP analysis for PM, 

we did not evaluate additional PM 

controls at any sources for purposes of 

our FIP. However, we note that, as 

detailed in CPC’s comments, the Rillito 

Plant will be required to improve its PM 

controls in order to comply with the 

Portland cement MACT. 

VIII. Responses to Comments on 

Statutory and Executive Order Reviews 

Comment: CPC stated that, with the 

exception of Consultation and 

Coordination with Indian Tribal 

Governments (Executive Order 13175), 

the proposed FIP asserts that the 

statutes and executive orders (E.O. or 

Order) are inapplicable in this matter, 

but does not adequately explain why. 

With respect to Regulatory Planning and 

Review (Executive Order 12866), the 

proposed FIP stated that it is not a 

‘‘significant regulatory action’’ and is 

not a rule of general applicability. CPC 

stated that the proposed FIP will have 

an adverse material effect on several 

sectors of the economy, in particular the 

cement and copper industries, and 

includes requirements that have 

statewide, general applicability. 

According to CPC, one of the provisions 

of Executive Order 12866 requires 

agencies to consider alternatives. CPC 

stated that had the Proposed FIP 

considered and evaluated alternatives, 

such as deferring controls on CPC 

during this first planning period, then it 

would be possible to conduct a full and 

fair evaluation to see if the benefits are 

worth the costs. Without this analysis of 

alternatives, CPC believes the proposed 

FIP is incomplete. Regarding the 

Unfunded Mandates Reform Act 

(UMRA), CPC asserted that given the 

extremely high costs to comply with the 

rule (about $81,000,000 for the Hayden 

Smelter alone), it is likely that the 

aggregate costs will exceed the 

$100,000,000 threshold in at least one 

year. Similarly, according to CPC, when 

combined with the BART controls 

imposed by the FIP on three power 

plants, annual expenditures will exceed 

the UMRA’s threshold ‘‘in any one 

year.’’ CPC stated EPA should not 

circumvent UMRA by subdividing a 

regulatory action, in this case the 

adoption of a FIP, into multiple parts. 

Regarding Executive Order 13563, CPC 

asserted that EPA must redo the 

proposed FIP to establish new RPGs, 

and identify controls as necessary to 

meet the RPGs. As part of that process, 

Executive Order 13563 should be 

followed so that EPA identifies and uses 

the best, most innovative, and least 

burdensome tools to achieve reasonable 

progress. CPC asserted that complying 

with the statutes and Executive Orders 

governing the rulemaking process is 

good public policy and the decision to 

disregard these principles has led to 

arbitrary and capricious results. 

Response: We do not agree that our 

proposed FIP is inconsistent with the 

requirements of any applicable 

Executive Orders (E.O.s) or statutes, or 

that we failed to explain the 

applicability of these requirements. 

Under E.O. 12866, ‘‘Regulatory Action’’ 

is defined as ‘‘any substantive action by 

an agency . . . that promulgates or is 

expected to lead to the promulgation of 

a final rule or regulation.’’ 283

‘‘Regulation’’ or ‘‘rule,’’ in turn, is 

defined as ‘‘an agency statement of 

general applicability and future 

effect.’’ 284 E.O. 12866 does not define 

‘‘statement of general applicability,’’ but 

this term commonly refers to statements 

that apply to groups or classes, as 

opposed to statements which apply only 

to named entities. The Phase 3 partial 

FIP for Arizona’s regional haze program 

is not a rule of general applicability 

because its requirements are tailored to 

six individually identified facilities. 

Thus, it is not a ‘‘rule’’ or ‘‘regulation’’ 

within the meaning of E.O. 12866 and 

this action is not a ‘‘regulatory action’’ 

subject to 12866. 

Executive Order 13563, Improving 

Regulation and Regulatory Review, is 

supplemental to and reaffirms the 

principles, structures, and definitions 

governing contemporary regulatory 

review that were established in EO 

12866. In general, the Order seeks to 

ensure the regulatory process is based 

on the best available science; allows for 

public participation and an open 

exchange of ideas; promotes 

predictability and reduces uncertainty; 

identifies and uses the best, most 

innovative, and least burdensome tools 

for achieving regulatory ends; and takes 

into account benefits and costs, both 

quantitative and qualitative. However, 

nothing in the Order shall be construed 

to impair or otherwise affect the 

authority granted by law to the Agency. 

As explained in our proposal, this 

action is not an action subject to review 

under Executive Orders 12866 and 

13563. In particular, as explained above, 

this action is not a ‘‘regulatory action’’ 

as defined under E.O. 12866. 

Nonetheless, we have followed the 

principles of E.O. 13563 in developing 

this action. We have applied the best 

available science, sought information 

and feedback from potentially affected 

sources, carefully considered costs and 

benefits, provided a public comment 

period and two public hearings, and 

offered flexibility on compliance 

mechanisms (e.g., a BART alternative 

for TEP Sundt, performance standards 

rather than emissions standards for the 

copper smelters, adjusted averaging 

times for the Nelson Lime Plant, and the 

option of annual emission limits for the 

cement plants). 

Under section 202 of UMRA, before 

promulgating any final rule for which a 

general notice of proposed rulemaking 

was published, EPA must prepare a 

written statement, including a costbenefit analysis, if that rule includes 

any ‘‘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 one year. 

As of 2013, the inflation-adjusted 

threshold was $150 million.285 UMRA 

defines the term ‘‘Federal private sector 

mandate’’ to mean any provision in 

regulation that would impose an 

enforceable duty upon the private 

sector. Under UMRA, the term 

‘‘regulation’’ or ‘‘rule’’ means any rule 

for which the agency publishes a 

general notice of proposed rulemaking. 

This final rule is limited to addressing 

the remaining requirements of the RHR 

for Arizona and does not include other 

regional haze actions occurring in 

separate rulemakings. We estimate that 

the total annual costs of this rulemaking 

action will not exceed $32,012,772.286


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total annual cost estimate includes both annualized 

capital costs and variable annual costs (i.e., 

operation and maintenance costs). 

287See, e.g., Mid-Tex Elec. Co-op, Inc. v. FERC, 

773 F.2d 327, 342 (D.C. Cir. 1985). 

288See Regulatory Flexibility Act Screening 

Analysis for Proposed Arizona Regional Haze 

Federal Implementation Plan (EPA–R09–OAR– 

2013–0588). 

Even if this were added to the annual 

costs of our prior Phase 1 FIP for 

Arizona ($65 million), the total cost is 

still less than the inflation-adjusted 

annual threshold. Furthermore, the cost 

estimates we have provided are based 

on conservative assumptions (i.e., 

tending to overestimate rather than 

underestimate costs) and do not account 

for the fact that certain controls (e.g., 

SO2 controls for the smelters) may be 

required under other provisions of the 

CAA prior to the implementation 

deadlines in this FIP. 

Comment: One commenter 

(Representative Gosar) expressed 

concern that the proposed FIP does not 

adequately assess the potential negative 

economic impacts on small businesses. 

The commenter noted that EPA states in 

the Federal Register that this proposed 

rule will not have a significant 

economic impact on a substantial 

number of small businesses as none of 

the facilities subject to this proposed 

rule are owned by a small entity. While 

conceding that the six facilities 

addressed in the FIP are technically not 

small businesses, the commenter 

asserted that the rule will harm small 

businesses with services that are 

dependent on the facilities. The 

commenter contended that putting these 

facilities out of business or causing 

them to increase their rates to pay for 

the new technology mandates will 

certainly have a trickle-down effect on 

a significant number of small 

businesses. 

Response: This comment appears to 

refer to EPA’s certification under the 

Regulatory Flexibility Act (RFA) that the 

FIP will not have a significant economic 

impact on a substantial number of small 

entities. Courts have interpreted the 

RFA to require a regulatory flexibility 

analysis only when a substantial 

number of small entities will be subject 

to the requirements of the Agency’s 

action.287 None of the facilities subject 

to this rule is owned by a small 

entity.288 Thus, no regulatory flexibility 

analysis is required. Nonetheless, EPA 

sought comments regarding the cost of 

controls from all entities affected by this 

action and carefully considered all 

relevant information. None of the 

affected entities, nor any other 

commenter, has provided any evidence 

that the requirements of today’s rule 

would cause any company to go out of 

business. As described elsewhere, this 

final action is necessary to achieve the 

objectives of the CAA and RHR based on 

our determination that the visibility 

improvements justify the costs of this 

rule. 

IX. Responses to Other Comments 

A. Comments on Preamble Language 

Comment: LNA recommended a 

number of corrections and clarifications 

to the preamble language in our 

proposed rule published on February 

18, 2014. 

Response: We acknowledge the 

corrections and clarifications from LNA. 

While we cannot revise the text of the 

proposal preamble, we have addressed 

the substantive issues identified by LNA 

in our responses to comments in this 

final rule. 

B. Comments on Rule Language 

Comment: Two commenters (LNA 

and ASARCO) suggested various 

corrections and clarifications to the 

proposed rule language. 

Response: We acknowledge the 

corrections and clarifications suggested 

by LNA and ASARCO. We have 

addressed the substantive issues 

identified by LNA and ASARCO in our 

responses to comments in this final rule. 

Where we agree with LNA’s and 

ASARCO’s suggestions, we have made 

the appropriate revisions to the 

regulatory text. 

C. Comments on Other Benefits of the 

Regional Haze Program 

Comment: Two commenters 

expressed concern about the health 

effects of the pollutants that cause or 

contribute to regional haze. Earthjustice 

stated that, in addition to improving 

visibility, the regional haze program for 

Arizona will yield significant public 

health benefits if properly implemented. 

Earthjustice noted that the same 

pollutants that impair scenic views at 

national parks and wilderness areas also 

cause significant public health impacts, 

including the following: 

• NOX is a precursor to ground level 

ozone, which is associated with 

respiratory diseases, asthma attacks, and 

decreased lung function. 

• NOX also reacts with ammonia, 

moisture, and other compounds to form 

particulates that can cause and worsen 

respiratory diseases, aggravate heart 

disease, and lead to premature death. 

• SO2 increases asthma symptoms, 

leads to increased hospital visits, and 

can form particulates that aggravate 

respiratory and heart diseases and cause 

premature death. 

• PM can penetrate deep into the 

lungs and cause a host of health 

problems, such as aggravated asthma 

and heart attacks. 

Earthjustice believes that Arizona’s 

regional haze program will reduce the 

serious public health toll imposed on 

Arizonans by the State’s power plants, 

copper smelters, and other sources of 

pollution. 

A private citizen expressed concerns 

specifically about the health effects that 

are a result of burning coal, which the 

commenter said is a form of energy that 

leads to some of the worst air pollution 

compared to renewable energy sources 

such as wind, solar and geothermal 

power. The commenter said that 87 

percent of NOX emissions, 94 percent of 

SO2 emissions, and 98 percent of 

mercury emissions from the utility 

sector are from utilities that burn coal. 

The commenter discussed the health 

effects of these pollutants and 

specifically mentioned the negative 

health effects of NOX, which can cause 

throat irritation at low levels of 

exposure and serious damage to the 

tissues in the respiratory tract, fluid 

buildup in the lungs, and death at high 

levels of exposure. 

Response: We agree that the same 

pollutants that contribute to haze also 

cause significant public health problems 

and that to the extent that this FIP 

reduces these pollutants, there are cobenefits for public health. However, for 

purposes of this regional haze action, 

we have not considered these benefits. 

Comment: Earthjustice stated the 

regional haze program for Arizona will 

provide substantial economic benefits, 

noting that EPA values the regional haze 

program’s health benefits nationally at 

$8.4 to $9.8 billion annually. 

Earthjustice also noted that requiring 

sources to invest in modern pollution 

controls is a job-creating mechanism in 

itself, as each installation creates shortterm construction jobs, as well as 

permanent operations and management 

positions. Earthjustice pointed out that 

the regional haze program protects 

national parks and wilderness areas, 

which are of great natural and cultural 

value, as well as serving to sustain local 

economies. According to Earthjustice, in 

2012 more than 4.4 million people 

visited the Grand Canyon. This tourism 

supported more than 6,000 jobs and 

resulted in more than $453 million in 

visitor spending. Another example is 

that over 1.2 million people visited 

Petrified Forest and Saguaro National 

Parks in 2012, which supported more 

than 1,000 jobs and resulted in more 

than $76 million in visitor spending. 

Earthjustice added that studies show 

that national park visitors prioritize 


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289 78 FR 46142. 

enjoying beautiful scenery when visiting 

national parks and will visit parks less 

during hazy conditions. Earthjustice 

concluded that the Arizona regional 

haze program will noticeably improve 

visibility at Arizona’s national parks, 

and thereby increase revenue to the 

parks and surrounding communities. 

Response: We agree that our action 

today, together with prior actions by the 

State and EPA, will provide economic 

benefits. However, for purposes of this 

action, we have not calculated these 

benefits. 

Comment: Earthjustice stated the 

regional haze program for Arizona will 

provide important environmental 

benefits because in addition to 

impairing visibility, NOX, SO2, and PM 

pollution harms plants and animals, soil 

health, and entire ecosystems in the 

following ways: 

• NOX and SO2 are the primary 

causes of acid rain, which acidifies 

lakes and streams and can damage 

certain types of trees and soils. Acid 

rain also accelerates the decay of 

building materials and paints, including 

irreplaceable buildings and statues that 

are part of our nation’s cultural heritage. 

• Nitrogen deposition, caused by wet 

and dry deposition of nitrates derived 

from NOX emissions, causes wellknown adverse impacts on ecological 

systems. At times, nitrogen deposition 

exceeds ‘‘critical loads’’ beyond the 

tolerance of various ecosystems. 

• NOX is also a precursor to ozone. 

Ground-level ozone affects plants and 

ecosystems by interfering with plants’ 

ability to produce food and increasing 

susceptibility to disease and insects. 

Ozone also contributes to wildfires and 

bark beetle outbreaks in the West by 

depressing plant water levels and 

growth. 

Response: We agree that NOX, SO2, 

and PM can have negative impacts on 

plants and ecosystems. However, while 

we note the potential for co-benefits to 

ecosystem health resulting from our 

action today, we have not taken these 

potential benefits into account in this 

action. 

D. Miscellaneous Comments 

Comment: PCC incorporated by 

reference its previous comments on 

EPA’s proposal for partial approval and 

partial disapproval of Arizona’s RH SIP 

published in a final rule dated July 30, 

2013. PCC also incorporated the 

comments that ADEQ made on EPA’s 

proposed action on the Arizona RH SIP. 

ADEQ’s comments were in regard to 

federalism and deference that EPA owes 

to the State’s decision-making under the 

regional haze provisions of the CAA, 

especially as they relate to non-BART 

sources of NOX and PCC’s facility in 

particular. 

Response: To the extent that previous 

comments from PCC and ADEQ 

regarding our Phase 2 SIP action are 

relevant here, we incorporate by 

reference our responses to those 

comments in the final SIP rule 

published on July 30, 2013.289

Comment: One private citizen 

acknowledged EPA’s proposal 

addressing regional haze in Arizona, but 

submitted comments regarding 

controlled burns that occur in the White 

Mountain area of North Arizona, and in 

other areas of the country. 

Response: We agree that wildfires also 

contribute to regional haze. However, 

today’s rule does not address wildfires. 

We will continue to work with the State 

to address emissions from wildfires. 

Comment: One private citizen pointed 

out that natural resources come in two 

forms, and some are finite, including 

coal and natural gas. The commenter 

noted that as those run out, we have to 

come up with other sources of energy, 

so we might as well start thinking about 

that sooner rather than later. The 

commenter went on to say that he 

would rather pay more for energy or not 

have technology at all if it is going to 

have a negative effect on health and 

medical costs. The commenter asked 

that EPA provide information, not only 

about the science, but also the social 

science of using finite resources. 

Response: This comment is not 

relevant to this rulemaking. 

X. Summary of Final Action 

A. Regional Haze 

EPA’s is promulgating a FIP to 

address the remaining portions of the 

Arizona RH SIP that we disapproved on 

July 30, 2013. This final rule establishes 

limits on NOX and SO2 emissions at four 

BART sources and on NOX emissions at 

two RP sources. We estimate that these 

emission limits on all six facilities will 

result in total annual emission 

reductions of about 2,900 tons/year of 

NOX and 29,300 tons/year of SO2 as 

shown in Table 12. While the rule also 

establishes emission limits for PM10 on 

the four BART facilities, these limits are 

based on existing controls. 

TABLE 12—EMISSIONS REDUCTIONS BY SOURCE

Source Control technology 

Emission reductions 

(tons/year) 

NOX SO2

Sundt Unit 4 (BART) ......................................................... SNCR and DSI ................................................................. 393 1,502 

Nelson Lime Plant Kilns 1 and 2 ...................................... SNCR and Lower sulfur fuel ............................................ 983 925 

Hayden Smelter (multiple units) ....................................... Amine scrubber for secondary capture ............................ .................... 20,036 

Miami Smelter (multiple units) .......................................... Improve primary and new secondary capture systems, 

additional controls as needed.

.................... 6,845 

PCC Clarkdale Plant Kiln 4 .............................................. SNCR ............................................................................... 810 ....................

CPC Rillito Plant Kiln 4 ..................................................... SNCR ............................................................................... 729 ....................

Total .................................................................................. ........................................................................................... 2,915 29,308 

The estimated costs associated with 

the NOX and SO2 emission reductions 

are shown in Tables 13 and 14 for each 

of the six sources, and are based on the 

control technology corresponding with 

the final emission limits. 


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TABLE 13—SUMMARY OF COSTS FOR NOX CONTROLS

Source Capital cost 

($) 

Annualized 

capital cost 

($/year) 

Annual O&M 

($/year) 

Total 

annualized 

cost 

($/year) 

Cost-effectiveness 

($/ton) 

TEP Sundt Unit 4 ................................................................. $3,079,089 $290,644 $975,124 $1,265,768 $3,222

Nelson Lime Plant Kiln 1 ..................................................... 450,000 42, 477 358,459 400,936 817 

Nelson Lime Plant Kiln 2 ..................................................... 450,000 42,477 354,981 397,458 807 

Phoenix Cement Kiln 4 ........................................................ 1,500,000 140,000 800,000 940,000 1,162 

CalPortland Cement Kiln 4 .................................................. 1,300,000 128,000 1,220,000 1,350,000 1,850 

TABLE 14—SUMMARY OF COSTS FOR SO2 CONTROLS

Source Capital cost 

($) 

Annualized 

capital cost 

($/year) 

Annual O&M 

($/year) 

Total 

annualized 

cost 

($/year) 

Cost-effectiveness 

($/ton) 

TEP Sundt Unit 4 ................................................................. $3,250,000 $306,777 $2,482,107 $2,788,884 $1,857 

Nelson Lime Plant Kiln 1 ..................................................... ........................ ........................ 313,096 313,096 856 

Nelson Lime Plant Kiln 2 ..................................................... ........................ ........................ 458,179 458,179 819 

Hayden Smelter ................................................................... 85,000,000 8,023,399 9,300,000 17,323,399 865 

Miami Smelter ...................................................................... 47,850,000 4,516,701 2,258,351 6,775,052 990

Based on air quality modeling, the 

emission reductions should result in 

improved visibility at 17 Class I areas in 

four states, including Arizona. The 

maximum and cumulative visibility 

benefits (i.e., the sum of benefits over 

affected areas) are shown in Table 15 for 

each source and type of control. 

TABLE 15—SUMMARY OF VISIBILITY BENEFITS

Source 

Maximum 

visibility 

benefit, 

(deciviews) 

Cumulative 

visibility 

benefit 

(deciviews) 

Control technology 

Sundt Unit 4 .................................................................. 0.49 1.4 SNCR and DSI. 

Sundt Unit 4: BART Alternative .................................... 1.06 2.7 Natural gas. 

Nelson Lime Plant Kilns 1 and 2 (NOX) ....................... 0.58 0.85 SNCR. 

Nelson Lime Plant Kilns 1 and 2 (SO2) ....................... 0.10 0.29 Lower sulfur fuel. 

Hayden Smelter (multiple units) ................................... 1.44 10.2 Amine scrubber for secondary capture. 

Miami Smelter (multiple units) ...................................... 0.41 1.7 Improve primary and new secondary capture systems, additional controls as needed. 

PCC Clarkdale Plant Kiln 4 .......................................... 0.52–1.85 1.7–3.0. SNCR 

CPC Rillito Plant Kiln 4 ................................................ 0.18 0.6 SNCR. 

This final rule, along with the 

previously approved portions of the 

Arizona RH SIP and a previously 

finalized FIP, constitute Arizona’s 

regional haze implementation plan for 

the first planning period that ends in 

2018. 

B. Interstate Transport 

We also are finalizing our 

determination 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 

measures in the Arizona RH SIP and 

FIP. These measures are in the approved 

portions of the Arizona RH SIP and in 

our two FIP actions, this final rule and 

our final rule on December 5, 2012. 

XI. Statutory and Executive Order 

Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

This action finalizes a Regional Haze 

FIP for six individually named facilities 

in Arizona. This action is not a rule of 

general applicability and therefore not a 

‘‘regulatory action’’ under the terms of 

Executive Order (EO) 12866 (58 FR 

51735, October 4, 1993). This type of 

action is exempt from review under EO 

12866 and is therefore not subject to 

review under Executive Order 13563 (76 

FR 3821, January 21, 2011). 

B. Paperwork Reduction Act 

This action does not impose an 

information collection burden under the 

provisions of the Paperwork Reduction 

Act, 44 U.S.C. 3501 et seq. Burden is 

defined at 5 CFR 1320.3(b). Because this 

action will finalize a Regional Haze FIP 

for only six facilities in Arizona, the 

Paperwork Reduction Act does not 

apply. See 5 CFR 1320.3(c). 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 


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290See Regulatory Flexibility Act Screening 

Analysis for Proposed Arizona Regional Haze 

Federal Implementation Plan (EPA–R09–OAR– 

2013–0588). 

291See Memorandum to Docket: Summary of 

Communications and Consultation between EPA, 

PCC and SRPMIC (January 27, 2014). 292PCC Comment Letter at 2. 293See Memo to Final—Communications with 

PCC and SRPMIC. 

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 this 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 action on small entities, 

I certify that this action will not have a 

significant economic impact on a 

substantial number of small entities. 

This final rule will not impose any 

requirements on small entities. None of 

the facilities subject to this rule is 

owned by a small entity.290

D. Unfunded Mandates Reform Act 

(UMRA) 

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 one 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 to 

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 rule does not 

contain a Federal mandate that may 

result in expenditures that exceed the 

inflation-adjusted UMRA threshold of 

$100 million (in 1996 dollars) by State, 

local, or Tribal governments or the 

private sector in any 1 year. In addition, 

this 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. 

E. Executive Order 13132: Federalism 

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. 

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 

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 so that they could 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.291

In our February 18, 2014 proposal, 

EPA proposed to require installation of 

SNCR at Kiln 4 at the Clarkdale Plant by 

December 31, 2018 and sought comment 

on the possibility of establishing an 

annual cap on NOX emissions from Kiln 

4 in lieu of a lb/ton emission limit. We 

explained that an annual cap would 

allow SRPMIC to delay installation of 

controls until the Plant’s production 

returns to pre-recession levels and 

would thus help to address the 

Community’s concerns about the 

budgetary impacts of control 

requirements. 

In its comments on the proposal, PCC 

expressed support for the cap ‘‘as long 

as the final FIP expressly provides that 

it would be at PCC’s election whether to 

meet this cap effective December 31, 

2018 or instead meet the applicable lbs/ 

ton limit effective December 31, 

2018.’’ 292 EPA subsequently requested 

clarification of this request from PCC.293

On May 22, 2014, SRPMIC submitted a 

letter to EPA describing a proposal that 

would enable PCC to elect either 

emission limit and subsequently switch 

from one to other every five years. In 

response, EPA suggested that, if 

SRPMIC wished to change the emission 


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294Email from Colleen McKaughan to Verle Martz 

(May 30, 2014). 

limit after 2018, it could seek to do so 

through a SIP revision.294 Consistent 

with this approach, in this final rule 

SRPMIC must elect which limit (i.e. 

either the lb/ton limit or the ton/year 

limit) by June 30, 2018. After that point, 

SRPMIC may seek to change the limit 

through a revision to the Arizona SIP. 

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. Also, because this 

action only applies to six sources and is 

not a rule of general applicability, it is 

not economically significant as defined 

under Executive Order 12866, and the 

rule also does not have a 

disproportionate effect on children. 

However, to the extent this action will 

limit emissions of NOX, SO2, and PM10, 

the rule will have a beneficial effect on 

children’s health by reducing air 

pollution that causes or exacerbates 

childhood asthma and other respiratory 

issues. 

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(d) of the National 

Technology Transfer and Advancement 

Act of 1995 (NTTAA), Public Law 104– 

113, 12(10) (15 U.S.C. 272 note) directs 

EPA to use voluntary consensus 

standards (VCS) in its regulatory 

activities unless to do so would be 

inconsistent with applicable law or 

otherwise impractical. VCS are 

technical standards (e.g., materials 

specifications, test methods, sampling 

procedures and business practices) that 

are developed or adopted by the VCS 

bodies. The NTTAA directs EPA to 

provide Congress, through annual 

reports to OMB, with explanations 

when the Agency decides not to use 

available and applicable VCS. This 

action does not 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 rule 

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 rule limits 

emissions of NOX, PM10, and SO2 from 

six facilities in Arizona. 

K. Congressional Review Act 

The Congressional Review Act, 5 

U.S.C. 801 et seq., as added by the Small 

Business Regulatory Enforcement 

Fairness Act of 1996, generally provides 

that before a rule may take effect, the 

agency promulgating the rule must 

submit a rule report, which includes a 

copy of the rule, to each House of the 

Congress and to the Comptroller General 

of the United States. Section 804 

exempts from section 801 the following 

types of rules: (1) Rules of particular 

applicability; (2) rules relating to agency 

management or personnel; and (3) rules 

of agency organization, procedure, or 

practice that do not substantially affect 

the rights or obligations of non-agency 

parties. 5 U.S.C. 804(3). EPA is not 

required to submit a rule report 

regarding this action under section 801 

because this is a rule of particular 

applicability that only applies to six 

named facilities. 

L. Petitions for Judicial Review 

Under section 307(b)(1) of the Clean 

Air Act, petitions for judicial review of 

this action must be filed in the United 

States Court of Appeals for the 

appropriate circuit by November 3, 

2014. Filing a petition for 

reconsideration by the Administrator of 

this final rule does not affect the finality 

of this rule for the purposes of judicial 

review nor does it extend the time 

within which a petition for judicial 

review may be filed, and shall not 

postpone the effectiveness of such rule 

or action. This action may not be 

challenged later in proceedings to 

enforce its requirements. See CAA 

section 307(b)(2). 

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. 

Dated: June 27, 2014. 

Gina McCarthy, 

Administrator. 

For the reasons stated in the 

preamble, part 52, chapter I, title 40 of 

the Code of Federal Regulations is 

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) and 

appendices (A) and (B) 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): 


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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, and 

stack gas volumetric flow rate. 

Kiln means either of the kilns 

identified in paragraph (i)(1) of this 

section. 

Kiln 1 means lime kiln 1, as identified 

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

Kiln 2 means lime 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 there 

is operation of Kiln 1, Kiln 2, or both 

kilns at any time. 

Kiln operation means any period 

when any raw materials are fed into the 

Kiln or any period when any 

combustion is occurring or fuel is being 

fired in the Kiln. 

Lime product means the product of 

the lime-kiln calcination process, 

including calcitic lime, dolomitic lime, 

and dead-burned dolomite. 

NOX means oxides of nitrogen. 

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. 

(3) Emission limitations. (i) The 

owner/operator of the kilns 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 12- 

month rolling basis. 

Kiln ID Pollutant 

emission limit NOX SO2

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

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

(ii) The owner/operator of the kilns 

identified in paragraph (i)(1) of this 

section shall not emit or cause to be 

emitted pollutants in excess of 3.27 tons 

of NOX per day and 10.10 tons of SO2

per day, combined from both kilns, 

based on a rolling 30-kiln-operating-day 

basis. 

(iii) In addition, if the owner/operator 

installs an ammonia injection system to 

comply with the limits specified in 

paragraph (i)(3) of this section, the 

owner/operator shall also comply with 

the control technology demonstration 

requirements set forth in paragraph 

(i)(5) of this section. 

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

operator of each kiln shall comply with 

the NOX emission limitations and other 

NOX-related requirements of this 

paragraph (i) no later than September 4, 

2017. 

(ii) The owner/operator of each kiln 

shall comply with the SO2 emission 

limitations and other SO2-related 

requirements of this paragraph (i) no 

later than March 3, 2016. 

(5) Control technology demonstration 

requirements. If the owner/operator of a 

kiln installs an ammonia injection 

system to comply with the limits 

specified in paragraph (i)(3) of this 

section, the owner/operator must 

comply with the following requirements 

for implementing combustion and 

process optimization measures. 

(i) Design report. Prior to commencing 

construction of an ammonia injection 

system used to comply with the limits 

specified in paragraph (i)(3) of this 

section, the owner/operator shall submit 

to EPA for review a Design Report as 

described in Appendix B of this section. 

(ii) Optimization protocol. Prior to 

commencement of the Optimization 

Program, the owner/operator shall 

submit to EPA for review an 

Optimization Protocol which shall 

include the procedures, as described in 

Appendix B of this section, to be used 

during the Optimization Program for the 

purpose of adjusting operating 

parameters and minimizing emissions. 

(iii) Optimization period. Following 

EPA review of the Optimization 

Protocol, the owner/operator shall 

operate the ammonia injection system 

and collect data in accordance with the 

Optimization Protocol. The owner/

operator shall operate the ammonia 

injection system in such a manner for 

no longer than 180 kiln operating days, 

or the duration specified in the 

Optimization Protocol, whichever is 

longer in duration. 

(iv) Optimization report. Within 60 

calendar days following the conclusion 

of the Optimization Program, the owner/ 

operator shall submit to EPA for review 

an Optimization Report, as described in 

Appendix B of this section, 

demonstrating conformance with the 

Optimization Protocol, and establishing 

optimized operating parameters for the 

ammonia injection system as well as 

other facility processes. 

(v) Demonstration period. Following 

EPA review of the Optimization Report, 

the owner/operator shall operate the 

ammonia injection system consistent 

with the optimized operations of the 

facility and ammonia injection system 

specified in the Optimization Report. 

The owner/operator shall operate the 

ammonia injection system in such a 

manner for a period of 360 kiln 

operating days, or the duration specified 

in the Optimization Report, whichever 

is longer. The Demonstration Period 

may be shortened or lengthened as 

provided for in appendix B of this 

section. 

(vi) Demonstration report. Within 60 

calendar days following the conclusion 

of the Demonstration Program, the 

owner/operator shall submit a 

Demonstration Report, as described in 

appendix B of this section, which 

identifies a proposed rolling 12-month 

emission limit for NOX. In a subsequent 

regulatory action, EPA may seek to 

lower the NOX emission limits in 

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

of, among other things, the information 

contained in the Demonstration Report. 

The proposed rolling 12-month 

emission limit shall be calculated in 

accordance with the following formula: 

X = m + 1.65s 

Where: 

X = Rolling 12-month emission limit, in 

pounds of NOX per ton of lime product; 

m = Arithmetic mean of all of the rolling 12- 

month emission rates; 

s = Standard deviation of all of the rolling 

12-month emission rates, as calculated in 

the following manner: 

Where: 

N = The total number of rolling 12-month 

emission rates; 

xi = Each rolling 12-month emission rate; 

x ̄ = The mean value of all of the rolling 12- 

month emission rates. 

(6) 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 kilns 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 diluent, stack 

gas volumetric flow rate, and 

concentration by volume of NOX and 

SO2 emissions into the atmosphere from 

kilns 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/


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Federal Register / Vol. 79, No. 170 / Wednesday, September 3, 2014 / Rules and Regulations 52481 

operator must operate the monitoring 

system and collect data at all required 

intervals at all times that an affected 

kiln 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 kiln, the owner or 

operator shall install, and thereafter 

maintain and operate, instrumentation 

to continuously monitor and record 

levels of ammonia consumption for that 

kiln. 

(iii) Compliance determination for lb 

per ton NOX limit. Compliance with the 

NOX emission limits described in 

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

determined based on a rolling 12-month 

basis. The 12-month rolling NOX

emission rate for each kiln shall be 

calculated within 30 days following the 

end of each calendar month in 

accordance with the following 

procedure: Step one, sum the hourly 

pounds of NOX emitted for the month 

just completed and the eleven (11) 

months preceding the month just 

completed to calculate the total pounds 

of NOX emitted over the most recent 

twelve (12) month period for that kiln; 

Step two, sum the total lime product, in 

tons, produced during the month just 

completed and the eleven (11) months 

preceding the month just completed to 

calculate the total lime product 

produced over the most recent twelve 

(12) month 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 12-month rolling NOX

emission rate for that kiln. Each 12- 

month rolling NOX emission rate shall 

include all emissions and all lime 

product that occur during all periods 

within the 12-month period, including 

emissions from startup, shutdown, and 

malfunction. 

(iv) Compliance determination for lb 

per ton SO2 limit. Compliance with the 

SO2 emission limits described in 

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

determined based on a rolling 12-month 

basis. The 12-month rolling SO2

emission rate for each kiln shall be 

calculated within 30 days following the 

end of each calendar month in 

accordance with the following 

procedure: Step one, sum the hourly 

pounds of SO2 emitted for the month 

just completed and the eleven (11) 

months preceding the month just 

completed to calculate the total pounds 

of SO2 emitted over the most recent 

twelve (12) month period for that kiln; 

Step two, sum the total lime product, in 

tons, produced during the month just 

completed and the eleven (11) months 

preceding the month just completed to 

calculate the total lime product 

produced over the most recent twelve 

(12) month 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 12-month rolling SO2

emission rate for that kiln. Each 12- 

month rolling SO2 emission rate shall 

include all emissions and all lime 

product that occur during all periods 

within the 12-month period, including 

emissions from startup, shutdown, and 

malfunction. 

(v) Compliance determination for ton 

per day NOX limit. Compliance with the 

NOX emission limit described in 

paragraph (i)(3)(ii) of this section shall 

be determined based on a rolling 30- 

kiln-operating-day basis. The rolling 30- 

kiln operating day NOX emission rate 

for the kilns shall be calculated for each 

kiln operating day in accordance with 

the following procedure: Step one, sum 

the hourly pounds of NOX emitted from 

both kilns for the current kiln operating 

day and the preceding twenty-nine (29) 

kiln-operating-day period for both kilns; 

Step two, divide the total pounds of 

NOX calculated from Step one by two 

thousand (2,000) to calculate the total 

tons of NOX; Step three, divide the total 

tons of NOX calculated from Step two by 

thirty (30) to calculate the rolling 30- 

kiln operating day NOX emission rate 

for both kilns. Each rolling 30-kiln 

operating day NOX emission rate shall 

include all emissions that occur from 

both kilns during all periods within any 

kiln operating day, including emissions 

from startup, shutdown, and 

malfunction. 

(vi) Compliance determination for ton 

per day SO2 limit. Compliance with the 

SO2 emission limit described in 

paragraph (i)(3)(ii) of this section shall 

be determined based on a rolling 30- 

kiln-operating-day basis. The rolling 30- 

kiln operating day SO2 emission rate for 

the kilns shall be calculated for each 

kiln operating day in accordance with 

the following procedure: Step one, sum 

the hourly pounds of SO2 emitted from 

both kilns 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 both kilns; Step two, 

divide the total pounds of SO2

calculated from Step one by two 

thousand (2,000) to calculate the total 

tons of SO2; Step three, divide the total 

tons of SO2 calculated from Step two by 

thirty (30) to calculate the rolling 30- 

kiln operating day SO2 emission rate for 

both kilns. Each rolling 30-kiln 

operating day SO2 emission rate shall 

include all emissions that occur from 

both kilns during all periods within any 

kiln operating day, including emissions 

from startup, shutdown, and 

malfunction. 

(7) 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) Monthly rolling 12-month 

emission rates of NOX and SO2, 

calculated in accordance with 

paragraphs (i)(6)(iii) and (iv) of this 

section. 

(iv) Daily rolling 30-kiln operating 

day emission rates of NOX and SO2

calculated in accordance with 

paragraphs (i)(6)(v) and (vi) of this 

section. 

(v) Records of quality assurance and 

quality control activities for emissions 

measuring systems including, but not 

limited to, any records specified by 40 

CFR part 60, appendix F, Procedure 1, 

as well as the following: 

(A) The occurrence and duration of 

any startup, shutdown, or malfunction, 

performance testing, evaluations, 

calibrations, checks, adjustments 

maintenance, duration of any periods 

during which a CEMS or COMS is 

inoperative, and corresponding 

emission measurements. 

(B) Date, place, and time of 

measurement or monitoring equipment 

maintenance activity; 

(C) Operating conditions at the time of 

measurement or monitoring equipment 

maintenance activity; 

(D) Date, place, name of company or 

entity that performed the measurement 

or monitoring equipment maintenance 

activity and the methods used; and 

(E) Results of the measurement or 

monitoring equipment maintenance. 

(vi) Records of ammonia 

consumption, as recorded by the 

instrumentation required in paragraph 

(i)(6)(ii) of this section. 

(vii) Records of all major maintenance 

activities conducted on emission units, 

air pollution control equipment, CEMS, 

and lime production measurement 

devices. 

(viii) All other records specified by 40 

CFR part 60, appendix F, Procedure 1. 

(8) Reporting. All reports required 

under this section shall be submitted by 

the owner/operator to the Director, 


emcdonald on DSK67QTVN1PROD with RULES2
52482 Federal Register / Vol. 79, No. 170 / Wednesday, September 3, 2014 / Rules and Regulations 

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 rolling 30-kiln 

operating day emission rates for NOX

and SO2, calculated in accordance with 

paragraphs (i)(6)(iii) and (iv) of this 

section. 

(ii) The owner/operator shall submit a 

report that lists the monthly rolling 12- 

month emission rates for NOX and SO2, 

calculated in accordance with 

paragraphs (i)(6)(v) and (vi) of this 

section. 

(iii) The owner/operator shall submit 

excess emissions reports for NOX and 

SO2 limits. Excess emissions means 

emissions that exceed any of 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 kiln; the nature and 

cause of any malfunction (if known); 

and the corrective action taken or 

preventative measures adopted. 

(iv) The owner/operator shall submit 

a summary of CEMS operation, 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. 

(v) The owner/operator shall submit 

results of all CEMS performance tests 

required by 40 CFR part 60, appendix F, 

Procedure 1 (Relative Accuracy Test 

Audits, Relative Accuracy Audits, and 

Cylinder Gas Audits). 

(vi) 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. 

(9) Notifications. All notifications 

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. 

(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 (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. 

(10) Equipment operations. (i) At all 

times, including periods of startup, 

shutdown, and malfunction, the owner/ 

operator shall, to the extent practicable, 

maintain and operate the kilns, 

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 kilns. 

(ii) After completion of installation of 

ammonia injection on a kiln, the owner/ 

operator shall inject sufficient ammonia 

to achieve compliance with the NOX

emission limits from paragraph (i)(3) of 

this section for that kiln while 

preventing excessive ammonia 

emissions. 

(11) Enforcement. Notwithstanding 

any other provision in this 

implementation plan, any credible 

evidence or information relevant as to 

whether the kiln 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/operator has 

violated or is in violation of any 

standard or applicable emission limit in 

the plan. 

(j) Source-specific federal 

implementation plan for regional haze 

at H. Wilson Sundt Generating Station— 

(1) Applicability. This paragraph (j) 

applies to the owner/operator of the 

electricity generating unit (EGU) 

designated as Unit I4 at the H. Wilson 

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. 

Natural gas means a naturally 

occurring fluid mixture of hydrocarbons 

as defined in 40 CFR 72.2. 

NOX means oxides of nitrogen. 

Owner/operator means any person 

who owns or who operates, controls, or 

supervises the EGU identified in 

paragraph (j)(1) of this section.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) of 

this section. 

(i) The owner/operator of the unit 

shall combust only natural gas or 

natural gas combined with landfill 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. 


emcdonald on DSK67QTVN1PROD with RULES2
Federal Register / Vol. 79, No. 170 / Wednesday, September 3, 2014 / Rules and Regulations 52483 

Pollutant 

Pollutant 

emission 

limit 

NOX .................................... 0 .25 

PM10 .................................... 0 .010 

SO2 ..................................... 0 .057 

(iii) If the results of the initial 

performance test conducted in 

accordance with paragraph (j)(8)(iv) of 

this section show PM10 emissions 

greater than the limit in paragraph 

(j)(4)(ii) of this section, the owner/

operator may elect to comply with an 

emission limit equal to the result of the 

initial performance test, in lieu of the 

PM10 emission limit in paragraph 

(j)(4)(ii). 

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

operator of the unit subject to this 

paragraph (j)(5) shall comply with the 

NOX and SO2 emission limitations of 

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

than September 4, 2017. 

(ii) The owner/operator of the unit 

subject to this paragraph (j)(5) shall 

comply with the PM emission limitation 

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 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

emission limitations of paragraph (j)(4) 

of this section 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 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 

40 CFR part 75, the 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 the requirements 

in part 75 of this chapter, 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/ 

hour of NOX, SO2, and heat input shall 

be performed each time the CEMS 

undergo relative accuracy testing. 

(ii) Ammonia consumption 

monitoring. Upon and after the 

completion of installation of ammonia 

injection on the unit, the owner/

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-boiler-operating-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 MMBtu, 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 rolling 30-boileroperating-day NOX emission rate, in 

pounds per MMBtu for that unit. Each 

rolling 30-boiler-operating-day 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 rolling 30-boiler-operating-day 

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 rolling 30-boiler-operating-day 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 

MMBtu, during the current boiler 

operating day and the preceding twentynine (29) boiler operating days to 

calculate the total heat input over the 

most recent thirty (30) boiler-operatingday period for that unit; Step three, 

divide the total amount of SO2

calculated from Step one by the total 

heat input calculated from Step two to 

calculate the rolling 30-boiler-operatingday SO2 emission rate, in pounds per 

MMBtu for that unit. Each rolling 30- 

boiler-operating-day 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 rolling 30-boiler-operating-day 

emission rate. 

(v) Compliance determination for PM. 

Compliance with the PM emission limit 

described in paragraph (j)(3) of this 

section 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 Methods 1 

through 5, in 40 CFR part 60, appendix 

A. Each test shall consist of three runs, 

with each run at least one hundred 

twenty (120) minutes in duration and 

each run collecting a minimum sample 

of sixty (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 (j)(8) may be used in lieu 

of paragraph (j)(7) of this section to 

demonstrate compliance with the 

emission limits in paragraph (j)(4) of 

this section. 

(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 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 


emcdonald on DSK67QTVN1PROD with RULES2
52484 Federal Register / Vol. 79, No. 170 / Wednesday, September 3, 2014 / Rules and Regulations 

with the emission limitation for NOX in 

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

the CEMS is out-of-control as defined by 

40 CFR part 75, the 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 ninety (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 

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 rolling 30-boileroperating-day 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) boileroperating-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 MMBtu, during the 

current boiler operating day and the 

preceding twenty-nine (29) boileroperating-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 rolling 30-boileroperating-day NOX emission rate, in 

pounds per MMBtu for that unit. Each 

rolling 30-boiler-operating-day 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 rolling 30-boiler-operating-day 

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 either natural 

gas or natural gas combined with 

landfill 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 Methods 1 through 4, 201A, 

and Method 202, per 40 CFR part 51, 

appendix M. Each test shall consist of 

three runs, with each run at least one 

hundred twenty (120) minutes in 

duration and each run collecting a 

minimum sample of sixty (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/

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 rolling 30-boiler operating 

day 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 (j)(10) in 

lieu of the records contained in 

paragraph (j)(9) of this section. The 

owner/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 rolling 30-boiler operating 

day 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 natural gas 

or natural gas combined with landfill 

gas. 

(viii) All PM10 stack test results. 

(11) Notifications. All notifications 

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. 

(i) By March 31, 2017, the owner/

operator shall submit notification by 

letter whether it will comply with the 

emission limits in paragraph (j)(3) of 

this section or whether it will comply 

with the emission limits in paragraph 

(j)(4) of this section. In the event that the 

owner/operator does not submit timely 

and proper notification by March 31, 

2017, the owner/operator may not 

choose to comply with the alternative 

emission limits in paragraph (j)(4) of 

this section and shall comply with the 

emission limits in paragraph (j)(3) of 

this section. 

(ii) The owner/operator shall submit 

notification 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. 

(v) The owner/operator shall submit 

notification of its intent to comply with 

the PM10 emission limit in paragraph 

(j)(4)(iii) of this section within one 

hundred twenty (120) days following 

the compliance deadline specified in 

paragraph (j)(6) of this section. The 

notification shall include results of the 

initial performance test and the 

resulting applicable emission limit. 

(12) Reporting. All reports required 

under this section shall be submitted by 

the owner/operator to the Director, 

Enforcement Division (Mail Code ENF– 


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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 rolling 30- 

boiler operating day 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 emission 

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 

a summary of CEMS operation, 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) of 

this section. 

(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 (j)(13) in 

lieu of the reports contained in 

paragraph (j)(12) of this section. All 

reports required under this paragraph 

(j)(13) 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 

(j)(13) 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 rolling 30- 

boiler operating day emission rates for 

NOX. 

(ii) The owner/operator shall submit 

excess emissions reports for NOX limits. 

Excess emissions means emissions that 

exceed the emission limit 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/ 

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/ 

operator shall inject sufficient ammonia 

to achieve compliance with the NOX

emission limit 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/operator has 

violated or is in violation of any 

standard or applicable emission limit in 

the plan. 

(k) Source-specific federal 

implementation plan for regional haze 

at Clarkdale Cement Plant and Rillito 

Cement Plant—(1) Applicability. This 

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


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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 at any time. 

Kiln operation means any period 

when any raw materials are fed into the 

kiln or any period when any 

combustion is occurring or fuel is being 

fired in the kiln. 

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. (i) The 

owner/operator of kiln 4 of the 

Clarkdale Plant, as identified in 

paragraph (k)(1) of this section, shall not 

emit or cause to be emitted from kiln 4 

NOX in excess of 2.12 pounds of NOX

per ton of clinker produced, based on a 

rolling 30-kiln operating day basis. In 

addition, if the owner/operator installs 

an ammonia injection system to comply 

with the limits specified in this 

paragraph (k)(3), the owner/operator 

shall also comply with the control 

technology demonstration requirements 

set forth in paragraph (k)(6) of this 

section. 

(ii) The owner/operator of kiln 4 of 

the Rillito Plant, as identified in 

paragraph (k)(1) of this section, shall not 

emit or cause to be emitted from kiln 4 

NOX in excess of 3.46 pounds of NOX

per ton of clinker produced, based on a 

rolling 30-kiln operating day basis. In 

addition, if the owner/operator installs 

an ammonia injection system to comply 

with the limits specified in this 

paragraph (k)(3), the owner/operator 

shall also comply with the control 

technology demonstration requirements 

set forth in paragraph (k)(6) of this 

section. 

(4) Alternative emissions limitation. 

In lieu of the emission limitation listed 

in paragraph (k)(3)(i) of this section, the 

owner/operator of kiln 4 of the 

Clarkdale Plant may choose to comply 

with the following limitation by 

providing notification per paragraph 

(k)(13)(iv) of this section. The owner/

operator of kiln 4 of the Clarkdale Plant, 

as identified in paragraph (k)(1) of this 

section, shall not emit or cause to be 

emitted from kiln 4 NOX in excess of 

810 tons per year, based on a rolling 12 

month basis. 

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

operator of each unit identified in 

paragraph (k)(1) of this section shall 

comply with the NOX emissions 

limitations and other NOX-related 

requirements of paragraph (k)(3) of this 

section no later than December 31, 2018. 

(ii) If the owner/operator of the 

Clarkdale Plant chooses to comply with 

the emission limit of paragraph (k)(4) of 

this section in lieu of paragraph (k)(3)(i) 

of this section, the owner/operator shall 

comply with the NOX emissions 

limitations and other NOX-related 

requirements of paragraph (k)(4) of this 

section no later than December 31, 2018. 

(6) Control technology demonstration 

requirements. If the owner/operator of a 

unit installs an ammonia injection 

system to comply with the limits 

specified in paragraph (k)(3) of this 

section, the owner/operator must 

comply with the following requirements 

for implementing combustion and 

process optimization measures. 

(i) Design report. Prior to commencing 

construction of an ammonia injection 

system used to comply with the limits 

specified in paragraph (k)(3) of this 

section, the owner/operator shall submit 

to EPA for review a Design Report as 

described in appendix A of this section. 

(ii) Optimization protocol. Prior to 

commencement of the Optimization 

Program, the owner/operator shall 

submit to EPA for review an 

Optimization Protocol which shall 

include the procedures, as described in 

appendix A of this section, to be used 

during the Optimization Program for the 

purpose of adjusting operating 

parameters and minimizing emissions. 

(iii) Optimization period. Following 

EPA review of the Optimization 

Protocol, the owner/operator shall 

operate the ammonia injection system 

and collect data in accordance with the 

Optimization Protocol. The owner/

operator shall operate the ammonia 

injection system in such a manner for 

no longer than 180 kiln operating days, 

or the duration specified in the 

Optimization Protocol, whichever is 

longer in duration. 

(iv) Optimization report. Within 60 

calendar days following the conclusion 

of the Optimization Program, the owner/ 

operator shall submit to EPA for review 

an Optimization Report, as described in 

appendix A of this section, 

demonstrating conformance with the 

Optimization Protocol, and establishing 

optimized operating parameters for the 

ammonia injection system as well as 

other facility processes. 

(v) Demonstration period. Following 

EPA review of the Optimization Report, 

the owner/operator shall operate the 

ammonia injection system consistent 

with the optimized operations of the 

facility and ammonia injection system 

specified in the Optimization Report. 

The owner/operator shall operate the 

ammonia injection system in such a 

manner for a period of 270 kiln 

operating days, or the duration specified 

in the Optimization Report, whichever 

is longer. The Demonstration Period 

may be shortened or lengthened as 

provided for in appendix A of this 

section. 

(vi) Demonstration report. Within 60 

calendar days following the conclusion 

of the Demonstration Program, the 

owner/operator shall submit a 

Demonstration Report, as described in 

appendix A of this section, which 

identifies a proposed rolling 30-kiln 

operating day emission limit for NOX. In 

a subsequent regulatory action, EPA 

may seek to lower the emission limits in 

paragraphs (k)(3) and/or (k)(4) of this 

section in view of, among other things, 

the information contained in the 

Demonstration Report. The proposed 

rolling 30-kiln operating day emission 

limit shall be calculated in accordance 

with the following formula: 

X = m + 1.65s 

Where: 

X = Rolling 30-kiln operating day emission 

limit, in pounds of NOx per ton of 

clinker; 

m = Arithmetic mean of all of the rolling 30- 

kiln operating day emission rates; 

s = Standard deviation of all of the rolling 

30-kiln operating day emission rates, as 

calculated in the following manner: 

Where: 

N = The total number of rolling 30-kiln 

operating day emission rates; 

xi = Each rolling 30-kiln operating day 

emission rate; 

x ̄ = The mean value of all of the rolling 30- 

kiln operating day emission rates. 

(7) Compliance determination—(i) 

Continuous emission monitoring 

system. (A) At all times after the 

compliance date specified in paragraph 

(k)(5) 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 


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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)(5) 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: 

E[D] = 30 kiln operating day average 

emission rate of NOX, lb/ton of clinker; 

C[i] = Concentration of NOX for hour i, ppm; 

Q[i] = Volumetric flow rate of effluent gas for 

hour i, where C[i] and Q[i] are on the 

same basis (either wet or dry), scf/hr; 

P[i] = Total kiln clinker produced during 

production hour i, ton/hr; 

k = Conversion factor, 1.194 x 10<-7> for 

NOX; and 

n = Number of kiln operating hours over 30 

kiln operating days, n = 1 up 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. 

(8) Alternative compliance 

determination. If the owner/operator of 

the Clarkdale Plant chooses to comply 

with the emission limits of paragraph 

(k)(4) of this section, this paragraph 

(k)(8) may be used in lieu of paragraph 

(k)(7) of this section to demonstrate 

compliance with the emission limits in 

paragraph (k)(4) of this section. 

(i) Continuous emission monitoring 

system. At all times after the compliance 

date specified in paragraph (k)(5) 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). 

(ii) Method. Compliance with the ton 

per year NOX emission limit described 

in paragraph (k)(4) of this section shall 

be determined based on a rolling 12 

month basis. The rolling 12-month NOX

emission rate for the kiln shall be 

calculated within 30 days following the 

end of each calendar month in 

accordance with the following 

procedure: Step one, sum the hourly 

pounds of NOX emitted for the month 

just completed and the eleven (11) 

months preceding the month just 

completed, to calculate the total pounds 

of NOX emitted over the most recent 

twelve (12) month period for that kiln; 

Step two, divide the total pounds of 

NOX calculated from Step one by two 

thousand (2,000) to calculate the total 

tons of NOX. Each rolling 12-month NOX

emission rate shall include all emissions 

that occur during all periods within the 

12-month period, including emissions 

from startup, shutdown and 

malfunction. 

(iii) Upon and after the completion of 

installation of ammonia injection on the 

unit, the owner/operator shall install, 

and thereafter maintain and operate, 

instrumentation to continuously 

monitor and record levels of ammonia 

consumption for that unit. 

(9) 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; emissions and 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)(7)(ii) of this section. 

(iv) Records of quality assurance and 

quality control activities for emissions 

measuring systems including, but not 

limited to, any records specified by 40 

CFR part 60, appendix F, Procedure 1. 

(v) Records of ammonia consumption, 

as recorded by the instrumentation 

required in paragraph (k)(7)(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. 


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(vii) Any other records specified by 40 

CFR part 60, subpart F, or 40 CFR part 

60, appendix F, Procedure 1. 

(10) Alternative recordkeeping 

requirements. If the owner/operator of 

the Clarkdale Plant chooses to comply 

with the emission limits of paragraph 

(k)(4) of this section, the owner/operator 

shall maintain the records listed in this 

paragraph (k)(10) in lieu of the records 

contained in paragraph (k)(9) of this 

section. The owner or 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; emissions and parameters 

sampled or measured; and results. 

(ii) Monthly rolling 12-month 

emission rates of NOX, calculated in 

accordance with paragraph (k)(8)(ii) of 

this section. 

(iii) Records of quality assurance and 

quality control activities for emissions 

measuring systems including, but not 

limited to, any records specified by 40 

CFR part 60, appendix F, Procedure 1. 

(iv) Records of ammonia 

consumption, as recorded by the 

instrumentation required in paragraph 

(k)(8)(iii) of this section. 

(v) Records of all major maintenance 

activities conducted on emission units, 

air pollution control equipment, and 

CEMS measurement devices. 

(vi) Any other records specified by 40 

CFR part 60, subpart F, or 40 CFR part 

60, appendix F, Procedure 1. 

(11) Reporting. All reports required 

under this section shall be submitted by 

the owner/operator to the Director, 

Enforcement Division (Mailcode 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 (k)(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. 

(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 specified 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)(9)(ii) 

of this section. 

(12) Alternative reporting 

requirements. If the owner/operator of 

the Clarkdale Plant chooses to comply 

with the emission limits of paragraph 

(k)(4) of this section, the owner/operator 

shall submit the reports listed in this 

paragraph (k)(12) in lieu of the reports 

contained in paragraph (k)(11) of this 

section. All reports required under this 

section shall be submitted by the owner/ 

operator to the Director, Enforcement 

Division (Mailcode 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 (k)(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 monthly rolling 12- 

month 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 specified 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)(9)(ii) 

of this section. 

(13) 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. 

(iv) By June 30, 2018, the owner/

operator of the Clarkdale Plant shall 

notify the Regional Administrator by 

letter whether it will comply with the 

emission limits in paragraph (k)(3)(i) of 

this section or whether it will comply 

with the emission limits in paragraph 

(k)(4) of this section. In the event that 

the owner/operator does not submit 

timely and proper notification by June 

30, 2018, the owner/operator of the 

Clarkdale Plant may not choose to 

comply with the alternative emission 

limits in paragraph (k)(4) of this section 

and shall comply with the emission 

limits in paragraph (k)(3)(i) of this 

section. 

(14) 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 


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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 set forth in 

paragraph (k)(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. 

(l) Source-specific federal 

implementation plan for regional haze 

at Hayden Copper Smelter—(1) 

Applicability. This paragraph (l) applies 

to each owner/operator of batch copper 

converters #1, 3, 4 and 5 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 

Peirce-Smith 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 96 and 98 

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. 

Capture system means the collection 

of components used to capture gases 

and fumes released from one or more 

emission points, and to convey the 

captured gases and fumes to one or 

more control devices. A capture system 

may include, but is not limited to, the 

following components as applicable to a 

given capture system design: Duct 

intake devices, hoods, enclosures, 

ductwork, dampers, manifolds, 

plenums, and fans. 

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. 

Regional Administrator means the 

Regional Administrator of EPA Region 9 

or his or her designated representative. 

SO2 means sulfur dioxide. 

(3) Emission capture. (i) The owner/ 

operator must operate a capture system 

that has been designed to maximize 

collection of process off gases vented 

from each converter identified in 

paragraph (l)(1) of this section. The 

capture system must include primary 

and secondary capture systems as 

described in 40 CFR 63.1444(d)(2). 

(ii) The operation of the batch copper 

converters, primary capture system, and 

secondary capture system shall be 

optimized to capture the maximum 

amount of process off gases vented from 

each converter at all times. 

(iii) The owner/operator shall prepare 

a written operation and maintenance 

plan according to the requirements in 

paragraph (l)(3)(iv) of this section and 

submit this plan to the Regional 

Administrator 180 days prior to the 

compliance date in paragraph (l)(5)(ii) of 

this section. The Regional Administrator 

shall approve or disapprove the plan 

within 180 days of submittal. At all 

times when one or more converters are 

blowing, the owner/operator must 

operate the capture system consistent 

with this plan. 

(iv) The written operations and 

maintenance plan must address the 

following requirements as applicable to 

the capture system or control device. 

(A) Preventative maintenance. The 

owner/operator must perform 

preventative maintenance for each 

capture system and control device 

according to written procedures 

specified in owner/operator’s operation 

and maintenance plan. The procedures 

must include a preventative 

maintenance schedule that is consistent 

with the manufacturer’s or engineer’s 

instructions for routine and long-term 

maintenance. 

(B) Capture system inspections. The 

owner/operator must perform capture 

system inspections for each capture 

system in accordance with the 

requirements of 40 CFR 63.1447(b)(2). 

(C) Copper converter department 

capture system operating limits. The 

owner/operator must establish, 

according to the requirements 40 CFR 

63.1447(b)(3)(i) through (iii), operating 

limits for the capture system that are 

representative and reliable indicators of 

the optimized performance of the 

capture system, consistent with 

paragraph (l)(3)(ii) of this section, when 

it is used to collect the process off-gas 

vented from batch copper converters 

during blowing. 

(4) Emission limitations and work 

practice standards. (i) SO2 emissions 

collected by any primary capture system 

required by paragraph (l)(3) of this 

section must be controlled by one or 

more control devices and reduced by at 

least 99.8 percent, based on a 365-day 

rolling average. 

(ii) SO2 emissions collected by any 

secondary capture system required by 

paragraph (l)(3) of this section must be 

controlled by one or more control 

devices and reduced by at least 98.5 

percent, based on a 365-day rolling 

average. 

(iii) The owner/operator must not 

cause or allow to be discharged to the 

atmosphere from any primary capture 

system required by paragraph (l)(3) of 

this section off-gas 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). 

(iv) 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). 

(v) Total NOX emissions from anode 

furnaces #1 and #2 and the batch copper 

converters shall not exceed 40 tons per 

12-continuous month period. 

(vi) Anode furnaces #1 and #2 shall 

only be charged with blister copper or 

higher purity copper. This charging 


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limitation does not extend to the use or 

addition of poling or fluxing agents 

necessary to achieve final casting 

chemistry. 

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

operator of each batch copper converter 

identified in paragraph (l)(1) of this 

section shall comply with the emissions 

limitations in paragraphs (l)(4)(ii) and 

(l)(4)(iv) of this section and other 

requirements of this section related to 

the secondary capture system no later 

than September 3, 2018. 

(ii) The owner/operator of each batch 

copper converter identified in paragraph 

(l)(1) of this section shall comply with 

the emissions limitations in paragraphs 

(l)(4)(i), (l)(4)(iii), (l)(4)(v), and (l)(4)(vi) 

of this section and other requirements of 

this section, except those requirements 

related to the secondary capture system, 

no later than September 4, 2017. 

(6) Compliance determination—(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 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 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

limit for the converters. The 365-day 

rolling SO2 emission control efficiency 

for the converters shall be calculated 

separately for the primary capture 

system and the secondary capture 

system 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 threehundred-sixty-four (364) calendar days, 

to calculate the total pounds of precontrol SO2 emissions over the most 

recent three-hundred-sixty-five (365) 

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 three-hundredsixty-four (364) calendar days, to 

calculate the total pounds of postcontrol SO2 emissions over the most 

recent three-hundred-sixty-five (365) 

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 ratio from one, 

and multiply the difference by 100 

percent to calculate the 365-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)(iii) of this section shall 

be demonstrated by the procedures in 

40 CFR 63.1451(b) and 63.1453(a)(2). 

The owner/operator shall conduct an 

initial compliance test within 180 days 

after the compliance date specified in 

paragraph (l)(5) of this section unless a 

test performed according to the 

procedures in 40 CFR 63.1450 in the 

past year shows compliance with the 

limit. 

(iv) Compliance determination for 

particulate matter. Compliance with the 

emission limit for particulate matter in 

paragraph (l)(4)(iv) of this section shall 

be demonstrated by the procedures in 

40 CFR 63.1451(a) and 63.1453(a)(1). 

The owner/operator shall conduct an 

initial compliance test within 180 days 

after the compliance date specified in 

paragraph (l)(5) of this section unless a 

test performed according to the 

procedures in 40 CFR 63.1450 in the 

past year shows compliance with the 

limit. 

(v) Compliance determination for 

NOX. Compliance with the emission 

limit for NOX in paragraph (l)(4)(v) 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) Alternatives to requirements to 

install CEMS. The requirement in 

paragraph (l)(6)(i) of this section to 

install CEMS to measure the mass of 

SO2 entering a control device or venting 

to the atmosphere through uncontrolled 

bypass stacks will be waived if the 

owner/operator complies with one of 

the options in this paragraph (l)(7). 

(i) Acid plants. The owner/operator 

may calculate the pounds of SO2

entering an acid plant during a calendar 

day by adding the pounds of SO2

emitted through the acid plant tail stack 

and 0.653 times the daily production of 

anhydrous sulfuric acid from the acid 

plant. 

(ii) Uncontrolled bypass stack. The 

owner/operator may calculate the 

pounds of SO2 venting to the 

atmosphere through an uncontrolled 

bypass stack based on test data provided 

the facility operates according to a 

startup, shutdown, and malfunction 

plan consistent with 40 CFR 63.6(e)(3) 

and the Regional Administrator has 

approved a calculation methodology for 

planned and unplanned bypass events. 

(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) through (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, 


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anhydrous sulfuric acid if the owner/

operator chooses to use the alternative 

compliance determination method in 

paragraph (l)(7)(i) of this section. 

(vii) Records of planned and 

unplanned bypass events and 

calculations used to determine 

emissions from bypass events if the 

owner/operator chooses to use the 

alternative compliance determination 

method in paragraph (l)(7)(ii) of this 

section. 

(viii) Records of daily natural gas 

consumption in each units identified in 

paragraph (l)(1) of this section and all 

calculations performed to demonstrate 

compliance with the limit in paragraph 

(l)(4)(vi) of this section. 

(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 (l)(10)(i), 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. 

(m) Source-specific federal 

implementation plan for regional haze 

at Miami Copper Smelter—(1) 

Applicability. This paragraph (m) 

applies to each owner/operator of batch 

copper converters 2, 3, 4 and 5 and the 

electric furnace at the copper smelting 

plant located in Miami, 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 

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. 

Capture system means the collection 

of components used to capture gases 

and fumes released from one or more 

emission points, and to convey the 

captured gases and fumes to one or 

more control devices. A capture system 

may include, but is not limited to, the 

following components as applicable to a 

given capture system design: duct intake 

devices, hoods, enclosures, ductwork, 

dampers, manifolds, plenums, and fans. 

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 


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52492 Federal Register / Vol. 79, No. 170 / Wednesday, September 3, 2014 / Rules and Regulations 

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. The capture system 

must include a primary capture system 

as described in 40 CFR 63.1444(d)(3) 

and a secondary capture system 

designed to maximize the collection of 

emissions not collected by the primary 

capture system. 

(ii) The operation of the batch copper 

converters, primary capture system, and 

secondary capture system shall be 

optimized to capture the maximum 

amount of process off gases vented from 

each converter at all times. 

(iii) The owner/operator shall prepare 

a written operation and maintenance 

plan according to the requirements in 

paragraph (m)(3)(iv) of this section and 

submit this plan to the Regional 

Administrator 180 days prior to the 

compliance date in paragraph (m)(5) of 

this section. The Regional Administrator 

shall approve or disapprove the plan 

within 180 days of submittal. At all 

times when one or more converters are 

blowing, the owner/operator must 

operate the capture system consistent 

with this plan. 

(iv) The written operations and 

maintenance plan must address the 

following requirements as applicable to 

the capture system or control device. 

(A) Preventative maintenance. The 

owner/operator must perform 

preventative maintenance for each 

capture system and control device 

according to written procedures 

specified in owner/operator’s operation 

and maintenance plan. The procedures 

must include a preventative 

maintenance schedule that is consistent 

with the manufacturer’s or engineer’s 

instructions for routine and long-term 

maintenance. 

(B) Capture system inspections. The 

owner/operator must perform capture 

system inspections for each capture 

system in accordance with the 

requirements of 40 CFR 63.1447(b)(2). 

(C) Copper converter department 

capture system operating limits. The 

owner/operator must establish, 

according to the requirements 40 CFR 

63.1447(b)(3)(i) through (iii), operating 

limits for the capture system that are 

representative and reliable indicators of 

the performance of capture system when 

it is used to collect the process off-gas 

vented from batch copper converters 

during blowing. 

(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 365-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 (m)(3) of 

this section off-gas 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) Total NOX emissions the electric 

furnace and the batch copper converters 

shall not exceed 40 tons per 12- 

continuous month period. 

(iv) The owner/operator shall not 

actively aerate the electric furnace. 

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

operator of each batch copper converter 

identified in paragraph (m)(1) of this 

section shall comply with the emission 

capture requirement in paragraph (m)(3) 

of this section; the emission limitation 

in paragraph (m)(4)(i) of this section; the 

compliance determination requirements 

in paragraphs (m)(6)(i) and (ii) and 

(m)(7) of this section; the capture system 

monitoring requirements in paragraph 

(m)(8) of this section; the recordkeeping 

requirements in paragraphs (m)(9)(i) 

through (viii) of this section; and the 

reporting requirements in paragraphs 

(m)(10)(i) through (iv) of this section no 

later than January 1, 2018. 

(ii) The owner/operator of each batch 

copper converter and the electric 

furnace identified in paragraph (m)(1) of 

this section shall comply with all 

requirements of this paragraph (m) 

except those listed in paragraph 

(m)(5)(i) of this section no later than 

September 2, 2016. 

(6) Compliance determination—(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 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)(i) 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 365-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 threehundred-sixty-four (364) calendar days, 

to calculate the total pounds of precontrol SO2 emissions over the most 

recent three-hundred-sixty-five (365) 

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 three-hundredsixty-four (364) calendar days, to 

calculate the total pounds of postcontrol SO2 emissions over the most 

recent three-hundred-sixty-five (365) 

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 ratio from one, 

and multiply the difference by 100 

percent to calculate the 365-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 (m)(4)(ii) of this section shall 

be demonstrated by the procedures in 

40 CFR 63.1451(b) and 63.1453(a)(2). 

The owner/operator shall conduct an 

initial compliance test within 180 days 

after the compliance date specified in 

paragraph (m)(5) of this section unless 

a test performed according to the 

procedures in 40 CFR 63.1450 in the 

past year shows compliance with the 

limit. 

(iv) Compliance determination for 

NOX. Compliance with the emission 

limit for NOX in paragraph (m)(4)(iii) 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 


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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) Alternatives to requirements to 

install CEMS. The requirement in 

paragraph (m)(6)(i) of this section to 

install CEMS to measure the mass of 

SO2 entering a control device or venting 

to the atmosphere through uncontrolled 

bypass stacks will be waived if the 

owner/operator complies with one of 

the options in this paragraph (m)(7). 

(i) Acid plants. The owner/operator 

may calculate the pounds of SO2

entering an acid plant during a calendar 

day by adding the pounds of SO2

emitted through the acid plant tail stack 

and 0.653 times the daily production of 

anhydrous sulfuric acid from the acid 

plant. 

(ii) Alkali scrubber. The owner/

operator may calculate the pounds of 

SO2 entering an alkali scrubber during 

a calendar day by using the following 

equation: 

Min,SO2 = Mout,SO2 + SF*Malk

Where: 

Min,SO2 is the calculated mass of SO2 entering 

the scrubber during a calendar day; 

Mout,SO2 is the mass of SO2 emitted through 

the scrubber stack measured by the 

CEMS for the calendar day; 

SF is a stoichiometric factor; and 

Malk is the mass of alkali added to the 

scrubber liquor during the calendar day. 

SF shall equal: 

1.14 if the alkali species is calcium oxide 

(CaO); 

1.59 if the alkali species is magnesium oxide 

(MgO); 

0.801 if the alkali species is sodium 

hydroxide (NaOH); or 

Another value if the owner/operator has 

received approval from the Regional 

Administrator in advance. 

(iii) Uncontrolled bypass stack. The 

owner/operator may calculate the 

pounds of SO2 venting to the 

atmosphere through an uncontrolled 

bypass stack based on test data provided 

the facility operates according to a 

startup, shutdown, and malfunction 

plan consistent with 40 CFR 63.6(e)(3) 

and EPA has approved a calculation 

methodology for planned and 

unplanned bypass events. 

(8) Capture system monitoring. For 

each operating limit established under 

the capture system operation and 

maintenance plan required by paragraph 

(m)(3) 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, 

anhydrous sulfuric acid if the owner/

operator chooses to use the alternative 

compliance determination method in 

paragraph (m)(7)(i) of this section. 

(vii) Records of daily alkali 

consumption in tons per day of pure, 

anhydrous alkali if the owner/operator 

chooses to use the alternative 

compliance determination method in 

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

(viii) Records of planned and 

unplanned bypass events and 

calculations used to determine 

emissions from bypass events if the 

owner/operator chooses to use the 

alternative compliance determination 

method in paragraph (m)(7)(iii) of this 

section. 

(ix) Records of daily natural gas 

consumption in each units identified in 

paragraph (m)(1) of this section and all 

calculations performed to demonstrate 

compliance with the limit in paragraph 

(m)(4)(iv) of this section. 

(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 (m)(10)(i), 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, 


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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. 

Appendix A to § 52.145—Cement Kiln 

Control Technology Demonstration 

Requirements 

I. Scope 

1. The owner/operator shall comply with 

the requirements contained in this appendix 

for implementing combustion and process 

optimization measures and in proposing and 

establishing rolling 30-kiln operating day 

limits for nitrogen oxide (NOX). 

2. The owner/operator shall take the 

following steps to establish rolling 30-kiln 

operating day limits for NOX. 

a. Design Report: At least 6 months prior 

to commencing construction of an ammonia 

injection system, the owner/operator shall 

prepare and submit to EPA for review a 

Design Report for the ammonia injection 

system. 

b. Baseline Data Collection: Prior to 

initiating operation of an ammonia injection 

system, the owner/operator shall either: (i) 

Collect new baseline emissions and 

operational data for a 180-day period; or (ii) 

submit for EPA review baseline emissions 

and operational data from a period prior to 

the date of any baseline data collection 

period. Such baseline emissions and 

operational data shall be representative of the 

full range of normal kiln operations, 

including regular operating changes in raw 

mix chemistry due to different clinker 

manufacture, changes in production levels, 

and operation of the oxygen plants. 

c. Optimization Protocol: Prior to 

commencement of the Optimization Period, 

the owner/operator shall submit for EPA 

review an Optimization Protocol which shall 

include the procedures to be used for the 

purpose of adjusting operating parameters 

and minimizing emissions. 

d. Optimization Period: Following 

completion of installation of an ammonia 

injection system, the owner/operator shall 

undertake a startup and optimization period 

for the ammonia injection system. 

e. Optimization Report: Within 60 calendar 

days following the conclusion of the 

Optimization Program, the owner/operator 

shall submit to EPA an Optimization Report 

demonstrating conformance with the 

Optimization Protocol, and establishing 

optimized operating parameters for the 

ammonia injection system as well as other 

facility processes. 

f. Demonstration Period: Upon completion 

of the optimization period specified above, 

the owner/operator shall operate the 

ammonia injection system in a manner 

consistent with the optimization period for a 

period of 270 kiln operating days (subject to 

being shortened or lengthened as provided 

for in Items 17 and 18 of this appendix) for 

the purpose of establishing a rolling 30-kiln 

operating day limit. 

g. Demonstration Report: The owner/

operator shall prepare and submit to EPA for 

review, a report following completion of the 

demonstration period for the ammonia 

injection system. 

II. Design Report 

3. Prior to commencing construction of the 

ammonia injection system, the owner/

operator shall submit to EPA for review a 

Design Report for the ammonia injection 

system. The owner/operator shall design the 

ammonia injection system to deliver the 

proposed reagent to the exhaust gases at the 

rate of at least 1.2 mols of reagent to 1.0 mols 

of NOX (1.2:1 molar ratio). The system shall 

be designed to inject Ammonia into the kiln 

exhaust gas stream. The owner/operator shall 

specify in the Design Report the reagent(s) 

selected, the locations selected for reagent 

injection, and other design parameters based 

on maximum emission reduction 

effectiveness, good engineering judgment, 

vendor standards, available data, kiln 

operability, and regulatory restrictions on 

reagent storage and use. 

4. Any permit application which may be 

required under state or federal law for the 

ammonia injection system shall be consistent 

with the Design Report. 

III. Baseline Data Collection 

5. Prior to commencement of continuous 

operation of the ammonia injection system, 

the owner/operator shall either: (a) Collect 

new baseline emissions and operational data 

for a 180-day period; or (b) submit for EPA 

review existing baseline emissions and 

operational data collected from a period of 

time prior to the initiation of a baseline 

collection period. Such baseline emissions 

and operational data shall include the data 

required by Item 8 below for periods of time 

representing the full range of normal kiln 

operations including changes in raw mix 

chemistry due to differing clinker 

manufacture, changes in production levels 

and operation of the oxygen plants. Within 

45 Days following the completion of the 

baseline data collection period, the owner/

operator shall submit to EPA the baseline 

data collected during the Baseline Data 

Collection Period. 

IV. Optimization Period 

6. The owner/operator shall install, 

operate, and collect NOX emissions data from 

a CEMS in accordance with § 52.145(k)(7)(i), 

reagent injection data in accordance with 

§ 52.145(k)(7)(ii)(D), and other operational 

data prior to commencement of the 

Optimization Period. 

7. During the Baseline Data Collection 

Period (if the owner/operator elects to collect 

new data) and the Optimization Period, the 

owner/operator shall operate the Kiln in a 

manner necessary to produce a quality 

cement clinker product. The owner/operator 

shall not be expected to operate the Kiln 

within normal operating parameters during 

periods of Kiln Malfunction, Startup and 

Shutdown. The owner/operator shall not 

intentionally adjust kiln operating 

parameters to increase the rate of emission 

(expressed as lb/ton of clinker produced) for 

NOX. Increases or variability in the Kiln feed 

sulfur content, fuel and other raw materials 

composition including imported raw 

materials, resulting from the inherent 

variability within the onsite quarries and 

imported materials shall not constitute an 

intentional increase in emission rate. 

8. The data to be collected during the 

Baseline Data Collection Period (if the 

owner/operator elects to collect baseline 

data) and the Optimization Period will 

include the following information either 

derived from available direct monitoring or 

as estimated from monitored or measured 

data: 

a. Kiln flue gas temperature at the inlet to 

the fabric filter or at the Kiln stack (daily 

average); 

b. Kiln production rate in tons of clinker 

(daily total) by type; 

c. Raw material feed rate in tons (daily 

total) by type; 

d. Type and percentage of each raw 

material used and the total feed rate (daily); 

e. NOX and CO concentrations (dry basis) 

and mass rates for the Kiln (daily average for 

concentrations and daily totals for mass 

rates) as measured at the Kiln stack gas 

analyzer location; 

f. Flue gas volumetric flow rate (daily 

average in dry acfm); 

g. Sulfate in feed (calculated to a daily 

average percentage); 

h. Feed burnability (C3S) (at least daily). In 

the event that more than one type of clinker 

is produced, the feed burnability for each 

clinker type will be included; 

i. Temperatures in or near the burning zone 

(by infrared or optical pyrometer); 

j. Kiln system fuel feed rate and type of 

fuel by weight or heat input rate (calculated 

to a daily average); 

k. Fuel distribution, an estimate of how 

much is injected at each location (daily 

average); 

l. Kiln amps (daily average); 

m. Kiln system draft fan settings and 

primary air blower flow rates; 

n. Documentation of any Startup, 

Shutdown, or Malfunction events; 

o. An explanation of any gaps in the data 

or missing data; and 


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p. Amount of oxygen generated and 

introduced into the Kiln (lb/day). 

9. The owner/operator shall submit the 

data to EPA in an electronic format and shall 

explain the reasons for any data not collected 

for each of the parameters. The owner/

operator shall report all data in a format 

consistent with and able to be manipulated 

by Microsoft Excel. 

10. Prior to commencement of the 

Optimization Period, the owner/operator 

shall submit to EPA for review a protocol 

(‘‘Optimization Protocol’’) for optimizing the 

ammonia injection system, including 

optimization of the operational parameters 

resulting in the minimization of emissions of 

NOX to the greatest extent practicable 

without violating any limits. The Protocol 

shall describe procedures to be used during 

the Optimization Period to optimize the 

facility processes to minimize emissions from 

the kiln and adjust ammonia injection system 

operating parameters, and shall include the 

following: 

a. The following measures to optimize the 

facility’s processes to reduce NOx emissions 

in conjunction with the ammonia injection 

system: 

i. Adjustment of the balance between fuel 

supplied to the existing riser duct burner and 

the existing calciner burners to improve 

overall combustion within the calciner while 

maintaining product quality; 

ii. Adjustments to the calciner combustion 

to ensure complete fuel burning, which will 

help to both reduce CO and improve NOx 

levels by, at a minimum: 

1. Adjusting fuel fineness to improve the 

degree of combustion completed in the 

calciner; and 

2. Adjusting the proportions of primary, 

secondary and tertiary air supplied to the 

kiln system while maintaining product 

quality; and 

iii. Adjustments to the raw mix chemical 

and physical properties using onsite raw 

materials to improve kiln stability and 

maintain product quality, including but not 

limited to, fineness of the raw mix. As part 

of this optimization measure, the owner/

operator shall take additional measurements 

using existing monitoring equipment at 

relevant process locations to evaluate the 

impact of raw mix refinements. 

b. The range of reagent injection rates (as 

a molar ratio of the average pollutant 

concentration); 

c. Sampling and testing programs that will 

be undertaken during the initial reagent 

injection rate period; 

d. A plan to increase the reagent injection 

rate to identify the injection rates with the 

maximum emission reduction effectiveness 

and associated sampling and testing 

programs for each increase in the reagent 

rate. The owner/operator shall test, at a 

minimum, for the ammonia injection system 

at molar ratios of 0.75, 1.0, and 1.20. If data 

collected at the highest molar ratio indicates 

decreasing lb/ton emissions, the owner/

operator shall continue to test the ammonia 

injection system by increasing the molar ratio 

by increments of 0.10 until either the lb/ton 

emission data indicates no significant 

decrease from the previous increment, or 

adverse effects are observed (e.g., ammonia 

slip emissions above 10 ppm, presence of a 

secondary particulate plume, impaired 

product, impaired kiln operations). 

e. The factors that will determine the 

optimum reagent injection rates and 

pollutant emission reductions (including 

maintenance of Kiln, productivity, and 

product quality); and 

f. Evaluation of any observed synergistic 

effects on Kiln emissions, Kiln operation, 

reagent slippage, or product quality from the 

ammonia injection system. 

11. As part of the Optimization Protocol, 

the owner/operator shall submit to EPA a 

schedule for optimizing each the ammonia 

injection system parameters identified in 

Item 10 of this appendix. The schedule shall 

indicate the total duration of the 

Optimization period, and must optimize each 

identified parameter for the following 

minimum amounts of time: 

Parameter 

Minimum 

optimization 

period 

(operating 

days) 

Fuel usage between riser 

duct burner and calciner 

burners .............................. 15 

Calciner combustion ............. 45 

Raw mix chemical and physical properties stabilization 45 

Setup of SNCR, initial operation of reagent injection, 

and calibration ................... 60 

12. Within 60 days following the 

termination of the Optimization Period(s), 

the owner/operator shall submit to EPA for 

review an Optimization Report 

demonstrating conformance with the 

Optimization Protocol for the ammonia 

injection system and establishing the 

optimized operating parameters for the 

facility processes and the ammonia injection 

system determined under the Optimization 

Protocol, including optimized injection rates 

for all reagents. The owner/operator may take 

into account energy, environmental, and 

economic impacts and other costs in 

proposing the optimized state of the 

ammonia injection system, including the 

injection rates of reagents, and the operating 

parameters for the facility processes. The 

owner/operator may also include in the 

Optimization Report a discussion of any 

problems encountered during the 

Optimization Period, and how that problem 

may impact the potential emission 

reductions (e.g. the quantity of reagent slip at 

varying injection rates and/or the possible 

observance of a detached plume above the 

Stack). 

13. Optimization Targets: Except as 

otherwise provided in this Item and in Item 

14 of this appendix, the ammonia injection 

system shall be deemed to be optimized if the 

Optimization Report demonstrates that the 

ammonia injection system during periods of 

normal operation has achieved emission 

reductions consistent with its maximum 

design stoichiometric rate identified in the 

Design Report. 

14. Notwithstanding the provisions of Item 

13 of this appendix, the ammonia injection 

system may be deemed to be optimized at a 

lower rate of emission reductions than that 

identified in Item 13 of this appendix if the 

Optimization Report demonstrates that, 

during periods of normal operation, a lower 

rate of emission reductions cannot be 

sustained after all parameters and injection 

rates are optimized during the Optimization 

Period without creating a meaningful risk of 

impairing product quality, impairing Kiln 

system reliability, impairing compliance with 

a maximum ammonia slip emissions limit of 

10 ppm or other permitted levels, or forming 

a detached plume. 

15. During the Optimization Period, the 

owner/operator, to the extent practicable and 

applicable, shall operate the ammonia 

injection system in a manner consistent with 

good air pollution control practice consistent 

with 40 CFR 60.11(d). The owner/operator 

will adjust its optimization of the ammonia 

injection system as may be necessary to 

avoid, mitigate or abate an identifiable noncompliance with an emission limitation or 

standard for pollutants other than NOx. In 

the event the owner/operator determines, 

prior to the expiration of the Optimization 

Period, that its ability to optimize the 

ammonia injection system will be affected by 

potential impairments to product quality, 

kiln system reliability or increased emissions 

of other pollutants, then the owner/operator 

shall promptly advise EPA of this 

determination, and include these 

considerations as part of its recommendation 

in its Optimization Report. 

V. Demonstration Period 

16. The Demonstration Period shall 

commence within 7 days after the owner/

operator’s receipt of final comments from 

EPA on the Optimization Report. During the 

Demonstration Period, the owner/operator 

shall operate the ammonia injection system 

for a period of 270 Operating Days consistent 

with the optimized operations of the Facility 

and the ammonia injection system as 

contained in the Optimization Report. This 

270 Operating Day Demonstration Period 

may be shortened or lengthened as provided 

for in Items 17 and 18 of this appendix. 

17. If Kiln Operation is disrupted by 

excessive unplanned outages, or excessive 

Startups and Shutdowns during the 

Demonstration Period, or if the Kiln 

temporarily ceases operation for business or 

technical reasons, the owner/operator may 

advise EPA that it is necessary to temporarily 

extend the Demonstration Period. Data 

gathered during periods of disruption may 

not be used to determine an emission 

limitation. 

18. If evidence arises during the 

Demonstration Period that product quality, 

kiln system reliability, or emission 

compliance with an emission limitation or 

standard is impaired by reason of longer term 

operation of the ammonia injection system in 

a manner consistent with the parameters 

identified in the Optimization Report, then 

the owner/operator may, upon notice to EPA, 

temporarily modify the manner of operation 

of the facility process or the ammonia 

injection system to mitigate the effects and, 

if necessary, notify EPA that the owner/

operator will suspend or extend the 


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52496 Federal Register / Vol. 79, No. 170 / Wednesday, September 3, 2014 / Rules and Regulations 

Demonstration Period for further technical 

evaluation of the effects of a process 

optimization or permanently modify the 

manner of operation of the ammonia 

injection system to mitigate the effects. 

19. During the Demonstration Period, the 

owner/operator shall collect the same data as 

required in Item 8 of this appendix. The 

Demonstration Report shall include the data 

collected as required in this Item. 

20. Within 60 Days following completion 

of the Demonstration Period for the ammonia 

injection system, the owner/operator shall 

submit a Demonstration Report to EPA, based 

upon and including all of the data collected 

during the Demonstration Period including 

data from Startup, Shutdown and 

Malfunction events, that identifies a 

proposed 30-kiln operating day emission 

limit for NOX. The 30-kiln operating day 

emission limit for NOX shall be based upon 

an analysis of CEMS data and clinker 

production data collected during the 

Demonstration Period, while the process and 

ammonia injection system parameters were 

optimized in determining the proposed final 

Emission Limit(s) achievable for the Facility. 

Total pounds of an affected pollutant emitted 

during an individual Operating Day will be 

calculated from collected CEMS data for that 

Day. Hours or Days when there is no Kiln 

Operation may be excluded from the 

analyses. However, the owner/operator shall 

provide an explanation in the Demonstration 

Report(s) for any data excluded from the 

analyses. In any event, the owner/operator 

shall include all data required to be collected 

during the Demonstration Period in the Final 

Demonstration Report(s). 

21. The owner/operator shall propose a 30- 

kiln operating day emission limit for NOx in 

the Demonstration Report(s) as provided in 

Item 20 of this appendix. This 30-kiln 

operating day emission limit shall be 

calculated in accordance with the following 

formula: 

X = m + 1.65s 

Where: 

X = 30-Day Rolling Average Emission Limit 

(lb/Ton of clinker); 

m = arithmetic mean of all of the 30-Day 

rolling averages; 

s = standard deviation of all of the 30-Day 

rolling averages, as calculated in the 

following manner: 

Where: 

N = The total number of rolling 30-kiln 

operating day emission rates; 

xi = Each rolling 30-kiln operating day 

emission rate; 

x ̄ = The mean value of all of the rolling 30- 

kiln operating day emission rates. 

22. Supporting data required to be 

submitted under this appendix may contain 

information relative to kiln operation and 

production that the owner/operator may 

consider to be proprietary. In such a 

situation, the owner/operator may submit the 

information to EPA as CBI, subject to the 

provisions of 40 CFR part 2. 

Appendix B to § 52.145—Lime Kiln 

Control Technology Demonstration 

Requirements 

I. Scope 

1. The owner/operator shall comply with 

the requirements contained in this appendix 

for implementing combustion and process 

optimization measures and in proposing and 

establishing rolling 12-month limits for 

nitrogen oxide (NOX). 

2. The owner/operator shall take the 

following steps to establish rolling 12-month 

limits for NOx. 

a. Design Report: At least 6 months prior 

to commencing construction of an ammonia 

injection system, the owner/operator shall 

prepare and submit to EPA for review a 

Design Report for the ammonia injection 

system; 

b. Baseline Data Collection: Prior to 

initiating operation of an ammonia injection 

system, the owner/operator shall either: (i) 

Collect new baseline emissions and 

operational data for a 180-day period; or (ii) 

submit for EPA review baseline emissions 

and operational data from a period prior to 

the date of any baseline data collection 

period. Such baseline emissions and 

operational data shall be representative of the 

full range of normal kiln operations. 

c. Optimization Protocol: Prior to 

commencement of the Optimization Period, 

the owner/operator shall submit for EPA 

review an Optimization Protocol which shall 

include the procedures to be used for the 

purpose of adjusting operating parameters 

and minimizing emissions. 

d. Optimization Period: Following 

completion of installation of an ammonia 

injection system, the owner/operator shall 

undertake a startup and optimization period 

for the ammonia injection system; 

e. Optimization Report: Within 60 calendar 

days following the conclusion of the 

Optimization Program, the owner/operator 

shall submit to EPA an Optimization Report 

demonstrating conformance with the 

Optimization Protocol, and establishing 

optimized operating parameters for the 

ammonia injection system as well as other 

facility processes. 

f. Demonstration Period: Upon completion 

of the optimization period specified above, 

the owner/operator shall operate the 

ammonia injection system in a manner 

consistent with the optimization period for a 

period of 360 kiln operating days (subject to 

being shortened or lengthened as provided 

for in Items 17 and 18 of this appendix) for 

the purpose of establishing a rolling 30-kiln 

operating day limit; and 

g. Demonstration Report: The owner/

operator shall prepare and submit to EPA for 

review, a report following completion of the 

demonstration period for the ammonia 

injection system. 

II. Design Report 

3. Prior to commencing construction of the 

ammonia injection system, the owner/

operator shall submit to EPA for review a 

Design Report for the ammonia injection 

system. The owner/operator shall design the 

ammonia injection system to deliver the 

proposed reagent to the exhaust gases at the 

rate of at least 1.2 mols of reagent to 1.0 mols 

of NOx (1.2:1 molar ratio). The system shall 

be designed to inject Ammonia into the kiln 

exhaust gas stream. The owner/operator shall 

specify in the Design Report the reagent(s) 

selected, the locations selected for reagent 

injection, and other design parameters based 

on maximum emission reduction 

effectiveness, good engineering judgment, 

vendor standards, available data, kiln 

operability, and regulatory restrictions on 

reagent storage and use. 

4. Any permit application which may be 

required under state or federal law for the 

ammonia injection system shall be consistent 

with the Design Report. 

III. Baseline Data Collection 

5. Prior to commencement of continuous 

operation of the ammonia injection system, 

the owner/operator shall either: (a) Collect 

new baseline emissions and operational data 

for a 180-day period; or (b) submit for EPA 

review existing baseline emissions and 

operational data collected from a period of 

time prior to the initiation of a baseline 

collection period. Such baseline emissions 

and operational data shall include the data 

required by Item 8 of this appendix for 

periods of time representing the full range of 

normal kiln operations. Within 45 Days 

following the completion of the baseline data 

collection period, the owner/operator shall 

submit to EPA the baseline data collected 

during the Baseline Data Collection Period. 

IV. Optimization Period 

6. The owner/operator shall install, 

operate, and collect NOX emissions data from 

a CEMS in accordance with § 52.145(k)(7)(i), 

reagent injection data in accordance with 

§ 52.145(k)(7)(ii)(D), and other operational 

data prior to commencement of the 

Optimization Period. 

7. During the Baseline Data Collection 

Period (if the owner/operator elects to collect 

new data) and the Optimization Period, the 

owner/operator shall operate the Kiln in a 

manner necessary to produce a quality lime 

product. The owner/operator shall not be 

expected to operate the Kiln within normal 

operating parameters during periods of Kiln 

Malfunction, Startup and Shutdown. The 

owner/operator shall not intentionally adjust 

kiln operating parameters to increase the rate 

of emission (expressed as lb/ton of lime 

product produced) for NOX. 

8. The data to be collected during the 

Baseline Data Collection Period (if the 

owner/operator elects to collect baseline 

data) and the Optimization Period will 

include the following information either 

derived from available direct monitoring or 

as estimated from monitored or measured 

data: 

a. Kiln flue gas temperature at the inlet to 

the fabric filter or at the Kiln stack (daily 

average); 

b. Kiln production rate in tons of lime 

product (daily total) by type; 

c. NOX and CO concentrations (dry basis) 

and mass rates for the Kiln (daily average for 

concentrations and daily totals for mass 

rates) as measured at the Kiln stack gas 

analyzer location; 

d. Flue gas volumetric flow rate (daily 

average in dry acfm); 


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e. Sulfate in feed (calculated to a daily 

average percentage); 

f. Feed burnability (C3S) (at least daily). In 

the event that more than one type of lime 

product is produced, the feed burnability for 

each type of lime product will be included; 

g. Temperatures in or near the burning 

zone (by infrared or optical pyrometer); 

h. Kiln system fuel feed rate and type of 

fuel by weight or heat input rate (calculated 

to a daily average); 

i. Fuel distribution, an estimate of how 

much is injected at each location (daily 

average); 

j. Kiln amps (daily average); 

k. Kiln system draft fan settings and 

primary air blower flow rates; 

l. Documentation of any Startup, 

Shutdown, or Malfunction events; 

m. An explanation of any gaps in the data 

or missing data; and 

n. Amount of oxygen generated and 

introduced into the Kiln (lb/day). 

9. The owner/operator shall submit the 

data to EPA in an electronic format and shall 

explain the reasons for any data not collected 

for each of the parameters. The owner/

operator shall report all data in a format 

consistent with and able to be manipulated 

by Microsoft Excel. 

10. Prior to commencement of the 

Optimization Period, the owner/operator 

shall submit to EPA for review a protocol 

(‘‘Optimization Protocol’’) for optimizing the 

ammonia injection system, including 

optimization of the operational parameters 

resulting in the minimization of emissions of 

NOX to the greatest extent practicable 

without violating any limits. The Protocol 

shall describe procedures to be used during 

the Optimization Period to optimize the 

facility processes to minimize emissions from 

the kiln and adjust ammonia injection system 

operating parameters, and shall include the 

following: 

a. The range of reagent injection rates (as 

a molar ratio of the average pollutant 

concentration); 

b. Sampling and testing programs that will 

be undertaken during the initial reagent 

injection rate period; 

c. A plan to increase the reagent injection 

rate to identify the injection rates with the 

maximum emission reduction effectiveness 

and associated sampling and testing 

programs for each increase in the reagent 

rate. The owner/operator shall test, at a 

minimum, for the ammonia injection system 

at three molar ratios of 0.75, 1.0, and 1.20; 

d. The factors that will determine the 

optimum reagent injection rates and 

pollutant emission reductions (including 

maintenance of Kiln, productivity, and 

product quality); and 

e. Evaluation of any observed synergistic 

effects on Kiln emissions, Kiln operation, 

reagent slippage, or product quality from the 

ammonia injection system. 

f. Any additional facility processes that the 

owner/operator determines may reduce NOX

emissions in conjunction with the ammonia 

injection system. 

11. As part of the Optimization Protocol, 

the owner/operator shall submit to EPA a 

schedule for optimizing each of the ammonia 

injection system parameters identified in 

Item 10 of this appendix. The schedule shall 

indicate the total duration of the 

Optimization period, and must optimize each 

identified parameter for the following 

minimum amounts of time: 

Parameter 

Minimum 

optimization 

period 

(operating 

days) 

Setup of SNCR, initial operation of reagent injection, 

and calibration ................... 60 

12. Within 60 Days following the 

termination of the Optimization Period(s), 

the owner/operator shall submit to EPA for 

review an Optimization Report 

demonstrating conformance with the 

Optimization Protocol for the ammonia 

injection system and establishing the 

optimized operating parameters for the 

facility processes and the ammonia injection 

system determined under the Optimization 

Protocol, including optimized injection rates 

for all reagents. The owner/operator may take 

into account energy, environmental, and 

economic impacts and other costs in 

proposing the optimized state of the 

ammonia injection system, including the 

injection rates of reagents, and the operating 

parameters for the facility processes. The 

owner/operator may also include in the 

Optimization Report a discussion of any 

problems encountered during the 

Optimization Period, and how that problem 

may impact the potential emission 

reductions (e.g. the quantity of reagent slip at 

varying injection rates and/or the possible 

observance of a detached plume above the 

Stack). 

13. Optimization Targets: Except as 

otherwise provided in this Item and in Item 

14 of this appendix, the ammonia injection 

system shall be deemed to be optimized if the 

Optimization Report demonstrates that the 

ammonia injection system during periods of 

normal operation has achieved emission 

reductions consistent with its maximum 

design stoichiometric rate identified in the 

Design Report approved pursuant to Item 3 

of this appendix. 

14. Notwithstanding the provisions of Item 

13 of this appendix, the ammonia injection 

system may be deemed to be optimized at a 

lower rate of emission reductions than that 

identified in Item 13 of this appendix if the 

Optimization Report demonstrates that, 

during periods of normal operation, a lower 

rate of emission reductions cannot be 

sustained after all parameters and injection 

rates are optimized during the Optimization 

Period without creating a meaningful risk of 

impairing product quality, impairing Kiln 

system reliability, impairing compliance with 

a maximum ammonia slip emissions limit of 

10 ppm or other permitted levels, or forming 

a detached plume. 

15. During the Optimization Period, the 

owner/operator, to the extent practicable and 

applicable, shall operate the ammonia 

injection system in a manner consistent with 

good air pollution control practice consistent 

with 40 CFR 60.11(d). The owner/operator 

will adjust its optimization of the ammonia 

injection system as may be necessary to 

avoid, mitigate or abate an identifiable noncompliance with an emission limitation or 

standard for pollutants other than NOX. In 

the event the owner/operator determines, 

prior to the expiration of the Optimization 

Period, that its ability to optimize the 

ammonia injection system will be affected by 

potential impairments to product quality, 

kiln system reliability or increased emissions 

of other pollutants, then the owner/operator 

shall promptly advise EPA of this 

determination, and include these 

considerations as part of its recommendation 

in its Optimization Report. 

V. Demonstration Period 

16. The Demonstration Period shall 

commence within 7 days after the owner/

operator’s receipt of the final comments from 

EPA on the Optimization Report. During the 

Demonstration Period, the owner/operator 

shall operate the ammonia injection system 

for a period of 360 Operating Days consistent 

with the optimized operations of the Facility 

and the ammonia injection system as 

contained in the Optimization Report. This 

360 Operating Day Demonstration Period 

may be shortened or lengthened as provided 

for in Items 17 and 18 of this appendix. 

17. If Kiln Operation is disrupted by 

excessive unplanned outages, or excessive 

Startups and Shutdowns during the 

Demonstration Period, or if the Kiln 

temporarily ceases operation for business or 

technical reasons, the owner/operator may 

advise EPA that it is necessary to temporarily 

extend the Demonstration Period. Data 

gathered during periods of disruption may 

not be used to determine an emission 

limitation. 

18. If evidence arises during the 

Demonstration Period that product quality, 

kiln system reliability, or emission 

compliance with an emission limitation or 

standard is impaired by reason of longer term 

operation of the ammonia injection system in 

a manner consistent with the parameters 

identified in the Optimization Report, then 

the owner/operator may, upon notice to EPA, 

temporarily modify the manner of operation 

of the facility process or the ammonia 

injection system to mitigate the effects and, 

if necessary, notify EPA that the owner/

operator will suspend or extend the 

Demonstration Period for further technical 

evaluation of the effects of a process 

optimization or permanently modify the 

manner of operation of the ammonia 

injection system to mitigate the effects. 

19. During the Demonstration Period, the 

owner/operator shall collect the same data as 

required in Item 8 of this appendix. The 

Demonstration Report shall include the data 

collected as required in this Item. 

20. Within 60 Days following completion 

of the Demonstration Period for the ammonia 

injection system, the owner/operator shall 

submit a Demonstration Report to EPA, based 

upon and including all of the data collected 

during the Demonstration Period including 

data from Startup, Shutdown and 

Malfunction events, that identifies a 

proposed rolling 12-month emission limit for 

NOX. The rolling 12-month emission limit for 

NOX shall be based upon an analysis of 


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52498 Federal Register / Vol. 79, No. 170 / Wednesday, September 3, 2014 / Rules and Regulations 

CEMS data and lime production data 

collected during the Demonstration Period, 

while the process and ammonia injection 

system parameters were optimized in 

determining the proposed Emission Limit(s) 

achievable for the Facility. However, the 

owner/operator shall provide an explanation 

in the Demonstration Report(s) for any data 

excluded from the analyses. In any event, the 

owner/operator shall include all data 

required to be collected during the 

Demonstration Period in the Final 

Demonstration Report(s). 

21. The owner/operator shall propose a 

rolling 12-month emission limit for NOX in 

the Demonstration Report(s) as provided in 

Item 20 of this appendix. This rolling 12- 

month limit shall be calculated in accordance 

with the following formula: 

X = m + 1.65s 

Where: 

X = Rolling 12-month Average Emission 

Limit (lb/Ton of lime product); 

m = arithmetic mean of all of the Rolling 12- 

month averages; 

s = standard deviation of all of the rolling 12- 

month averages, as calculated in the 

following manner: 

Where: 

N = The total number of rolling 12-month 

emission rates; 

xi = Each rolling 12-month emission rate; 

x ̄ = The mean value of all of the rolling 12- 

month emission rates. 

22. Supporting data required to be 

submitted under this Appendix may contain 

information relative to kiln operation and 

production that the owner/operator may 

consider to be proprietary. In such a 

situation, the owner/operator may submit the 

information to EPA as CBI, subject to the 

provisions of 40 CFR part 2. 

[FR Doc. 2014–15895 Filed 9–2–14; 8:45 am] 

BILLING CODE 6560–50–P 


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